T-REX OIL, INC. - Annual Report: 2007 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended March 31, 2007

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

For the transition period from __________ to __________

Commission file number: 000-51425

RANCHER ENERGY CORP.

(Exact name of registrant as specified in its charter)

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

999-18th Street, Suite 1740

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

(303) 629-1125

(Telephone number, including area code)

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

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

Title of each class
Common Stock, par value $0.00001 per share

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

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

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

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

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

Large accelerated filer £

Accelerated filer R

Non-accelerated filer £

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

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

TABLE OF CONTENTS

PAGE NO.

PART I		1

Item 1.	Business.	2
Item 1A.	Risk Factors.	8
Item 1B.	Unresolved Staff Comments.	15
Item 2.	Properties.	16
Item 3.	Legal Proceedings.	19
Item 4.	Submission of Matters to a Vote of Security Holders.	19

PART II		20

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	20
Item 6.	Selected Financial Data.	25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	42
Item 8.	Financial Statements and Supplementary Data.	43
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	43
Item 9A.	Controls and Procedures.	43
Item 9B.	Other Information.	52

PART III		53

Item 10.	Directors, Executive Officers and Corporate Governance.	53
Item 11.	Executive Compensation.	53
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	53
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	53
Item 14.	Principal Accountant Fees and Services.	53

PART IV		54

Item 15.	Exhibits, Financial Statement Schedules.	54

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

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

PART I

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

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

•

business strategy;

•

CO₂ availability, deliverability, and tertiary production targets;

•

inventories, projects, and programs;

•

other anticipated capital expenditures and budgets;

•

future cash flows and borrowings;

•

the availability and terms of financing;

•

oil reserves;

•

reservoir response to CO₂ injection;

•

ability to obtain permits and governmental approvals;

•

technology;

•

financial strategy;

•

realized oil prices;

•

production;

•

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

•

availability and costs of drilling rigs and field services;

•

future operating results; 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.

ITEM 1. BUSINESS.

The Company

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

We operate three fields in the Powder River Basin, Wyoming, which is located in the Rocky Mountain region of the United States. The fields, acquired in December 2006 and January 2007, are the South Glenrock B Field, the Big Muddy Field, and the Cole Creek South Field. All three fields currently produce some oil and are CO₂ tertiary recovery candidates. We plan to substantially increase production in our fields by using CO₂injection and other enhanced oil recovery (EOR) techniques. To fund the acquisition of the three fields and our operating expenses, from June 2006 through January 2007, we sold $89,300,000 of our securities in two private placements. In December 2006, we also entered into an agreement with the Anadarko Petroleum Corporation to supply us with CO₂needed to conduct CO₂ tertiary recovery operations in our three fields. We are in the process of planning for a pipeline to transport the CO₂ to our fields and for infrastructure improvements to implement EOR techniques.

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

Incorporation and Organization

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

Business Strategy

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

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

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

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

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

Our Recent Acquisitions

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

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

Our Development Program

We have completed field studies and economic analyses of the Dakota, Lower Muddy, and Upper Muddy horizons in the South Glenrock B Field and the Wall Creek horizon of the Big Muddy Field, and have entered into a CO₂ supply agreement. We are also seeking arrangements for other CO₂supplies. We are planning to proceed with the tertiary development of the South Glenrock B Field, subject to obtaining additional financing. Our planned order of development will be the South Glenrock B Field, the Big Muddy Field, and then the Cole Creek South Field.

Oil & Gas Operations

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

CO₂Tertiary Recovery

Our business strategy is to employ modern EOR technology to recover hydrocarbons that remain behind in mature reservoirs. The closing of our private placement of equity financing, the acquisition of the South Glenrock B Field, the Big Muddy Field, and the Cole Creek South Field located in the Powder River Basin, and entry into the CO₂supply contract with Anadarko were important steps in executing our business strategy. Important next steps are to secure debt financing in a sufficient amount for our development program, complete the required environmental and regulatory permitting, build a spur pipeline to transport 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, 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.

We intend to conduct a 3-D seismic survey on the South Glenrock B and Big Muddy Fields in conjunction with the CO₂ development program. The seismic information will be used to further define reservoir configuration and trapping, thus filling in gaps in the available information for our fields.

Anadarko CO₂ Supply 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 CO₂delivery, 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%.

In addition to the CO₂ supply arrangement with Anadarko, we plan to pursue the acquisition of additional daily volumes of CO₂. Additional CO₂ supplies would be used to increase CO₂ injection rates, with the expectation that increased oil production rates would result.

CO₂ Pipeline Construction

Under the Purchase Contract with Anadarko, we have the responsibility for providing pipeline transportation of purchased CO₂ from a connection point on the Anadarko trunkline to our project area. We are evaluating alternatives to construct and operate the pipeline. We have engaged an engineering firm to study potential routes and configurations. Depending on the final route selection, the pipeline may range from 50 to 132 miles in length, and cost estimates range from $50 to $110 million.

We are exploring two options to finance construction of the pipeline. One option is to have a third party build, own, and operate the CO₂ pipeline. This operator would be reimbursed for operating expenses and capital investment by way of a transportation tariff on the CO₂ delivered, with the tariff varying as a function of throughput. The second option is for us to construct, own, and operate the pipeline. We would require additional capital for this option. We are currently planning to borrow funds to implement development of our fields, and we may include the funds necessary for construction of the CO₂ pipeline in a debt financing.

Anadarko currently is receiving CO₂ for its Salt Creek Field in Wyoming from the ExxonMobil Corporation 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.

Financing Plans

We are planning to obtain funding for the surface facility construction, 3-D seismic, well drilling and conversion, other development costs, the cost of purchasing and transporting CO₂, and potentially the CO₂ pipeline. We expect this financing will be primarily fixed term debt with a high interest rate secured by our properties. We also expect to arrange for a senior revolving debt facility supported by our proved oil reserves. Our goal is to close both debt financings in the third calendar quarter of 2007. Completion of these debt offerings will be subject to market conditions and Company-specific factors.

Federal and State Regulations

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

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

Regulation of Oil Exploration and Production

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

Federal Regulation of Sales Prices and Transportation

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

Federal or State Leases

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

Regulation of Proposed CO₂ Pipeline

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

Environmental Regulations

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

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

Available Information

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

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.

EOR.	Enhanced oil recovery.

Field.	An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

MMcf.	One million cubic feet of natural gas.

Metalex.	Metalex Resources, Inc.

Miscible.	Capable of being mixed in all proportions. Water and oil are not miscible. Alcohol and water are miscible. CO₂ and oil can be miscible under the proper conditions.

Proved reserves.	The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Purchase Contract.	The Anadarko Product Sale and Purchase Contract.

Tertiary recovery.	The third process used for oil recovery. Usually primary recovery is the result of depletion drive, secondary recovery is from a waterflood, and tertiary recovery is an enhanced oil recovery process such as CO₂ flooding.

Working interest.	An interest in an oil & gas lease that gives the owner of the interest the right to drill and produce oil & gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties.

ITEM 1A. RISK FACTORS.

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

Risks Related to our Industry, Business, and Strategy

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

Our plans to develop the properties are dependent on the construction of a 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.

Our production is dependent upon sufficient amounts of CO₂ and will decline if our access to sufficient amounts of CO₂ is limited.

Our long-term growth strategy is focused on our CO₂tertiary 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, and quality of the supplied CO₂, problems with our facilities, including compression equipment, or catastrophic pipeline failure. Our agreement with our current sole supplier of CO₂provides that before it delivers CO₂ to us, it may satisfy its own CO₂ needs. If we are not successful in obtaining the required amount of CO₂ to achieve crude oil production or the crude oil production in the future were to decline as a result of a decrease in delivered CO₂ supply, it could have a material adverse effect on our financial condition and results of operations and cash flows.

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

Our current cash position will not be sufficient to fund construction of the CO₂ pipeline, or the development of our three properties. We will require substantial additional funding. Our plan is to obtain debt financing. The terms of any debt financing may restrict our future business activities and expenditures. We do not know if additional financing will be available at all when needed or on acceptable terms. Insufficient funds will prevent us from implementing our tertiary recovery business strategy.

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

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

·	our proved reserves;

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

·	the prices at which the oil is sold; and

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

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

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

We were organized in 2004 to explore a gold prospect and in 2006 changed our business focus to oil & gas development using 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 have incurred losses from operations in the past and expect to do so in the future.

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

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

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

We may be unable to develop additional reserves.

Our ability to develop future revenues will depend on whether we can successfully implement our planned CO₂ injection program. We have no experience using CO₂ technology, the properties we plan to acquire 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, John Dobitz, our Senior Vice President, Engineering, Andrew Casazza, our Chief Operating Officer, and Daniel P. Foley, our Chief Financial Officer. There is no guarantee that any of the members of our management team will remain employed by us. While we have employment agreements with them, their continued service cannot be assured. The loss of our senior executives could harm our business.

Oil operations are inherently risky.

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

We are subject to extensive government regulations.

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

·	the prevention of waste;

·	the discharge of materials into the environment;

·	the conservation of oil;

·	pollution;

·	permits for drilling operations;

·	underground gas injection permits;

·	drilling bonds; and

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

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

Government regulation and environmental risks could increase our costs.

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

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

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

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

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

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

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

Oil prices may be impacted adversely by new taxes.

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

Shortages of equipment, supplies, and personnel, and delays in construction of the CO₂ pipeline, construction of surface facilities, and delivery of CO₂ could delay or otherwise adversely affect our cost of operations or our ability to operate according to our business plans.

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

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

Risks Related to our Common Stock

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

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

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

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

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

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

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

·	Actual or anticipated quarterly variations in our operating results;

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

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

·	Conditions generally affecting the oil & gas industry;

·	The success of our operating strategy; and

·	The operating and stock performance of other comparable companies.

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

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

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

·	discuss our future expectations;

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

·	state other “forward-looking” information.

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

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

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

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

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS.

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

ITEM 2. PROPERTIES.

Field Summaries

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

We plan to make approximately $75 million of capital expenditures in the fiscal year ending March 31, 2008 on our three fields, building facilities, shooting 3-D seismic, drilling wells, expanding production, and preparing the area for CO₂ delivery, which we expect will add both additional oil reserves and production for future operations. If we elect to own and operate the CO₂ pipeline, we will spend additional capital in fiscal years 2008 and 2009 for that purpose.

South Glenrock B Field

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

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

The South Glenrock B Field is an active waterflood that currently produces approximately 200 BOPD of sweet 35 degree API crude oil. There are 20 active producing wells. This waterflood unit was developed with a fairly regular 40 acre well spacing and drilled with modern rotary equipment. The South Glenrock B Field is slated to be the first of our fields for 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. We plan to start CO₂ injection in the South Glenrock B Field in calendar year 2008.

Big Muddy Field

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

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

The current reservoir pressure is very low and not sufficient for effective 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 requires us to form two separate units, one for the Wall Creek formation and one for the Dakota formation, due to the different sizes of the productive horizons. It is expected that the unitization will be completed in calendar year 2008. We plan to start CO₂ injection in the Big Muddy Field in calendar year 2009.

Cole Creek South Field

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

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

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

The Cole Creek South Field is presently at reservoir pressure sufficient for miscible 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. We plan to start CO₂ injection in the Cole Creek South Field in either calendar year 2009 or 2010.

Oil & Gas Acreage and Productive Wells

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

	Developed Acres				Undeveloped Acres				Total Acres
Field	Gross		Net		Gross		Net		Gross		Net

Big Muddy Field		1,640		972		8,920		8,908		10,560		9,880
South Glenrock B Field		10,873		10,177		-		-		10,873		10,177
Cole Creek South Field		3,782		3,782		-		-		3,782		3,782

Total		16,295		14,931		8,920		8,908		25,215		23,839

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

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

Production

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

	For the Year Ended March 31, 2007

Net oil production (barrels)		23,838
Average realized oil sales price per barrel	$	48.74
Production costs per barrel:
Production taxes	$	5.72
Lease operating expenses	$	29.39

Title to Properties

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

Environmental Assessments

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

Geographic Segments

All of our operations are in the continental United States.

Significant Oil & Gas Purchasers and Product Marketing

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

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

Oil Marketing

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

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

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

Competition and Markets

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

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

ITEM 3. LEGAL PROCEEDINGS.

None.

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

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

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

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

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

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

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

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

PART II

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

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

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

Stock Performance Graph

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

Stock Performance Graph Data
	1/10/06		3/31/06		3/31/07

Rancher Energy Corp.		100.0		11,858.7		10,952.8
NASDAQ Composite		100.0		106.8		112.3
Dow Jones Wilshire MicroCap Exploration & Production		100.0		108.3		86.7

Holders

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

Dividends

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

Recent Sales of Unregistered Securities

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

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

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

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

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

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

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

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

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

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

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

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

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

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

ITEM 6. SELECTED FINANCIAL DATA.

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

The following selected financial data reflects the following:

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

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

Predecessor (the Cole Creek South Field and the South Glenrock B Field) revenues, lease operating expenses and production taxes for the period from January 1, 2006 through December 21, 2006 (the date of acquisition of the Predecessor by Rancher Energy Corp.), the year ended December 31, 2005, and for the period from September 1, 2004 (the date that the Predecessor was acquired from the Pre-Predecessor) through December 31, 2004;

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

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

Adjustments to eliminate the Predecessor’s results for the three months ended March 31, 2006 from the Predecessor results for the year ended December 31, 2006, so that the combined results will reflect the results for Rancher Energy Corp’s fiscal year ended March 31, 2007; and

Combined revenue, lease operating expenses and production taxes.

	Rancher Energy Corp.			Predecessor			Adjustments			Combined
	(1)(2)
	(Unaudited)
2007:
Revenues	$	1,161,819		$	4,488,315		$	(1,148,825	)	$	4,501,309
Production taxes		136,305			493,956			(120,313	)		509,948
Lease operating expenses		700,623			2,944,287			(574,756	)		3,070,154
Income (loss) from continuing operations		(8,702,255	)		(577,740	)		N/A			N/A
Loss from continuing operations per share		(0.16	)		N/A			N/A			N/A
Weighted average shares outstanding		53,782,291			N/A			N/A			N/A

Total assets		81,478,031			14,597,618			N/A			N/A

2006:
Revenues	$	-		$	3,713,973		$	N/A		$	3,713,973
Production taxes		N/A			428,905			N/A			428,905
Lease operating expenses		N/A			1,537,992			N/A			1,537,992
Income (loss) from continuing operations		(124,453	)		26,886			N/A			N/A
Loss from continuing operations per share		(0.00	)		N/A			N/A			N/A
Weighted average shares outstanding		32,819,623			N/A			N/A			N/A

Total assets		46,557			13,058,437			N/A			N/A

2005:
Revenues	$	-		$	1,997,663		$	N/A		$	1,997,663
Production taxes		N/A			219,955			N/A			219,955
Lease operating expenses		N/A			944,149			N/A			944,149
Income (loss) from continuing operations		(27,154	)		474,770			N/A			N/A
Loss from continuing operations per share		(0.00	)		N/A			N/A			N/A
Weighted average shares outstanding		70,000,000			N/A			N/A			N/A

Total assets		4,749			N/A			N/A			N/A

2004:
Revenues	$	-			N/A			N/A			N/A
Income (loss) from continuing operations		(375,000	)		N/A			N/A			N/A
Loss from continuing operations per share		(0.01	)		N/A			N/A			N/A
Weighted average shares outstanding					N/A			N/A			N/A

Total assets		-			N/A			N/A			N/A

_____________________

N/A - Not Applicable.

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

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

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

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

Organization

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

Oil & Gas Property Acquisitions

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

Cole Creek South Field and South Glenrock B Field Acquisitions

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

The total adjusted purchase price was allocated as follows:

Acquisition costs:
Cash consideration	$	46,750,000
Direct acquisition costs		323,657
Estimated fair value of warrants to purchase common stock		616,140
Total	$	47,689,797

Allocation of acquisition costs:
Oil & gas properties:
Unproved	$	31,569,778
Proved		16,682,101
Other assets - long-term accounts receivable		53,341
Other assets - inventory		227,220
Asset retirement obligation		(842,643	)
Total	$	47,689,797

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

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

Big Muddy Field Acquisition

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

The total adjusted purchase price was allocated as follows:

Acquisition costs:
Cash consideration	$	25,000,000
Direct acquisition costs		672,638
Total	$	25,672,638

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

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

Outlook for the Coming Year

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

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

Since late 2006 we have added operating staff and have engaged consultants to conduct field studies of tertiary development of the three Powder River Basin fields. To date, work has focused on field and engineering studies to prepare for development operations. We have also engaged an engineering firm to evaluate routes and undertake the required front end engineering and design for the required CO₂ pipeline, as well as another engineering firm to evaluate and design surface facilities appropriate for CO₂injection.

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

We plan to begin CO₂ development operations in the South Glenrock B Field, and preliminary development in the Big Muddy Field. We also plan to make capital expenditures relating to existing production in the three fields. The sum of our planned general and administrative costs, operating costs, CO₂ purchase costs, and field development capital expenditures for the fiscal years ending March 31, 2008 and 2009 are estimated to be approximately $90 to $95 million and $70 to $75 million, respectively. Of the fiscal year 2008 costs, about $75 million is projected for the South Glenrock B Field and Big Muddy Field projects, with about two-thirds of this cost for 3-D seismic, and well drilling and conversion for CO₂ injection, and the remainder for compressors and facilities. Since the acquisition of the three fields, other than the agreement with Anadarko for supply of CO₂, we have made no major capital expenditures nor any firm commitments for future capital expenditures to date.

The capital expenditures discussed above do not include costs of construction of the CO₂ pipeline. The route and configuration of this pipeline are being evaluated, and decisions on those factors have not been finalized. In addition, we are evaluating whether we will own and operate the line, or whether a third party will do so. That decision is also dependent on financing availability and certain other strategic factors.

Commitments

As part of our 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.

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 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%.

Results of Operations, Including Combined Results

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

The following data includes:

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

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

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

Combined results of operations.

	Year Ended March 31, 2007 (Unaudited)
	Rancher Energy Corp.			Predecessor			Adjustments			Combined
Revenue:
Oil production (in barrels)		23,838			73,076			(18,631	)		78,283
Oil price (per barrel)		48.74			61.42			61.66			57.50
Oil & gas sales	$	1,161,819		$	4,488,315		$	(1,148,825	)	$	4,501,309

Operating expenses:
Production taxes		136,305			493,956			(120,313	)		509,948
Lease operating expenses		700,623			2,944,287			(574,756	)		3,070,154
Depreciation, depletion, and amortization		375,701			952,784			(267,050	)		1,061,435
Impairment of unproved properties		734,383			-			-			734,383
Accretion expense		29,730			107,504			(26,876	)		110,358
Exploration expense		333,919			-			-			333,919
General and administrative		4,501,737			567,524			(141,881	)		4,927,380
Total operating expenses		6,812,398			5,066,055			(1,130,876	)		10,747,577

		(5,650,579	)		(577,740	)		(17,949	)		(6,246,268	)

Other income (expense):
Liquidated damages pursuant to registration rights agreement		(2,705,531	)		-			-			(2,705,531	)
Interest expense		(37,654	)		-			-			(37,654	)
Amortization of deferred financing costs		(537,822	)		-			-			(537,822	)
Interest and other income		229,331			-			-			229,331
Total other income (expense)		(3,051,676	)		-			-			(3,051,676	)

	$	(8,702,255	)	$	(577,740	)	$	(17,949	)	$	(9,297,944	)

	Year Ended March 31, 2006 (Unaudited)
	Rancher Energy Corp.			Predecessor		Combined
Revenue:
Oil production (in barrels)		-			67,321		67,321
Oil price (per barrel)		-			55.17		55.17
Oil & gas sales		-			3,713,973		3,713,973

Operating expenses:
Production taxes		-			428,905		428,905
Lease operating expenses		-			1,537,992		1,537,992
Depreciation, depletion and amortization		213			567,345		567,558
Accretion expense		-			107,712		107,712
General and administrative		74,240			1,045,133		1,119,373
Exploration expense - mining		50,000			-		50,000
Total operating expenses		124,453			3,687,087		3,811,540

	$	(124,453	)	$	26,886	$	(97,567	)

	Year Ended March 31, 2005 (Unaudited)
	Rancher Energy Corp.			Predecessor			Pre- Predecessor		Combined
Revenue:
Oil production (in barrels)		-			16,234			35,882		52,116
Oil price (per barrel)		-			44.50			35.54		38.33
Oil & gas sales		-			722,449			1,275,214		1,997,663

Operating expenses:
Production taxes		-			81,868			138,087		219,955
Lease operating expenses		-			360,207			583,942		944,149
Depreciation, depletion and amortization		201			62,542			-		62,473
Accretion expense		-			12,990			-		12,990
General and administrative		26,953			283,257			-		310,210
Total operating expenses		27,154			800,864			722,029		1,550,047

	$	(27,154	)	$	(78,415	)	$	553,185	$	447,616

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

Rancher Energy Corp.

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

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

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

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

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

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

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

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

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

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

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

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

Rancher Energy Corp. Combined with Predecessor and Pre-Predecessor

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

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

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

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

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

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

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

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

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

Liquidity and Capital Resources

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

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

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

We currently have negative cash flow from operating activities. Monthly oil & gas production revenue is adequate to cover monthly field operating costs and production taxes at the current time. Only a portion of the remaining cash costs, which consist primarily of general and administrative expenses, are covered by cash flow. At current staffing levels, the negative cash flow is projected to be covered by available cash, assuming no additional financing is obtained by us, through fiscal year 2008. However, in the event we are not successful in raising financing adequate to begin our CO₂ development projects, we do not plan to allow negative monthly cash flow to remain at current levels. Rather, we plan to address the situation at that time by reducing staffing levels to reduce cash requirements, and using proceeds of a senior revolving debt facility, if available, to pursue development projects to enhance near term production rates and cash flow.

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

Change in Financial Condition

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

Convertible Debt Transactions

Venture Capital First LLC

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

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

Private Placement - Convertible Notes Payable

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

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

Equity Transactions

Units Issued Pursuant to Regulation S

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

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

Warrant Modification - Warrants Issued Pursuant to Regulation S

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

Private Placement

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

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

Summary of Warrants

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

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

	Warrants		Exercise Price		Expiration Date
Warrants issued in connection with the following:

Sale of common stock pursuant to Regulation S		18,133,500	$	0.75-$1.00		July 5, 2008 to October 18, 2008

Conversion of notes payable into common stock		1,006,905	$	0.75		July 19, 2008

Private placement of common stock		45,940,510	$	1.50		March 30, 2012

Private placement of convertible notes payable		6,996,322	$	1.50		March 30, 2012

Private placement agent commissions		2,187,580	$	1.50		March 30, 2009

Private placement agent commissions		1,445,733	$	1.50		March 30, 2012

Acquisition of oil & gas properties		250,000	$	1.50		December 22, 2011

Total warrants outstanding at March 31, 2007		75,960,550

Cash Flows

The following is a summary of our comparative cash flows:

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

Analysis of cash flow changes between 2007 and 2006

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

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

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

Capital Expenditures

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

	For the Year Ended March 31,
	2007		2006		2005

Exploration	$	333,919	$	-	$	-
Development		-		-		-
Acquisitions:
Unproved		56,813,516		-		-
Proved		18,552,188		-		-
Total		75,699,623		-		-

Costs associated with asset retirement obligations	$	1,191,837	$	-	$	-

Schedule of Contractual Obligations

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

	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years

Operating lease	$	1,907,640	$	280,859	$	733,061	$	765,773	$	127,947

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

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

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

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

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

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

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

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

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

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

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

Commodity Price Risk

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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

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

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

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

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

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

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

ITEM 9A. CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures.

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

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

Management’s Annual Report on Internal Control over Financial Reporting

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

·	Establish and maintain adequate internal control over financial reporting,

·	Assess the effectiveness of internal control over financing reporting,

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

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

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

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

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

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

Management’s assessment of our internal control over financial reporting is not effective as of March 31, 2007 due to the identification of the following material weaknesses.

(A) Our operating environment did not sufficiently promote effective internal control over financial reporting throughout the organization.

During the year, the Company changed focus from one engaged in the exploration of a gold prospect in British Columbia, Canada which found no commercially exploitable deposits or reserves of gold, to an oil & gas company focused on using CO₂ enhanced oil recovery methods in the Powder River Basin, Wyoming.

The change in operating environment is evidenced by the following:

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

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

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

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

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

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

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

We did not maintain sufficient auditable evidence of management’s review and analysis of the reports that we file or submit under the Exchange Act. We have implemented measures to retain copies of comments from our personnel evidencing such review and analysis. We anticipate that this deficiency will be remediated December 31, 2007.

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

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

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

We did not conduct a full fraud assessment process prior to year end. In May 2007 we initiated a formal fraud assessment process. Our policies call for a quarterly fraud assessment as part of our financial closing procedures and an annual fraud assessment as part of the business planning process carried out by our management. We anticipate that the steps necessary to address this deficiency will be fully implemented by December 31, 2007.

We did not obtain prescribed attestations by management regarding their compliance with an insider trading policy or attestations from our employees as to their understanding of and compliance with the company policies related to insider trading. We adopted a formal Insider Trading Policy on May 31, 2007. This policy document has been posted on our website and we have distributed the policy document to all employees and Directors, and as of the date of filing of this Annual Report we received from all employees and Directors attestations as to their understanding of and compliance with this policy.

(B) We did not have a sufficient complement of personnel with appropriate training and experience in GAAP, as evidenced by the following deficiencies:

The rapid employee growth of the Company from two employees one year ago to over 25 employees as of the date of filing of this Annual Report resulted in the Company not having a sufficient complement of personnel with appropriate training and experience in GAAP during the past fiscal year. We did not have any significant properties or operations until we completed our equity private placement in mid-January 2007 and acquired our three properties in Wyoming. In January 2007 we hired a Chief Financial Officer with an M.B.A. in Finance from the Wharton School, University of Pennsylvania, and with B.S. and Master’s degrees in civil engineering from Rice University. He has over twenty years of experience in financial management and strategic planning in the energy industry, including serving most recently as treasurer and acting chief financial officer of a privately held energy and production company. Although both our Chief Executive Officer and Chief Financial Officer have substantial financial experience, they do not have significant experience in preparing financial statements of a publicly held company or in implementing internal control over financing reporting for a public company. As a result, during the year we relied primarily on consultants for preparation of our financial statements and for our internal control over financial reporting. For example, the reconciliation of payroll, among other items, to the general ledger was not performed throughout the year. Management, in coordination with the Audit Committee, has undertaken steps to reorganize our Accounting Department, and management is allocating significant additional resources to our Accounting Department, including retaining additional consultants and hiring new full-time personnel.

In June 2007, our Financial Controller, who was hired in March 2007, announced her intention to leave the Company. Management, in coordination with the Audit Committee, has begun an executive search for a new Financial Controller. We expect this deficiency will be remediated by December 31, 2007.

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

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

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

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

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

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

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

Changes in Internal Control over Financial Reporting

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

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Rancher Energy Corp.

Denver, Colorado

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control, that Rancher Energy Corp. did not maintain effective internal control over financial reporting as of March 31, 2007, because of the effect of the material weaknesses identified in management’s assessment, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Rancher Energy Corp.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

To the Board of Directors

Rancher Energy Corp.

Page 2

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

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weaknesses have been identified and included in management’s assessment as of March 31, 2007.

1)	The Company’s control environment did not sufficiently promote effective internal control over financial reporting throughout the organization.

2)	The Company did not have in place adequate competent accounting personnel with the appropriate training and expertise in generally accepted accounting principles (“GAAP”).

3)	The Company did not adequately segregate the duties in the accounting department, due to an insufficient complement of personnel and inadequate management oversight.

These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2007 financial statements, and this report does not affect our report dated June 28, 2007 on those financial statements.

In our opinion, management’s assessment that Rancher Energy Corp. did not maintain effective internal control over financial reporting as of March 31, 2007, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by COSO. Also, in our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, Rancher Energy Corp. did not maintain effective internal control over financial reporting as of March 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO.

/s/ HEIN& ASSOCIATES LLP

Denver, Colorado

June 28, 2007

ITEM 9B. OTHER INFORMATION.

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

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

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

ITEM 11. EXECUTIVE COMPENSATION.

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

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

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

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

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

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

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

PART IV

ITEM 15. EXHIBITS, Financial Statement Schedules.

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

(1) Index to Consolidated Financial Statements of the Company

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

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

(3) Exhibits

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(20)	Filed herewith.

SIGNATURES

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

		RANCHER ENERGY CORP.

		/s/ John Works
		John Works, President, Chief Executive Officer, Principal Executive Officer, Director, Secretary, and Treasurer

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

Signature	Title	Date

/s/ John Works	President, Chief Executive Officer,
John Works	Principal Executive Officer, Director, Secretary, and Treasurer	June 29, 2007

/s/ Daniel P. Foley	Chief Financial Officer, Principal
Daniel P. Foley	\Financial Officer, and Principal Accounting Officer	June 29, 2007

/s/ William A. Anderson
William A. Anderson	Director	June 29, 2007

/s/ Joseph P. McCoy
Joseph P. McCoy	Director	June 29, 2007

/s/ Patrick M. Murray
Patrick M. Murray	Director	June 29, 2007

/s/ Myron M. Sheinfeld
Myron M. Sheinfeld	Director	June 29, 2007

/s/ Mark Worthey
Mark Worthey	Director	June 29, 2007

EXHIBIT INDEX

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

E-1

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

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

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

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

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

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

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

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

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

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

E-2

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

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

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

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

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

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

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

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

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

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

(20)	Filed herewith.

E-3

INDEX TO FINANCIAL STATEMENTS

Audited Financial Statements - Rancher Energy Corp.

Report of Independent Registered Public Accounting Firm	F-2

Report of Independent Registered Public Accounting Firm	F-3

Balance Sheets as of March 31, 2007 and 2006	F-4

Statements of Operations for the Years Ended March 31, 2007, 2006, and 2005	F-5

Statement of Changes in Stockholders’ Equity (Deficit) for the Years Ended March 31, 2007, 2006, and 2005	F-6

Statements of Cash Flows for the Years Ended March 31, 2007, 2006, and 2005	F-7

Notes to Financial Statements	F-8

Audited Carve Out Financial Statements - Cole Creek South and South Glenrock Operations

Report of Independent Registered Public Accounting Firm	F-29

Carve Out Balance Sheets as of December 21, 2006 and December 31, 2005	F-30

Carve Out Statements of Operations for the Period from January 1, 2006 through December 21, 2006, the year ended December 31, 2005 and for the Period from September 1, 2004 (inception) through December 31, 2004	F-31

Carve Out Statement of Changes in Owner’s Net Investment for the Period from September 1, 2004 (inception) through December 31, 2004, the year ended December 31, 2005, and for the Period from January 1, 2006 through December 21, 2006	F-32

Carve Out Statements of Cash Flows for the Period from January 1, 2006 through December 21, 2006, the year ended December 31, 2005 and the Period from September 1, 2004 (inception) through December 31, 2004	F-33

Notes to Carve Out Financial Statements	F-34

Audited Statement of Revenues and Direct Operating Expenses - Cole Creek South and South Glenrock Operations

Report of Independent Registered Public Accounting Firm	F-42

Statement of Revenues and Direct Operating Expenses for the Period from January 1, 2004 through August 31, 2004	F-43

Notes to Statement of Revenues and Direct Operating Expenses	F-44

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders of Rancher Energy Corp.

Denver, Colorado

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

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

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

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

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

/s/ Hein & Associates LLP

Denver, Colorado

June 28, 2007

F-2

To the Board of Directors

Rancher Energy Corp.

(fka Metalex Resources, Inc.)

Spokane, Washington

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited the accompanying balance sheets of Rancher Energy Corp. (fka Metalex Resources, Inc. and a Nevada corporation and an exploration stage company) as of March 31, 2006 and 2005, and the related statements of operations, stockholder’s deficit and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rancher Energy Corp. as of March 31, 2006 and 2005, and the results of its operations, stockholder’s deficit and cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company’s operating losses raise substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters also are described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/Williams & Webster, P.S.

Williams & Webster, P.S.

Certified Public Accountants

Spokane, Washington

June 19, 2006

F-3

Rancher Energy Corp.

Balance Sheets

	March 31,
	2007			2006
ASSETS

Current assets:
Cash and cash equivalents	$	5,129,883		$	46,081
Accounts receivable		453,709			-
Total current assets		5,583,592			46,081

Oil & gas properties (successful efforts method):
Unproved		56,079,133			-
Proved		18,552,188			-
Less: Accumulated depletion, depreciation, and amortization		(347,821	)		-
Net oil & gas properties		74,283,500			-

Other assets, net of accumulated depreciation of $27,880 and $414, respectively		1,610,939			476

Total assets	$	81,478,031		$	46,557

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	1,542,840		$	2,070
Accrued oil & gas property costs		250,000			-
Asset retirement obligation		196,000			-
Liquidated damages pursuant to registration rights arrangement		2,705,531			-
Total current liabilities		4,694,371			2,070

Long-term liabilities:
Asset retirement obligation		1,025,567			-

Commitments and contingencies (Note 5)

Stockholders’ equity:
Common stock, $0.00001 par value, 275,000,000 and 100,000,000 shares authorized at March 31, 2007 and 2006, respectively; 102,041,432 and 28,500,000 shares issued and outstanding at March 31, 2007 and 2006, respectively		1,021			285
Additional paid-in capital		84,985,934			570,809
Accumulated deficit		( 9,228,862	)		(526,607	)
Total stockholders’ equity		75,758,093			44,487

Total liabilities and stockholders’ equity	$	81,478,031		$	46,557

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

F-4

Rancher Energy Corp.

Statements of Operations

	For the Years Ended March 31,
	2007			2006			2005
Revenue:
Oil & gas sales	$	1,161,819		$	-		$	-

Operating expenses:
Production taxes		136,305			-			-
Lease operating expenses		700,623			-			-
Depreciation, depletion, and amortization		375,701			213			201
Impairment of unproved properties		734,383			-			-
Accretion expense		29,730			-			-
Exploration expense		333,919			-			-
General and administrative		4,501,737			74,240			26,953
Exploration expense - mining		-			50,000			-
Total operating expenses		6,812,398			124,453			27,154

Loss from operations		(5,650,579	)		(124,453	)		(27,154	)

Other income (expense):
Liquidated damages pursuant to registration rights arrangement		( 2,705,531	)		-			-
Amortization of deferred financing costs		( 537,822	)		-			-
Interest expense		(37,654	)		-			-
Interest and other income		229,331			-			-
Total other income (expense)		( 3,051,676	)		-			-

Net loss	$	( 8,702,255	)	$	(124,453	)	$	(27,154	)

Basic and fully diluted net loss per share	$	(0.16	)	$	(0.00	)	$	(0.00	)

Weighted average shares outstanding		53,782,291			32,819,623			70,000,000

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

F-5

Rancher Energy Corp.

Statement of Changes in Stockholders’ Equity (Deficit)

	Shares			Amount			Additional Paid- In Capital		Accumulated Deficit			Total Stockholders’ Equity (Deficit)

Balance, April 1, 2004		70,000,000		$	700		$	374,300	$	(375,000	)	$	-

Net loss		-			-			-		(27,154	)		(27,154	)

Balance, March 31, 2005		70,000,000			700			374,300		(402,154	)		(27,154	)

Common stock issued for cash, net of offering costs of $3,906		28,000,000			280			195,814		-			196,094

Shares returned by founding stockholder		(69,500,000	)		(695	)		695		-			-

Net loss		-			-			-		(124,453	)		(124,453	)

Balance, March 31, 2006		28,500,000			285			570,809		(526,607	)		44,487

Common stock issued for cash, net of offering costs of $529,749		17,075,221			171			8,106,967		-			8,107,138

Common stock issued on conversion of note payable		1,006,905			10			503,443		-			503,453

Common stock issued on exercise of stock options		1,000,000			10			-		-			10

Common stock issued for cash, net of offering costs of $41,212		1,522,454			15			720,001		-			720,016

Warrants issued in exchange for acquisition of oil & gas properties		-			-			616,140		-			616,140

Common stock issued for cash, net of offering costs of $6,054,063		45,940,510			460			62,856,243		-			62,856,703

Common stock issued for conversion of notes payable, net of offering costs of $384,159		6,996,342			70			10,110,423		-			10,110,493

Stock-based compensation		-			-			1,501,908		-			1,501,908

Net loss		-			-			-		( 8,702,255	)		( 8,702,255	)

Balance, March 31, 2007		102,041,432		$	1,021		$	84,985,934	$	( 9,228,862	)	$	75,758,093

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

F-6

Rancher Energy Corp.

Statements of Cash Flows

	For the Years Ended March 31,
	2007			2006			2005
Cash flows from operating activities:
Net loss	$	( 8,702,255	)	$	(124,453	)	$	(27,154	)
Adjustments to reconcile net loss to net cash used for operating activities:
Liquidated damages pursuant to registration rights arrangements		2,705,531			-			-
Depreciation, depletion, and amortization		375,701			213			201
Impairment of unproved properties		734,383			-			-
Accretion expense		29,730			-			-
Stock-based compensation expense		1,501,908			-			-
Amortization of deferred financing costs		537,822			-			-
Interest expense on convertible note payable beneficial conversion		30,000			-			-
Interest expense on debt converted to equity		3,453			-			-
Changes in operating assets and liabilities:
Accounts receivable		(453,709	)		-			-
Other assets		(588,764	)		-			-
Accounts payable and accrued liabilities		1,540,770			167			1,903
Net cash used for operating activities		(2,285,430	)		(124,073	)		(25,050	)

Cash flows from investing activities:
Acquisition of Cole Creek South and South Glenrock B Fields		(47,073,657	)		-			-
Acquisition of Big Muddy Field		(25,672,638	)		-			-
Capital expenditures for oil & gas properties		(841,993	)		-			-
Increase in other assets		(769,018	)		-			(890	)
Net cash used for investing activities		(74,357,306	)		-			(890	)

Cash flows from financing activities:
Increase in deferred financing costs		( 921,981	)		-			-
Proceeds from issuance of convertible notes payable		11,144,582			-			-
Payment of convertible note payable		(150,000	)
Proceeds from shareholder loans		-			-			30,000
Payment of shareholder loans		-			(30,000	)		-
Proceeds from sale of common stock and warrants		71,653,937			196,094			-
Net cash provided by financing activities		81,726,538			166,094			30,000

Increase in cash and cash equivalents		5,083,802			42,021			4,060
Cash and cash equivalents, beginning of year		46,081			4,060			-
Cash and cash equivalents, end of year	$	5,129,883		$	46,081		$	4,060
Non-cash investing and financing activities:
Payables for purchase of oil & gas properties	$	250,000		$	-		$	-
Asset retirement asset and obligation	$	1,191,837		$	-		$	-
Value of warrants issued in connection with acquisition of Cole Creek South and South Glenrock B Fields	$	616,140		$	-		$	-
Common stock and warrants issued on conversion of notes payable	$	10,613,876		$	-		$	-

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

F-7

Rancher Energy Corp.

Notes to Financial Statements

Note 1—Organization and Summary of Significant Accounting Policies

Organization

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

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

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

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

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

Use of Estimates in the Preparation of Financial Statements

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

Revenue Recognition

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

F-8

Cash and Cash Equivalents

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

Concentration of Credit Risk

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

Oil & Gas Producing Activities

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

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

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

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

F-9

Sales of Proved and Unproved Properties

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

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

Other Property and Equipment

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

Fair Value of Financial Instruments

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

Income Taxes

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

Net Income (Loss) per Share

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

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

F-10

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

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

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

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

	For the Year Ended March 31,
	2007			2006			2005

Net loss	$	( 8,702,255	)	$	(124,453	)	$	(27,154	)

Basic weighted average common shares outstanding		53,782,291			32,819,623			70,000,000

Basic and diluted net loss per common share		(0.16	)		(0.00	)		(0.00	)

Share-Based Payment

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

Registration Payment Arrangements

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

F-11

Recently Issued Accounting Standards

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

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

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

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

Comprehensive Income (Loss)

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

Major Customers

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

F-12

Industry Segment and Geographic Information

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

Off—Balance Sheet Arrangements

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

Note 2—Oil & Gas Properties

Acquisitions

Cole Creek South Field and South Glenrock B Field Acquisitions

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

The total adjusted purchase price was allocated as follows:

Acquisition costs:
Cash consideration	$	46,750,000
Direct acquisition costs		323,657
Estimated fair value of warrants to purchase common stock		616,140
Total	$	47,689,797

Allocation of acquisition costs:
Oil & gas properties:
Unproved	$	31,569,778
Proved		16,682,101
Other assets - long-term accounts receivable		53,341
Other assets - inventory		227,220
Asset retirement obligation		(842,643	)
Total	$	47,689,797

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

F-13

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

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

Big Muddy Field Acquisition

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

The total adjusted purchase price was allocated as follows:

Acquisition costs:
Cash consideration	$	25,000,000
Direct acquisition costs		672,638
Total	$	25,672,638

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

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

Pro Forma Results of Operations

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

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

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

Carbon Dioxide Product Sale and Purchase Contract

As part of our CO₂ tertiary recovery strategy, on December 15, 2006, the Company entered into a Product Sale and Purchase Contract (Purchase Contract) with the Anadarko Petroleum Corporation (Anadarko) for the purchase of CO₂ (meeting certain quality specifications identified in the agreement) from Anadarko. The Company intends to use the CO₂ for its enhanced oil recovery (EOR) projects.

F-14

The primary term of the Agreement commences upon the later of January 1, 2008, or the date of the first CO₂delivery, 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. 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.

Impairment of Unproved Properties

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

Note 3—Asset Retirement Obligations

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

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

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

F-15

Beginning asset retirement obligation	$	-
Liabilities incurred		1,191,837
Accretion expense		29,730
Ending asset retirement obligation	$	1,221,567

Current	$	196,000
Long-term		1,025,567
	$	1,221,567

Note 4—Convertible Notes Payable

Enerex Capital Corp.

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

Venture Capital First LLC

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

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

Private Placement

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

F-16

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

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

Note 5—Commitments and Contingencies

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

Years Ending March 31,
2008	$	280,859
2009		362,403
2010		370,658
2011		381,931
2012		383,842
Thereafter		127,947
Total	$	1,907,640

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

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

Note 6—Sale of Common Stock and Warrants

For the Year Ended March 31, 2007

Units Issued Pursuant to Regulation S

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

F-17

Warrant Modification - Warrants Issued Pursuant to Regulation S

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

Private Placement

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

Summary of Warrants

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

	Warrants		Exercise Price		Expiration Date
Warrants issued in connection with the following:

Sale of common stock pursuant to Regulation S		18,133,500	$	0.75-$1.00		July 5, 2008 to October 18, 2008

Conversion of notes payable into common stock		1,006,905	$	0.75		July 19, 2008

Private placement of common stock		45,940,510	$	1.50		March 30, 2012

Private placement of convertible notes payable		6,996,322	$	1.50		March 30, 2012

Private placement agent commissions		2,187,580	$	1.50		March 30, 2009

Private placement agent commissions		1,445,733	$	1.50		March 30, 2012

Acquisition of oil & gas properties		250,000	$	1.50		December 22, 2011

Total warrants outstanding at March 31, 2007		75,960,550

F-18

Registration and Other Payment Arrangements

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

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

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

F-19

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

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

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

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

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

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

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

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

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

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

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

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

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

Currently, there are no equity conditions failures.

F-20

For the Year Ended March 31, 2006

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

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

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

Note 7—Share-Based Compensation

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

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

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

Chief Executive Officer (CEO) Option Grant

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

F-21

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

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

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

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

2006 Stock Incentive Plan

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

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

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

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

F-22

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

	Outstanding Options
	Number of Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in Years)		Total Intrinsic Value
Outstanding, April 1, 2006		—
Granted—
CEO		4,000,000		$	0.00001		2.25
Plan		3,335,000		$	2.34		4.61
Total		7,335,000		$	1.06		3.32

Exercised—CEO		(1,000,000	)		0.00001		—

Outstanding, March 31, 2007
CEO		3,000,000			0.00001		2.25	$	3,989,970
Plan		3,335,000			2.34		4.61	$	(4,593,750	)
Total		6,335,000			1.23		3.49	$	(603,780	)

Vested or expected to vest at March 31, 2007—
CEO		1,750,000		$	0.00001		2.25	$	2,327,483
Plan		187,500		$	1.75		4.50	$	(78,750	)
Total		1,937,500		$	0.19		2.47	$	2,248,733

Exercisable, March 31, 2007—
CEO		750,000		$	0.00001		2.25	$	997,493
Plan		187,500		$	1.75		4.50	$	(328,125	)
Total		937,500		$	0.35		2.70	$	669,368

F-23

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

	Number of Shares			Grant Date Fair Value

Non-vested, April 1, 2006		__		$	__
Granted—
CEO		4,000,000			0.42
Plan		3,335,000			1.52
Total		7,335,000			0.92

Vested—
CEO		(750,000	)		0.42
Plan		(187,500	)		1.13
Total		(937,500	)		0.56

Exercised—CEO		(1,000,000	)		0.42

Non-vested, March 31, 2007
CEO		2,250,000		$	0.42
Plan		3,147,500		$	1.54
Total		5,397,500		$	1.07

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

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

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

Subsequent Events

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

F-24

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

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

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

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

Note 8—Income Taxes

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

	For the Year Ended March 31,
	2007			2006			2005

Expected amount	$	3,045,789		$	43,559		$	9,504
Permanent items		(183,726	)		-			-
Other		128,087			-			-
Change in valuation allowance		(2,990,150	)		(43,559	)		(9,504	)
	$	-		$	-		$	-

F-25

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

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

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

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

Note 9—Disclosures about Oil & Gas Producing Activities

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

Costs Incurred in Oil & Gas Producing Activities:

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

	For the Year Ended March 31,
	2007		2006		2005

Exploration	$	333,919	$	-	$	-
Development		-		-		-
Acquisitions:
Unproved		56,813,516		-		-
Proved		18,552,188		-		-
Total		75,699,623		-		-

Costs associated with asset retirement obligations	$	1,191,837	$	-	$	-

Oil & Gas Reserve Quantities (Unaudited):

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

F-26

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

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

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

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

Proved developed reserves:	1,062,206

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

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

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

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

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

F-27

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

	As of March 31, 2007

Future cash inflows	$	68,396,874
Future production costs		(38,185,216	)
Future development costs		(2,004,287	)
Future income taxes		-
Future net cash flows		28,207,371
10% annual discount		(15,088,423	)
Standardized measure of discounted future net cash flows	$	13,118,948

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

	For the year ended March 31, 2007

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

Note 10—Related Party Transaction

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

F-28

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Nielson & Associates, Inc.:

We have audited the accompanying carve out balance sheets of South Cole Creek and South Glenrock operations as of December 21, 2006 and December 31, 2005, and the related carve out statements of operations, changes in owner’s net investment, and cash flows for the period from January 1, 2006 to December 21, 2006, the year ended December 31, 2005, and the period from September 1, 2004 to December 31, 2004. These financial statements are the responsibility of Nielson & Associates, Inc.’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the carve out financial position of South Cole Creek and South Glenrock operations as of December 21, 2006 and December 31, 2005, and the carve out results of their operations and their cash flows for the period from January 1, 2006 to December 21, 2006, the year ended December 31, 2005, and the period from September 1, 2004 to December 31, 2004, in conformity with U.S. generally accepted accounting principles.

South Cole Creek and South Glenrock Operations

Carve Out Balance Sheets

	December 21, 2006			December 31, 2005
Assets

Current assets:
Accounts receivable:
Revenue	$	281,142		$	359,903
Joint interest		91,024			12,036
Total current assets		372,166			371,939

Property and equipment, at cost:
Oil and gas properties, successful efforts method of accounting
Proved properties		15,634,302			13,142,564
Unproved properties		173,821			173,821
		15,808,123			13,316,385
Less accumulated depreciation, depletion, and amortization		(1,582,671	)		(629,887	)
Net property and equipment		14,225,452			12,686,498

Total assets	$	14,597,618		$	13,058,437

Liabilities and Owner’s Net Investment

Current liabilities:
Accounts payable and accrued liabilities	$	663,922	$	359,319
Production taxes		368,088		238,093
Asset retirement obligations		10,916		482,369
Total current liabilities		1,042,926		1,079,781

Production taxes		163,700		165,957

Asset retirement obligations		958,023		861,435

Owner’s net investment		12,432,969		10,951,264

Total liabilities and owner’s net investment	$	14,597,618	$	13,058,437

See accompanying notes to carve out financial statements.

F-30

South Cole Creek and South Glenrock Operations

Carve Out Statements of Operations

	From January 1, 2006 to December 21, 2006			Year Ended December 31, 2005		From September 1, 2004 to December 31, 2004

Revenue:
Oil sales	$	4,488,315		$	3,713,973	$	722,449

Operating expenses:
Lease operating expense		2,944,287			1,537,992		360,207
Production taxes		493,956			428,905		81,868
General and administrative		567,524			1,045,133		283,257
Depreciation, depletion, and amortization		952,784			567,345		62,542
Accretion of asset retirement obligations		107,504			107,712		12,990
Total operating expenses		5,066,055			3,687,087		800,864

Net income (loss)	$	(577,740	)	$	26,886	$	(78,415	)

See accompanying notes to carve out financial statements.

F-31

South Cole Creek and South Glenrock Operations

Carve Out Statement of Changes in Owner’s Net Investment



Balance at September 1, 2004 (inception)	$	-

Owner’s contributions, net		2,468,305
Net loss		(78,415	)

Balance at December 31, 2004		2,389,890

Owner’s contributions, net		8,534,488
Net income		26,886

Balance at December 31, 2005		10,951,264

Owner’s contributions, net		2,059,445
Net loss		(577,740	)

Balance at December 21, 2006	$	12,432,969

See accompanying notes to carve out financial statements.

F-32

South Cole Creek and South Glenrock Operations

Carve Out Statements of Cash Flows

	From January 1, 2006 to December 21, 2006			Year Ended December 31, 2005			From September 1, 2004 to December 31, 2004

Operating activities:
Net income (loss)	$	(577,740	)	$	26,886		$	(78,415	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization		952,784			567,345			62,542
Accretion of asset retirement obligations		107,504			107,712			12,990
Change in operating assets and liabilities:
Accounts receivable		(227	)		(51,094	)		(320,845	)
Accounts payable and accrued expenses		304,603			103,287			256,032
Production taxes payable		127,738			306,150			97,900
Settlement of asset retirement obligations		(482,369	)		(110,314	)		-
Net cash provided by operating activities		432,293			949,972			30,204

Investing activities:
Acquisition of oil and gas properties		-			(2,299,715	)		(2,498,509	)
Exploration and development expenditures		(2,491,738	)		(7,184,745	)		-
Net cash used for investing activities		(2,491,738	)		(9,484,460	)		(2,498,509	)

Financing activities:
Contributions from owner, net		2,059,445			8,534,488			2,468,305
Net cash provided by financing activities		2,059,445			8,534,488			2,468,305

Net increase (decrease) in cash and cash equivalents		-			-			-

Cash and cash equivalents at beginning of period		-			-			-

Cash and cash equivalents at end of period	$	-		$	-		$	-

Non-cash investing activities:
Increase in asset retirement obligations	$	-		$	507,748		$	825,668

See accompanying notes to carve out financial statements.

F-33

South Cole Creek and South Glenrock Operations

Notes to Carve Out Financial Statements

December 21, 2006

Note 1 - Basis of Presentation

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

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

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

Note 2 - Summary of Significant Accounting Policies

Cash and Cash Equivalents

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

F-34

South Cole Creek and South Glenrock Operations

Notes to Carve Out Financial Statements

December 21, 2006

Note 2 - Summary of Significant Accounting Policies (continued)

Use of Estimates

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

Revenue Recognition and Receivables

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

Oil Properties

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

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

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

F-35

South Cole Creek and South Glenrock Operations

Notes to Carve Out Financial Statements

December 21, 2006

Note 2 - Summary of Significant Accounting Policies (continued)

Oil Properties (continued)

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

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

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

Asset Retirement Obligations

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

Income Taxes

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

F-36

South Cole Creek and South Glenrock Operations

Notes to Carve Out Financial Statements

December 21, 2006

Note 2 - Summary of Significant Accounting Policies (continued)

Allocation of Costs

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

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

Earnings Per Share

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

Note 3 - Asset Retirement Obligations

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

	From January 1, 2006 to December 21, 2006			Year Ended December 31, 2005			From September 1, 2004 to December 31, 2004

ARO liability- beginning of period	$	1,343,804		$	838,658		$	-
ARO liabilities assumed in acquisitions		-			484,922			825,668
ARO liabilities incurred in the current period		-			22,826			-
ARO liabilities settled in the current period		(482,369	)		(110,314	)		-
Accretion expense		107,504			107,712			12,990

ARO liability - end of period	$	968,939		$	1,343,804		$	838,658

F-37

South Cole Creek and South Glenrock Operations

Notes to Carve Out Financial Statements

December 21, 2006

Note 4 - Concentrations

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

	From January 1, 2006 to December 21, 2006			Year Ended December 31, 2005			From September 1, 2004 to December 31, 2004

Customer A		-			11	%		46	%
Customer B		58	%		62	%		54	%
Customer C		42	%		27	%		-

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

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

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

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

	From January 1, 2006 to December 21, 2006		Year Ended December 31, 2005		From September 1, 2004 to December 31, 2004

Acquisition of proved properties	$	-	$	2,807,433	$	3,306,967
Acquisition of unproved properties		-		156,611		17,210
Exploration costs		-		-		-
Development costs		2,491,738		7,028,164		-
Total costs incurred for acquisition, exploration and development activities	$	2,491,738	$	9,992,208	$	3,324,177

F-38

South Cole Creek and South Glenrock Operations

Notes to Carve Out Financial Statements

December 21, 2006

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

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

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

Proved developed and undeveloped reserves:

Proved reserves:	Year Ended December 31, 2006			Year Ended December 31, 2005			From September 1, 2004 to December 31, 2004

Beginning of period		1,588,713			837,846			-
Purchases of minerals in place		-			633,384			854,080
Revisions of estimates		(487,469	)		94,280			-
Extensions and discoveries		-			90,524			-
Production		(73,076	)		(67,321	)		(16,234	)

End of period		1,028,168			1,588,713			837,846

Proved Developed Reserves		827,487			1,372,989			837,846

Standardized Measure of Discounted Future Net Cash Flows

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

F-39

South Cole Creek and South Glenrock Operations

Notes to Carve Out Financial Statements

December 21, 2006

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

Standardized Measure of Discounted Future Net Cash Flows (continued)

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

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

	December 31, 2006			December 31, 2005			December 31, 2004

Future cash inflows	$	47,317,344		$	86,488,888		$	33,157,864
Future production costs		(29,851,344	)		(46,837,348	)		(19,815,423	)
Future development costs		(2,004,287	)		(2,304,287	)		-
Future net cash flows		15,461,713			37,347,253			13,342,441
10 percent annual discount		(7,666,089	)		(20,374,454	)		(6,595,775	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	7,795,624		$	16,972,799		$	6,746,666

F-40

South Cole Creek and South Glenrock Operations

Notes to Carve Out Financial Statements

December 21, 2006

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

Standardized Measure of Discounted Future Net Cash Flows (continued)

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

	From January 1, 2006 to December 31, 2006			Year Ended December 31, 2005			From September 1, 2004 to December 31, 2004

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

End of period	$	7,795,624		$	16,972,799		$	6,746,666

F-41

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

Board of Directors

Rancher Energy Corp.

Denver, Colorado

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

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

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

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

/s/ HEIN & ASSOCIATES LLP

Denver, Colorado

June 28, 2007

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South Cole Creek and South Glenrock Operations

Statement of Revenues and Direct Operating Expenses

	For the Period January 1 through August 31, 2004

Revenue:
Oil sales	$	1,275,214

Direct operating expenses:
Lease operating expense		583,942
Production taxes		138,087
Total direct operating expenses		722,029

Revenues in excess of direct operating expenses	$	553,185

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

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South Cole Creek and South Glenrock Operations

Notes to Statement of Revenues and Direct Operating Expenses

Note 1 - Basis of Presentation

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

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

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

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

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

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

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

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

Proved developed and undeveloped reserves:

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

Proved Developed		936,677
Total Proved		936,677

Standardized Measure of Discounted Future Net Cash Flows

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

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

	August 31, 2004
Future cash inflows	$	37,307,874
Future production costs		(14,681,028	)
Future development costs		-
Future net cash flows		22,626,846
10% annual discount		(12,460,123	)
Standardized measure of discounted future net cash flows	$	10,166,723

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

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

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