T-REX OIL, INC. - Annual Report: 2010 (Form 10-K)

Unassociated Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended March 31, 2010

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

For the transition period from __________ to __________

Commission file number: 000-51425

RANCHER ENERGY CORP.

(Exact name of registrant as specified in its charter)

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

999-18th Street, Suite 3400

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

(303) 629-1125

(Telephone number, including area code)

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

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

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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

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

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

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

APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY

PROCEEDINGS DURING THE PRECEDING FIVE YEARS:

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes o No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter ended September 30, 2009 was $7,755,587.

The number of shares outstanding of the registrant’s common stock as of July 12, 2010 was 119,316,720.

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS

		PAGE NO.
PART I		3

ITEM 1.	BUSINESS	4
ITEM 1A.	RISK FACTORS	10
ITEM 1B.	UNRESOLVED STAFF COMMENTS	16
ITEM 2.	PROPERTIES	16
ITEM 3.	LEGAL PROCEEDINGS	19
ITEM 4.	(REMOVED AND RESERVED)	19

PART II		19

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	19
ITEM 6.	SELECTED FINANCIAL DATA	22
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	29
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	30
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	30
ITEM 9A(T).	CONTROLS AND PROCEDURES	30
ITEM 9B.	OTHER INFORMATION	31

PART III		31

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	31
ITEM 11.	EXECUTIVE COMPENSATION	35
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	38
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	39
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	40

PART IV		40

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	40

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

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

PART I

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. These forward-looking statements 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 undertake no obligation to update forward-looking statements to reflect events or circumstances occurring after the date of this annual report on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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.

As used in this annual report on Form 10-K, unless the context otherwise requires, the terms “we,” “us,” “the Company,” “Rancher” and “Rancher Energy” refer to Rancher Energy Corp, a Nevada corporation, and its subsidiary. The statements contained in this Annual Report on Form 10-K that are not historical are “forward-looking statements," as that term is defined in Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), that involve a number of risks and uncertainties.

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

	·	business strategy;

	·	ability to raise debtor in possession financing and the terms thereof;

ability to develop a plan of reorganization acceptable to the Bankruptcy Court and to emerge from bankruptcy;

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

ability to obtain the financial resources to continue operations, to repay secured debt, to enhance current production and to conduct the EOR projects;

water availability and waterflood production targets;

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

construction of surface facilities for waterflood and CO2 operations and a CO2 pipeline;

inventories, projects, and programs;

other anticipated capital expenditures and budgets;

future cash flows and borrowings;

the availability and terms of financing;

oil reserves;

reservoir response to water and 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.

ITEM 1. BUSINESS

The Company

General

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

We operate four 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, the Cole Creek South Field and the South Glenrock A Field,. All four fields currently produce some oil and reservoir engineering studies indicate significant volumes of crude oil could be recovered through the use of secondary and tertiary recovery techniques..

Our headquarters office is located in Denver, Colorado where we employ 4 persons, including 2 executive officers, and our field office is located in Glenrock, Wyoming, where we employ 3 persons.

Incorporation, Organization and Management

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.

On September 30, 2009, at a meeting of the Company’s shareholders, the following individual were elected to replace the six standing directors: Andrei Stytsenko, Silvia Soltan, Vladimir Vaskevich, Mathijs van Houweninge, A.L. “Sid” Overton and Jeffrey B. Bennett. On October 1, 2009, the Board of Directors terminated the employment of John Works, the Company’s President, Chief Executive Officer, Chief Financial Officer, Secretary and Treasurer. On October 2, 2009 the Board of Directors appointed Jon C. Nicolaysen President and Chief Executive Officer and Mathijs van Houweninge as Secretary and Treasurer of the Company, each to serve until the Board’s next annual meeting or until their successors are appointed. On October 21, 2009, Mr. Stytsenko, Mr. Vaskevich and Ms. Soltan, resigned their positions as Directors of the Company. On October 27, 2009, Jon C. Nicolaysen was appointed to the Board of Directors.

Chapter 11 Reorganization

On October 15, 2009 a Note Payable (the “Note”) issued by the Company to GasRock Capital LLC (“GasRock” or the “Lender”) in October 2007 became due and payable. We were unable to pay the amount due of approximately $10.2 million, and we were unsuccessful in reaching agreement with GasRock to extend the term or otherwise modify the terms of the Note. On October 16, 2009 GasRock notified us of the existence of an event of default and of their intention to foreclose on the assets that secured the Note. On October 21, 2009 GasRock gave instructions the our bank to transfer all funds held in our operating account to GasRock, leaving us without funds to conduct operations, pay staff or generally operate our business. On October 28, 2009, the Company filed a voluntary petition (the “petition”) for relief in the United States Bankruptcy Court (the “Court”), District of Colorado under Chapter 11 of Title 11 of the U.S. Bankruptcy Code. (the “Bankruptcy Code”).

As a result of the Chapter 11 filing we continue to operate our business as “debtor-in-possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and the order of the Court, as we devote renewed efforts to resolve our liquidity problems and develop a reorganization plan. In November 2009 the Court approved an interim order for our Use of Cash Collateral through December 8, 2009. The interim order for continued use of cash collateral has since been extended by the Court on several occasions. As of the date of filing this annual report we continue to use cash collateral under the authority of the Court, until such time as the Court rules on our Motion to Use Cash Collateral.

Pursuant to the provisions of the Bankruptcy Code, we are not permitted to pay any claims or obligations which arose prior to the filing date (prepetition claims) unless specifically authorized by the Court. Similarly, claimants may not enforce any claims against us that arose prior to the date of the filing. In addition, as a debtor-in-possession, we have the right, subject to the Court’s approval, to assume or reject any executory contracts and unexpired leases in existence at the date of the filing. Parties having claims as a result of any such rejection may file claims with the Court which will be dealt with as part of the Chapter 11 cases.

The Bankruptcy Code gives us the exclusive right to file a plan of reorganization, originally for a period of 120 days after the petition date. We have filed a motion with the Court to extend the exclusive period through August 24, 2010, and are awaiting a decision on the motion. In March 2010, with Court authorization, we retained a financial advisor to identify potential sources of capital including strategic and industry participants and to assist us in the development of a plan of reorganization. That process is ongoing as of the date of filing of this annual report. It is our intention to address all of our prepetition claims in a plan of reorganization in our Chapter 11 cases. At this juncture, it is impossible to predict with any degree of certainty how such a plan will treat such claims and the impact our Chapter 11 cases and any reorganization plan will have on the trading market for our stock. Generally, under the provisions of the Bankruptcy Code, holders of equity interests may not participate under a plan of reorganization unless the claims of creditors are satisfied in full under the plan or unless creditors accept a reorganization plan which permits holders of equity interests to participate. If we are not successful in presenting a plan of reorganization within the prescribed time or if any such plan or reorganization is not confirmed by the court, any party in interest may file a plan of reorganization for us, which could result in the forced sale of our assets to satisfy our pre-petition obligations.

Business Strategy

Emergence From Bankruptcy

As noted above, we are evaluating various strategic alternatives in an effort to develop a plan of reorganization that will satisfy the requirements of the Court and enable us to meet our pre-petition obligations and ultimately to emerge from Bankruptcy. These alternatives include the raising of capital through the issuance of debt or equity, the sale of some or all of our assets or farming out certain interests in our oil fields in an effort to prove up additional crude oil reserves in the fields and attract capital and partners for further field development. There is no certainty that we will be successful in completing a plan of reorganization that will be confirmed by the Court, or if we do complete such a plan there is no assurance we will complete the sale of assets or the raising of capital in amounts sufficient to enable us to meet our prepetition obligations or to successfully emerge from Bankruptcy. If we are not successful in presenting a plan of reorganization within the prescribed time or if any such plan or reorganization is not confirmed by the court, any party in interest may file a plan of reorganization for us, which could result in the forced sale of our assets to satisfy our pre petition obligations.

Oil and Gas Operations

Since filing the bankruptcy petition in late October 2009 and subject to the constraints during the bankruptcy process, our new management modified the short term business strategy from focusing on the active pursuit of an enhanced oil recovery project, to a more traditional crude oil development and production strategy. Commencing in December 2009 we have carried out repair and remediation work on a number of non-productive wells, bringing them back on production and increasing daily production from the fields by approximately 50 barrels or 25% compared to the pre-petition production levels. We continue to evaluate the productive capabilities of the fields with the primary objective of identifying additional low cost projects to enhance production and a secondary objective to identify additional productive formations on our existing leasehold position. In March 2010, with Court authorization, we retained a professional geologist with extensive experience in the Powder River Basin, to conduct an evaluation and analysis of the Niobrara Shale potential for hydrocarbon production in and around our fields. That evaluation and analysis has since been completed and as of the date of filing this annual report, we are reviewing the geologist’s report and developing a strategy to ensure the potential identified in the geologist’s report is fully evaluated and exploited.

Subject to our successful emergence from bankruptcy, our longer term business strategy remains the same, to employ modern Enhanced Oil Recovery (EOR) technology to recover hydrocarbons that remain behind in mature reservoirs. 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.

To carry out this strategy, and subject to successfully emerging from the bankruptcy process, we will need to raise significant capital to drill additional producing and injection wells, to construct surface facilities and otherwise prepare the fields for CO2 injection.

In addition we will need to secure a long term reliable source of CO2. As discussed elsewhere in this annual report, in prior years we had executed two CO2 supply agreements, one with Anadarko Petroleum Corporation (Anadarko) and one with ExxonMobil Corporation (ExxonMobil). In April 2009, ExxonMobil notified us they were terminating the supply agreement based upon our failure to provide performance assurances in the form of a letter of credit. In conjunction with our bankruptcy petition, we filed a motion with the Court to reject the Anadarko supply agreement. The motion was granted by the Court in April 2010. We currently have no CO2 supply agreements and there is no assurance we will be successful in securing any such contracts.

Property Acquisitions

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

On January 4, 2007, we acquired the Big Muddy and South Glenrock A Fields, also located in the Southern Powder River Basin. The total purchase price was $25,000,000 and closing costs were $672,638.

Federal and State Regulations

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

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

Bankruptcy Proceedings

Since filing a voluntary petition for relief in the United States Bankruptcy Court on October 28, 2009, we have operated as a debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the U.S. Bankruptcy Code and orders of the Bankruptcy Court.

Regulation of Oil Exploration and Production

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

Federal Regulation of Sales Prices and Transportation

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

Federal or State Leases

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

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

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

Climate Change Legislation and Greenhouse Gas Regulation

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” or “GHGs” pursuant to the United Nations Framework Convention on Climate Change, and the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are considered “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. Additionally, the United States Supreme Court has ruled, in Massachusetts, et al. v. EPA , that the EPA abused its discretion under the Clean Air Act by refusing to regulate carbon dioxide emissions from mobile sources. As a result of the Supreme Court decision and the change in presidential administrations, on December 7, 2009, the EPA issued a finding that serves as the foundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, on September 22, 2009, the EPA also issued a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. The emissions will be published on a register to be made available on the Internet. These regulations may apply to our operations. The EPA has proposed two other rules that would regulate GHGs, one of which would regulate GHGs from stationary sources, and may affect sources in the oil and natural gas exploration and production industry and the pipeline industry. The EPA’s finding, the greenhouse gas reporting rule, and the proposed rules to regulate the emissions of greenhouse gases would result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry.

On June 26, 2009, the United States House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. On November 5, 2009 the Senate Committee on Environment and Public Works approved the “Clean Energy Jobs and American Power Act of 2009,” authored by John Kerry and Barbara Boxer, that is similar in many ways to ACESA. One of the purposes of these bills is to control and reduce emissions of greenhouse gases in the United States. These bills would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% to 20% (from 2005 levels) by 2020, and by over 80% by 2050. Under these bills, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet the overall emission reduction goals of the bills. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of these bills would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. President Obama has indicated that he is in support of the adoption of legislation such as the two bills discussed above, and the White House is expending significant efforts to push for the legislation.

Two recent court decisions, one before the United States Second Circuit Court of Appeals and one before the United States Fifth Circuit Court of Appeals (The Fifth Circuit) have allowed cases to proceed. In the first case, Connecticut v. American Electric Power , the Second Circuit ruled that several states and other plaintiffs could continue a suit to impose GHG reductions on several utility defendants, concluding that a political question and standing objections of the defendants did not prohibit the suit from going forward. The Fifth Circuit, in Comer v. Murphy Oil , ruled that plaintiffs could similarly pursue a damage suit and the political question did not prohibit the suit. This case involves claims by plaintiffs who suffered damages from Hurricane Katrina that are seeking to recover damages from certain GHG emitters asserting their emissions contributed to their increased damages. In another case filed in the Texas District Court in Austin on October 6, 2009, a citizens group sued the Texas Commission on Environmental Quality (TCEQ) asserting that the agency was required to regulate carbon dioxide emissions from parties applying for permits under the Texas Clean Air Act. The result of this lawsuit could impose additional regulations on oil and gas operations in Texas, if the Texas courts require the TCEQ to regulate carbon dioxide and perhaps other GHGs such as methane. We may be subject to the EPA GHG monitoring and reporting rule, and potentially new EPA permitting rules if adopted to apply GHG permitting obligations and emissions limitations under the federal Clean Air Act. Even if no federal greenhouse gas regulations are enacted, or if the EPA issues regulations, more than one-third of the states have begun taking action on their own to control and/or reduce emissions of greenhouse gases. Several multi-state programs have been developed or are in the process of being developed: the Regional Greenhouse Gas Initiative involving 10 Northeastern states, the Western Climate Initiative involving seven western states, and the Midwestern Greenhouse Gas Reduction Accord involving seven states. The latter two programs have several other states acting as observers and they may join one of the programs at a later date. Any of the climate change regulatory and legislative initiatives described above could have a material adverse effect on our business, financial condition, and results of operations.

Competition and Markets

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

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

Available Information

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

Glossary of Abbreviations and Terms

Anadarko		The Anadarko Petroleum Corporation.

Bcf		One billion cubic feet of natural gas at standard atmospheric conditions.

CO2		Carbon Dioxide.

ExxonMobil		ExxonMobil Gas & Power Marketing Company, a division of ExxonMobil Corporation.

EOR		Enhanced oil recovery.

Farmout		The transfer of all or part of the working interest in a property, in exchange for the transferee assuming all or part of the cost of developing the property.

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

Metalex		Metalex Resources, Inc.

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.

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

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

ITEM 1A. RISK FACTORS

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

Risks Related to our Industry, Business and Strategy

Our pending bankruptcy raise questions as to our ability to continue as a going concern and may limit our ability to borrow additional funds, issue equity or capitalize on acquisition or other business opportunities and preserve the value of our equity

On October 28, 2009, we filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Our bankruptcy filing was made after defaulting on the terms of our senior secured debt and being notified by the lender of their intention to foreclose on the assets held as collateral for the debt.

As of March 31, 2010, and as of the filing of this annual report, we continued to operate as a debtor-in-possession in the Chapter 11 case. We are in the process of developing a plan of reorganization to resolve pre-petition obligations; however, there is no assurance that any such plan of reorganization will ultimately be confirmed and become effective, nor is there any assurance that the ultimate terms of our exit from bankruptcy will preserve the rights of our existing equity holders in whole or at all. Accordingly, our equity holders continue to be subject to a risk that we will not be able to successfully emerge from bankruptcy or that rights of the equity holders will be diminished substantially or eliminated entirely.

Our continued use of cash collateral is subject to Court authorization which could be terminated by Court order.

Presently our only source of cash to pay for operating activities and overhead is proceeds from the sale of crude oil under the provisions of the Court’s interim order for use of cash collateral. Our lender has filed an objection to the continued use of cash collateral. If the Court does not extend the interim order or issue a final order for use of cash collateral our ability to continue operations would be limited to a period of 30 -45 days after which the oilfields would need to be shut in. There is no certainty that the fields could be returned to production at the same level of production, or at all, if they are shut in for an extended period of time

Our status as debtor-in-possession may adversely affect our ability to raise capital to conduct oilfield operations and our ability to find and develop reserves.

If we are unable to obtain financing on satisfactory terms, we may be unable to support our existing repair and remediation program, or to develop new reserves during the pendency of the Chapter 11 case or following exit from bankruptcy. Further, if we are unable to successfully restructure or refinance our debt in the Chapter 11 case, we may be required to liquidate some or all of our properties. In either of such events, we and our shareholders could suffer substantial impairment in the value of our holdings, including the potential complete loss of such holdings. There is no assurance that we will be able to secure financing on acceptable terms, or at all, that we will be able to restructure or refinance our existing debt on acceptable terms, or at all, or that we will be able to successfully operate during the pendency of the Chapter 11 case or following the Chapter 11 case, any of which could result in a total loss to our company and our shareholders.

If we do not develop and plan of reorganization or a plan of reorganization is not approved by the Court we could be forced to sell our assets.

If we are not successful in presenting a plan of reorganization within the prescribed time or if any such plan or reorganization is not confirmed by the court, any party in interest may file a plan of reorganization for us, which could result in the forced sale of our assets to satisfy our pre-petition obligations

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 $20,261,262 and $46,341,341 for the fiscal years ended March 31, 2010 and 2009, respectively. We do not expect to be profitable during the fiscal year ending March 31, 2011. Our development of prospects will require substantial additional capital expenditures in the future. The uncertainty and factors described throughout this section may impede our ability to economically acquire, develop, and exploit oil reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future.

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

Our short term plans are to increase crude oil production by carrying our repair and remediation efforts on existing well bores, and, if it is determined feasible, by exploiting additional formations within our existing leasehold. While we have had some success in the past six months in repairing and restoring old wells to production, there is no certainty we will continue to have such success. Furthermore, there is no certainty that we will be successful in the exploitation of additional formations or reservoirs within our existing leasehold. If we are not successful these efforts, it could have a material adverse effect on our financial condition and results of operations and cash flows.

Our long term plans to develop the properties are dependent on the construction of a CO2 pipeline and securing 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 ability to secure a reliable long term source for 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 tertiary recovery project is dependent upon sufficient amounts of CO2and will decline if our access to sufficient amounts of CO2 is limited.

Assuming we are successful in raising sufficient financing, our long-term growth strategy is focused on our CO2 tertiary recovery operations. The crude oil production from our tertiary recovery projects depends on having access to sufficient amounts of CO2. Our ability to produce this oil would be hindered if our supply of CO2 were limited due to problems with the supply, delivery, quality of the supplied CO2, problems with our facilities, including compression equipment, or catastrophic pipeline failure. We have received no CO2 to date. We do not currently have a CO2 supply agreement. If we are not successful in obtaining the required amount of CO2 to achieve crude oil production or the crude oil production in the future were to decline as a result if a decrease in delivered CO2 supply, it could have a material adverse effect on our financial condition and results of operations and cash flows.

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

The oil industry is capital intensive. We have made and are required to make substantial capital expenditures in our business and operations for the development, production, and acquisition of oil and gas reserves. To date, we have financed capital expenditures primarily with sales of our equity securities and we have financed operating activities through the issuance of short term debt. Our access to capital is subject to a number of variables, including:

our proved reserves;

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

the prices at which the oil is sold; and

our ability to acquire, locate and produce new reserves.

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

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

We operate four fields in the Powder River Basin, Wyoming. Oil in these fields was discovered over fifty years ago and production has been ongoing. Our strategy is to substantially increase production and reserves in these fields by using waterflood and CO2 EOR techniques. However, there is a risk that the properties may be significantly depleted of oil, and if so, our future results could be impacted negatively.

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

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

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

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

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

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

We may be unable to develop additional reserves.

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

We depend on key personnel, the loss of any of whom could materially adversely affect future operations.

Our success will depend to a large extent upon the efforts and abilities of our executive officers, board of directors and key operations personnel. The loss of the services of one or more of these key individuals could have a material adverse effect on us. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs, or prevent us from pursuing our exploitation strategy as quickly as we would otherwise wish to do.

Oil operations are inherently risky.

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

We are subject to extensive government regulations.

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

the prevention of waste;

the discharge of materials into the environment;

the conservation of oil;

pollution;

permits for drilling operations;

underground gas injection permits;

drilling bonds; and

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

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

Government regulation and environmental risks could increase our costs.

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

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

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

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

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

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

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

Oil prices may be impacted adversely by new taxes.

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

Shortages of equipment, supplies, personnel, and delays in construction of the CO2pipeline, construction of surface facilities, and delivery of 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, delays in the construction of the CO2 pipeline, construction of surface facilities, and delivery of CO2 could delay, restrict, or curtail our exploration and development operations, which may materially adversely affect our business, financial condition, and results of operations.

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

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

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

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

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

Risks Related to our Common Stock

We are operating as a debtor-in possession under the authorization of the US Bankruptcy Court and provisions of the U.S. Bankruptcy Code.

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, post-petition liabilities and pre-petition liabilities must be satisfied in full before shareholders of the Company are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery, if any, to shareholders of the Company will not be determined until confirmation and consummation of a plan of reorganization. No assurance can be given as to what values, if any, will be ascribed in the bankruptcy case to shareholders or what types or amounts of distributions, if any, they would receive. Accordingly, the Company urges that extreme caution be exercised with respect to existing and future investments in any of the Company's liabilities and/or securities.

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

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

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

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

Actual or anticipated quarterly variations in our operating results;

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

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

Conditions generally affecting the oil and gas industry;

The success of our operating strategy; and

The operating and stock performance of other comparable companies.

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

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

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

· discuss our future expectations;

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

· state other “forward-looking” information.

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

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

In our annual reports on Form 10-K for the fiscal years ended March 31, 2010 and 2009, we reported the determination of our management that we had a material weakness in our internal control over financial reporting. The determination was made by management that we did not adequately segregate duties of different personnel in our accounting department due to an insufficient complement of staff and inadequate management oversight. While we have made progress in remediating the weakness, we have not completely remediated it, primarily due to limited resources to add experienced staff. Until we obtain sufficient financing we will not be able to correct the material weakness in our internal control over financial reporting, and our business could be harmed and the stock price of our common stock could be adversely affected.

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

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Field Summaries

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

South Glenrock B Field

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

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

The South Glenrock B Field is an active waterflood that currently produces approximately 128 BOPD of sweet 35 degree API crude oil. There are 14 active producing wells and 13 injector wells servicing the field. This waterflood unit was developed with a fairly regular 40 acre well spacing and drilled with modern rotary equipment.

In February 2010 we engaged a geologist to conduct an evaluation and analysis of Niobrara Shale potential for hydrocarbon production in the South Glenrock B Field. The results of that evaluation and analysis are currently under review by management and, if appropriate, will be incorporated into our plan of reorganization.

Subject to obtaining financing, and securing a CO2 supply, 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.

Big Muddy Field

The Big Muddy Field is located 17 miles east of Casper, in Converse County, Wyoming. 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 38 BOPD of 36 degree API sweet crude oil, from five producing wells with two water injection wells servicing the field. 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.

In February 2010 we engaged a geologist to conduct an evaluation and analysis of Niobrara Shale potential for hydrocarbon production in the Big Muddy Field. The results of that evaluation and analysis are currently under review by management and, if appropriate, will be incorporated into our plan of reorganization.

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 required unitization prior to a waterflood or a CO2 flood. The State of Wyoming required us to form two separate units, one for the Wall Creek/2nd Frontier formation and one for the Dakota formation, due to the different sizes of the productive horizons. The unitization 2nd Frontier was completed in calendar year 2008 and subject to obtaining financing and securing a CO2 supply; we would start CO2 injection in the Big Muddy Field within one to two years after commencing CO2 injection in the South Glenrock B Field.

Cole Creek South Field

The Cole Creek South Field, also in the 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 73 BOPD of 34 degree API sweet crude oil from 10 producing wells. There are 9 active injector wells in the field. Production is from the Dakota, Lakota and First and Second Frontier formations.

In February 2010 we engaged a geologist to conduct an evaluation and analysis of Niobrara Shale potential for hydrocarbon production in the Cole Creek South Field. The results of that evaluation and analysis are currently under review by management and, if appropriate, will be incorporated into our plan of reorganization.

The Cole Creek South Field is presently at reservoir pressure sufficient for miscible CO2 flooding and the wells are generally 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 would be the third field to undergo CO2 flooding. Subject to obtaining financing and securing a CO2 supply, we would start CO2 injection in the Cole Creek South Field in within four to five years after commencing CO2 injection in the South Glenrock B Field.

South Glenrock A Field

The South Glenrock A Field, also located in Converse County Wyoming about 18 miles east of Casper, produces approximately 26 BOPD from 2 wells in the Muddy, Dakota and Shannon formations. Due to the relatively small reservoir, this field is not included in our plans for CO2 flooding. Sinclair Oil & Gas Company was the initial Operator and started waterflooding activities late 1966.

In February 2010 we engaged a geologist to conduct an evaluation and analysis of Niobrara Shale potential for hydrocarbon production in the South Glenrock A Field. The results of that evaluation and analysis are currently under review by management and, if appropriate, will be incorporated into our plan of reorganization

The following table summarizes reserves, ownership interests and daily production of our properties as of March 31, 2010:

Field	Proved Reserves (Barrels) (A)		Proved Developed Producing %			PV – 10 ($000) (A)		Net Revenue Interest			Daily Production (Bbls) - Gross		Daily Production (Bbls) - Net
South Glenrock B		399,302		100	%	$	3,832		73.4% - 77.7	%		128		96
Big Muddy		40,229		100	%		579		77.9	%		38		30
Cole Creek South		344,442		90	%		4.321		75% - 78.3	%		73		56
South Glenrock A		67,206		100	%		1,018		75% - 77.6	%		26		20
TOTAL		851,179		-		$	9,750					265		202

(A)

Proved reserve volumes and PV – 10 based upon SEC reserve parameters. See further discussion in Note 12 -Disclosures About Oil and Gas Producing Activities in Part IV of this annual report.

The following table summarizes acreage holdings and well counts as or March 3, 2010:

	Developed Acres				Undeveloped Acres				Total Acres				Producing Well Count
Field	Gross		Net		Gross		Net		Gross		Net		Gross		Net
South Glenrock B		10,873		10,177		-		-		10,873		10,177		14		13.2
Big Muddy		522		522		8,435		7,755		8,957		8,277		5		5
Cole Creek South		3,782		3,782		-		-		3,782		3,782		10		10
South Glenrock A		1,283		1,283		-		-		1,283		1,283		2		2
TOTAL		16,460		15,764		8,435		7,755		24,895		23,519		31		30.2

Production

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

	For the Year Ended March 31,
	2010		2009

Net oil sales (barrels)		56,818		65,308
Average realized oil sales price per barrel	$	63.11	$	78.71
Production costs per barrel:
Production taxes	$	10.10	$	9.92
Lease operating expenses	$	30.33	$	37.10

Title to Properties

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

Environmental Assessments

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

Geographic Segments

All of our operations are in the continental United States.

Significant Oil and Gas Purchasers and Product Marketing

Due to the close proximity of our fields to one another, oil production from our 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 due to the ready availability of other purchasers in the area. 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 $2.12 to $2.35 per barrel.

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

ITEM 3. LEGAL PROCEEDINGS

On October 28, 2009, the Company filed a voluntary petition (the “petition”) for relief in the United States Bankruptcy Court (the “Court”), District of Colorado under Chapter 11 of Title 11 of the U.S. Bankruptcy Code. (the “Bankruptcy Code”). The Bankruptcy proceedings are discussed in further detail in Item 1 of this filing.

On February 12, 2010, the Company filed an adversary proceeding in the Bankruptcy Court against GasRock Capital LLC, Case No. 10-01173-MER. The complaint seeks to recover the 10% NPI conveyed to GasRock in connection with the Eighth Amendment to the Term Credit Agreement and the additional 1% ORRI conveyed to the Lender in October 2008 in connection with an extension of the short term note. The primary basis of the complaint is that the Lender gave less than fair equivalent value for the conveyances at a time when the Company was insolvent, or when the conveyances left the Company with insufficient capital. In other words, the Company has claimed that the value of the conveyances was in excess of a reasonable fee for the extensions, and, as a result, the conveyances were "constructively fraudulent" under both applicable Bankruptcy law and the Uniform Fraudulent Transfers Act. In addition, the Company has challenged the conveyance of the NPI and the 1% ORRI, together with the original 2% ORRI conveyed to Lender when its loan was first made, on the grounds that they should be recharacterized as security interests and not outright transfers of title. The Company has also claimed that the conveyances rendered the Loan usurious under Texas law. Further, the Company has sought to have the NPI and 1% ORRI avoided as preferences under ss. 547 of the Bankruptcy Code and to equitably subordinate the Lender's claim. Although the Company believes its claims are well-taken, the Company expects the Lender to vigorously defend against the complaint, and no assurance can be given that the Company will be successful in whole or in part.

In a letter dated February 18, 2009 sent to each of our Directors, attorneys representing a group of persons who purchased approximately $1,800,000 of securities (in the aggregate) in our private placement offering commenced in late 2006 alleged that securities laws were violated in that offering. In April 2009, we entered into tolling agreements with the purchasers to toll the statutes of limitations applicable to any claims related to the private placement. In February 2009, our Board of Directors established a Special Committee of the Board (the “Special Committee”) to investigate the allegations. Following the completion of the investigation, the Special Committee recommended no action be taken. We deny the allegations and believe they are without merit. We cannot predict the likelihood of a lawsuit being filed, its possible outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in any such lawsuit. The claimants have filed a Proof of Claim with the Bankruptcy Court in the amount of $2,001,050 purported to be damages attributable to the alleged securities violations.

ITEM 4. (REMOVED AND RESERVED.)

PART II

ITEM 5.

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

Our Common Stock has been quoted on the OTC Bulletin Board under the symbol “RNCH” since January 10, 2006. As a result of our filing for protection under the U.S. Bankruptcy Code, our stock has been trading under the symbol “RNCHQ” since October 28, 2009For 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 2010	High Bid		Low Bid
First Quarter	$	0.044	$	0.012
Second Quarter	$	0.065	$	0.023
Third Quarter	$	0.09	$	0.01
Fourth Quarter	$	0.04	$	0.006
Fiscal Year 2009
First Quarter	$	0.53	$	0.31
Second Quarter	$	0.30	$	0.11
Third Quarter	$	0.16	$	0.02
Fourth Quarter	$	0.04	$	0.02

Holders

As of March 31, 20010, there were approximately 190 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 former President, Chief Executive Officer, and a member of our Board of Directors, an option to purchase 4,000,000 shares of our common stock at a price of $0.00001 per share. These options vested over time through May 31, 2009. The table that follows summarizes the exercise of Mr. Works’ options during the year ended March 31, 2010:

Exercise Date	Number of Options Exercised		Exercise Price		Aggregate Purchase Price
May 12, 2009		250,000	$	0.00001	$	2.50
May 31, 2009		250,000	$	0.00001	$	2.50

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

On October 27, 2009, under the provisions Management Retention Agreements with each of our four directors, we granted each director an option to purchase 2,500,000 shares of our common stock at a price of $0.035 per share. These options vest 10% on the date of grant and 90% upon the earliest to occur of the following:

November 1, 2010;

the confirmation by the Bankruptcy Court of a plan of reorganization;

the dismissal from Chapter 11 Bankruptcy with the approval of the Court;

an event of a merger, consolidation, sale of assets or other transaction which results in the holders of the Company’s common stock immediately before such transaction owning less that 50% of the stock outstanding immediately after the transaction;

any other forms of change of control;

a voluntary termination for good reason.

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

Pursuant to our 2006 Stock Incentive Plan (the 2006 Stock Incentive Plan), we granted options to purchase shares of common stock to officers employees, directors and consultants. Options outstanding as of March 31, 2010 are summarized below:

Date

Granted To

Number of

Options

Exercise

Price

Vesting

Term

April 10, 2007

Employees

31,000

1.18

33.3% on 1st , 2nd and 3rd anniversaries of grant

“

April 10, 2007

Consultant

25,000

1.64

50% at 8/31/07 and 50% at 2/29/08

“

August 27, 2007

Officer

450,000

0.45

33.3% on 1st, 2nd and 3rd anniversaries of grant

5 years

October 27, 2009

Employees

700,000

0.035

10% at date of grant, 90 % upon the earliest of November 1, 2010 or change of control or emergence from bankruptcy

5years

October 27, 2009

Consultant

1,000,000

0.035

10% at date of grant, 90 % upon the earliest of November 1, 2010, emergence from bankruptcy, of change of control

5years

The options granted to officers and employees are subject to early termination of the individual’s employment with us. The foregoing transactions were made pursuant to Section 4(2) of the Securities Act. As of March 31, 2010, 7,794,000 options remain available for issuance under the 2006 Stock Incentive Plan.

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 and gas properties a warrant to purchase up to 250,000 shares of our common stock at an exercise price of $1.50 per share. The seller may exercise the warrant at any time beginning June 22, 2007 and ending December 22, 2011. The foregoing transaction was made pursuant to Section 4(2) of the Securities Act.

On April 20, 2007, our Board of Directors appointed William A. Anderson, Joseph P. McCoy, Patrick M. Murray, and Myron M. Sheinfeld as members of the Board to serve until the next annual meeting of stockholders or their successors are duly elected and qualified. We had no special arrangements, related party transactions or understandings with the foregoing appointed directors in connection with their appointment to the Board, except for compensation arrangements. On April 20, 2007, each newly appointed director was granted an option to purchase 10,000 shares of our common stock pursuant to our 2006 Stock Incentive Plan, as summarized in the table above. Each newly appointed director will be entitled to receive annual grants of options to purchase 10,000 shares that will be priced at the future grant dates. Each newly appointed director also received a stock grant of 100,000 shares of our common stock that vests 20% (20,000 shares) on the date of grant with vesting 20% per year thereafter. The foregoing transactions were made pursuant to Section 4(2) of the Securities Act. At a meeting of shareholders on September 30, 2009, the Board of Directors was not retained. A total of 200,000 shares that were not vested were cancelled as of that date.

Under the terms of the registration rights agreement, we were obligated to pay the holders of the registrable securities issued in December 21, 2006 private placement liquidated damages if the registration statement filed in conjunction with the private placement was not declared effective by the SEC within 150 days of the closing of the private placement and every 30 days thereafter until the registration statement is declared effective. The closing occurred on December 21, 2006. The amount due on each applicable date is 1% of the aggregate purchase price or $794,000. Pursuant to the terms of the registration rights agreement, the number of shares issued on each payment date is based on the payment amount of $794,000 divided by an amount that equals 90% of the volume weighted average price of our common stock for the 10 days immediately preceding the payment date. The table below summarize the shares issued pursuant to the terms of the registration rights agreement:

Payment Date	90% of Volume Weighted Average Price for 10 Days Preceding Payment		Shares Issued		Closing Price at Payment Date		Value of Shares Issued
May 18, 2007	$	0.85		933,458	$	1.04	$	970,797
June 19, 2007	$	0.84		946,819	$	0.88	$	833,201
July 19, 2007	$	0.60		1,321,799	$	0.66	$	872,387
August 17, 2007	$	0.45		1,757,212	$	0.41	$	720,457
September 17, 2007	$	0.32		2,467,484	$	0.34	$	838,945
October 17, 2007	$	0.55		1,443,712	$	0.57	$	822,915
October 31, 2007	$	0.43		861,085	$	0.47	$	404,710
				9,731,569			$	5,463,412

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

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

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

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

Date of Issue	Number of Shares Issued			Fair Market Value Per Share at Issue Date

Jun 30, 2007		101,713		$	.0.73
Sep 30, 2007		181,098		$	0.41
Dec 31, 2007		275,001		$	0.27
Mar 31, 2008		190,.385		$	0.39
Jun 30, 2008		239,514		$	0.31
Sep 30, 2008		495,000		$	0.15
Dec 31, 2008		2,653,845		$	0.026
Mar 31, 2009		0	*	$	N/A
Jun 30, 2009		0	*	$	N/A
Sep 30, 2009		0	*	$	N/A

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

*All of the non-employee directors elected to forego stock compensation for the quarters ended March 31, June 30 and September 2009. The practice of granting stock in lieu of cash for service on the Board of Directors was terminated in October 2009.

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

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

Organization

We are an independent energy company that explores for and develops, produces, and markets oil and gas in North America. We were known as Metalex Resources, Inc. until April 2006 when our name was changed to Rancher Energy Corp. We operate four oil fields in the Powder River Basin, Wyoming. Since October 28, 2009 we have been operating as debtor-in-possession under Chapter 11 of the U.S. Bankruptcy Code. See “Proceedings Under Chapter 11” below.

Proceedings Under Chapter 11

We acquired our oilfields in late 2006 and early 2007 with the intention of significantly increasing crude oil production through an enhanced oil recovery (EOR) project utilizing modern CO2 injection techniques. The planned EOR project required a significant amount of capital to carry out. In October 2007 we borrowed $12.24 million from GasRock Capital LLC (GasRock), an investment bank, to serve as a “bridge loan” to enable us to complete plans for the EOR project while we sought a larger, longer-term source of capital to conduct the project. At least partially due to the severe disruptions in credit and financial markets, coupled with extreme volatility in crude oil prices in the period, we were not successful in raising the capital to repay the bridge loan and commence the project. Following a series of amendments to the GasRock loan agreement and extensions of the maturity date, we were unable to repay the loan on the amended due date of October 15, 2009. On October 16, 2009 GasRock notified us the failure to repay the loan constituted an event of default and notified us of their intention to foreclose on the assets pledged as collateral for the loan. GasRock instructed our bank to transfer all cash we had on deposit to GasRock, leaving us without funds to operate the oilfields or pay overhead.

On October 28, 2009, we filed a voluntary petition for relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Colorado (the “Court”) (Case number 09-32943) We continue to operate our business as “debtor-in-possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and the order of the Court, as we devote renewed efforts to resolve our liquidity problems and develop a reorganization plan.

In November 2009, the Court granted our motion for interim use of cash collateral. We immediately took steps to reduce operating costs and overhead, including salary cuts of 10% - 20% for employees and the rejection of the office lease for our corporate headquarters. In addition we carried out a program of repair and remediation on a number wells that had become non-producing , resulting in a 25% increase in daily crude oil production as compared to pre-petition production levels.

With the Court’s consent, we have engaged professionals and consultants including an engineering consultant to conduct a market valuation of our oil and gas properties; a geologist to conduct an evaluation and analysis of Niobrara Shale potential for hydrocarbon production in our oilfields and a financial advisor to assist us in the development of a plan of reorganization. We have filed a motion with the Court to extend the exclusive period through August 24, 2010, and are awaiting a decision on the motion. We intend to file a plan of reorganization prior to the expiration of the exclusivity period,

On February 12, 2010, the Company filed an adversary proceeding in the Bankruptcy Court against GasRock. The complaint seeks to avoid the interest of GasRock in the 10% NPI conveyed to GasRock in connection with the Eighth Amendment to the Term Credit Agreement and the additional 1% ORRI conveyed to the Lender in October 2008 in connection with an extension of the short term note. The primary basis of the complaint is that the Lender gave less than fair equivalent value for the conveyances at a time when the Company was insolvent, or when the conveyances left the Company with insufficient capital. In other words, the Company has claimed that the value of the conveyances was in excess of a reasonable fee for the extensions, and, as a result, the conveyances were "constructively fraudulent" under both applicable Bankruptcy law and the Uniform Fraudulent Transfers Act. In addition, the Company has challenged the conveyance of the NPI and the 1% ORRI, together with the original 2% ORRI conveyed to Lender when its loan was first made, on the grounds that they should be recharacterized as security interests and not outright transfers of title. The Company has also claimed that the conveyances rendered the Loan usurious under Texas law. Further, the Company has sought to have the NPI and 1% ORRI avoided as preferences under ss. 547 of the Bankruptcy Code and to equitably subordinate the Lender's claim. Although the Company believes its claims are well-taken, the Company expects the Lender to vigorously defend against the complaint, and no assurance can be given that the Company will be successful in whole or in part.

Results of Operations

Rancher Energy Corp.

Results of Operations

Years Ended March 31,

	2010			2009
Revenue:
Oil production (in barrels)		56,818			65,308
Oil price (per barrel)	$	63.11		$	78.71

Oil and gas sales	$	3,585,738		$	5,140,660
Derivative gains (losses)		(357,582	)		1,020,672	)
		3,228,156			6,161,332

Operating expenses:
Production taxes		573,992			647,755
Lease operating expenses		1,723,015			2,423,015
Depreciation, depletion, and amortization		1,178,986			1,196,970
Impairment of unproved properties		13,525,642			39,050,000
Accretion expense		167,896			158,009
Exploration expense		19,181			20,108
General and administrative		2,490,453			3,631,580
Total operating expenses		19,679,165			47,127,437

Loss from operations		(16,451,009	)		(40,966,105	)

Other income (expense):
Interest expense		(1,732,360	)		(1,369,957	)
Amortization of deferred financing costs		(1,770,789	)		(4,021,767	)
Interest and other income		3,487			16,488
Total other income (expense)		(3,499,662	)		(5,375,236	)

Loss before reorganization items		(19,950,671	)		46,341,341

Reorganization items
Professional and legal fees		310,591			—

Net loss	$	(20,261,262	)	$	(46,341,341	)

Year Ended March 31, 2010 Compared to Year Ended March 31, 2009

Overview. For the year ended March 31, 2010, we reported a net loss of $20,261,262, or $0.17 per basic and fully-diluted share, compared to a net loss of $46,341,341 or $0.40 per basic and fully-diluted share, for year ended March 31, 2009. Discussions of individually significant period to period variances follow.

Revenue, production taxes, and lease operating expenses. For the year ended March 31, 2010, we recorded crude oil sales of $3,585,738 on 56,818 barrels of oil at an average price of $63.11, as compared to revenues of $5,140,660 on 65,308 barrels of oil at an average price of $78.71 per barrel in 2009. The year-to-year variance reflects a volume variance of $(668,283) and a price variance of $(886,639). The decreased volume in 2010 reflects the loss of several producing wells due to mechanical problems in early 2010, coupled with routine production decline from year to year. Following the bankruptcy filing and after reaching agreement with our secured lender for the use of cash collateral we have begun efforts to stop the production decline by repairing wells and surface facilities that had been offline due to lack of available capital. Production taxes (including ad valorem and property taxes) were $573,992 (16% of crude oil sales revenue) in 2010 as compared to $647,755 (12.6% of crude oil sales revenue) in 2009. The increase as a percentage of crude oil sales revenue reflects additional accruals for ad valorem taxes reflecting higher mil levy rates. Lease operating expenses decreased to $1,723,015 ($30.33/bbl) in 2010 as compared to $2,423,015 ($37.10/bbl) in 2009. The year to year variance reflects a volume variance of $314,990 and a cost variance of $385,010. The per barrel decrease in 2010 compared to 2009 reflects costs saving efforts undertaken to preserve capital, coupled with a lack of significant well or surface facility repair work for most of the 2010 period as compared to the 2009 period. As mentioned above, late in the current period we have begun a program to repair wells and surface facilities to increase production. These efforts will likely result in higher operating expenses in future periods.

Derivative losses. In connection with short term debt financing entered into in October 2007, we entered into a crude oil derivative contract with an unrelated counterparty to set a price floor of $63 per barrel for 75% of our estimated crude oil production for the next two years, and a price ceiling of $83.50 for 45% of the same level of production. During the year ended March 31, 2010 we recorded total losses on the derivative activities of $357,582 compared to gains of $1,020,670 in 2009. The 2010 losses were comprised of $98,378 of realized gains and $455,960 of unrealized losses, compared to $206,895 of realized losses and $1,227,567 of unrealized gains in 2009.

Depreciation, depletion, amortization. For the year ended March 31, 2010, we reflected total depreciation, depletion, amortization and accretion of $1,346,881 comprised of $988,603 ($17.40/bbl) related to oil and gas properties, $190,382 related to other assets and accretion of asset retirement obligation of $167,896. The comparable amounts for the 2009 period were $1,354,979 comprised of $1,009,359 ($15.46/bbl), related to oil and gas properties, $187,610 related to other assets, and accretion of asset retirement obligation of $158,009. The increase in per barrel DD&A reflects decreases in the crude oil reserve base used to calculate such DD&A in 2010 compared to 2009.

Impairment of unproved properties. In consideration of the global credit crisis, volatile commodity prices and reflecting the lack of success in securing financing to conduct our CO2 enhanced oil recovery projects, we determined during the year ended March 31, 2010 to recognize full impairment of the carrying value of our unproved properties in an amount of approximately $13,525,000. This decision reflects management’s current plans to gradually increase and stabilize production from existing wells and facilities before commencing the more comprehensive CO2 projects. In the year ended March 31, 2009 we recognized a partial impairment of unproved properties in the amount of $39,300,000.

Reorganization items. The $310,591 of costs reflected as reorganization items in the year ended March 31, 2010, include those items of expense specifically related to our reorganization following the filing of a voluntary petition for relief under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court on October 28, 2009. These costs consist primarily of professional fees to legal counsel for representation before the Bankruptcy Court, financial advisor fees for assistance in the development of a reorganization plan and engineering and geological consulting fees. We expect these expenses to continue to be significant as we progress through the bankruptcy process.

General and administrative expense. For the year ended March 31, 2010 we reflected general and administrative expenses of $2,490,453 as compared to $3,631,581 for the corresponding year ended March 31, 2009. Significant components of the 2010-2009 year-to-year variance include:

	Year ended March 31,
Expense Category	2010			2009			Discussion
Salaries, payroll taxes and benefits	$	1,033,939		$	1,329,030		Decrease reflects staff cuts (4 full time employees in corporate office vs. 7 in prior year) coupled with salary cuts following election of new board and filing of bankruptcy proceedings.
Consultants		136,010			355,614		Decrease reflects lower usage of consulting staff including: accounting $96K; land $13K and financial advisors $95K
Travel & entertainment		29,826			91,747		Decrease reflects cost cutting measures enacted late in fiscal 2009
IT		75,692			105,125		Decrease reflects reduced need for IT services due to lower staff count and cost cutting measures enacted by management
Legal fees		406,767			386,476		Increase reflects costs associated with renegotiation of senior secured debt (7 amendments), proxy preparation, issues surrounding annual meeting and proxy battle, plus debtor counseling fees incurred prior to filing of bankruptcy
Audit, SOX and tax compliance		118,244			220,334		Decrease reflects efficiencies achieved in audit and quarterly review process based upon experience gained in first three years of the process
Investor relations, shareholders meeting		19,197			75,678		Decrease reflects termination of contract with outside investor relations professional in the middle of FY 2009, partially offset by cost of proxy preparation and annual meeting in 2010.
Office rent, communication & other office expenses		456,807			503,958		Office rent expense remained stable in 2020 vs. 2010 at $365K. Other office expenses reflect decrease due to lower staff count and reduced level of activity.
Insurance		168,865			157,228		Slight increase reflects increase cost of Director and Officer insurance premium in 2010 vs. 2009.
Stock based compensation		338,873			574,353		Decreased stock based compensation reflects expenses associated with former CEO options that were fully vested in mid year of 2010 plus, ($212K) plus expense associated with stock options to terminated directors and employees not recognized in 2010.
Director fees		179,500			321,250		Decrease reflects half year effect of revised compensation scheme following election of new board. Current fees are paid at rate of $5K/quarter for each of 3 non-executive directors compared with prior fee base approximately $15K /quarter for 5 non-executive directors.
Field overhead recoveries		(473,266	)		(489,213	)	Slightly lower field overhead recoveries reflect lower producing well count in 2010 vs. 2009.
TOTAL G&A	$	2,490,453		$	3,631,580

Interest expense and financing costs. For the year ended March 31, 2010, we reflected interest expense and financing costs of $3,503,150 as compared to $5,391,725 for the year ended March 31, 2009. The 2010 amount is comprised of interest paid on the Note Payable issued in October 2007, as amended, of $1,702,719, interest penalty on non-timely filed Wyoming severance and ad valorem taxes of $29,641, and amortization of deferred financing costs and discount on Note Payable of $1,770,789. Comparable amounts for the 2009 period were $1,369,733 of interest on the Note Payable and $4,021,991 of deferred finance discount amortization. The higher interest on Note Payable reflects a 4% increase in the interest rate occurring as part of the amendment to the Term Credit Agreement in June 2009, plus the effect of an additional 2% increase reflecting the default rate after October 15, 2009.

Liquidity and Capital Resources

The report of our independent registered public accounting firm on the financial statements for the years ended March 31, 2010 and 2009 includes an explanatory paragraph relating to the uncertainty of our ability to continue as a going concern. We have incurred a cumulative net loss of $89 million for the period from inception (February 4, 2004) to March 31, 2010, have a working capital deficit of $11 million and have defaulted on our senior secured debt.

On October 15, 2009, short term debt in the amount of approximately $10.2 million matured. We were unable to repay the short term debt, which constituted an Event of Default under the terms of the Term Credit Agreement. On October 16, 2009 we received notice of the Event of Default from the Lender, GasRock Capital LLC (GasRock), and notice of their intent to foreclose on the properties securing the debt. On October 21, 2009 GasRock swept the remaining $98,000 from our operating bank account, leaving us without the ability to meet operating expense obligations, or pay staff or other administrative expenses.

On October 27, 2009 we raised $140,000 in cash through the issuance of convertible promissory notes to certain of our officers, directors and shareholders and used the funds to retain counsel to provide debtor advice and to provide working capital. See Note 7 - Convertible Promissory Notes Payable in the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2010 in Part IV, Item 15, of this Annual Report.

On October 28, 2009 we filed a voluntary petition for relief in the United States Bankruptcy Court, District of Colorado under Chapter 11 of Title 11 of the U.S. Bankruptcy Code. (the “Bankruptcy Court”). We have reached agreement with GasRock and the Bankruptcy Court has approved an order for limited use of cash collateral. Under the terms of the order we receive the proceeds from crude oil sales from our fields and are able to pay operating, and administrative costs in accordance with the approved cash collateral budget. This arrangement has enabled us to meet all allowable operating and administrative obligations and to build an operating cash reserve totaling $372,000 as of March 31, 2010, increasing to $480,000 as of June 20, 2010.

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

We believe that our cash flows from operations and cash on hand are sufficient to support our liquidity needs during the pendency of our bankruptcy. We do not, however, believe that our cash flows from operations and cash on hand will be adequate to fully satisfy our pre petition obligations or to pursue drilling and development activities. We are reviewing strategic alternatives for raising sufficient capital to support our plan of reorganization, including the issuance of debt, the sale of some or all of our assets or the sale of equity; however at the present time we have no commitments to provide additional capital or financing and, given the current condition of the capital and credit markets, there is no assurance that any such capital or financing will be available on acceptable terms, or at all.

Cash Flows

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

	For the Year Ended March 31,
	2010			2009
Cash flows from (used for)::
Operating activities, including reorganization items of $110,154 in 2010	$	(562,009	)	$	(2,964,942	)
Investing activities	$	(24,745	)	$	(618,791	)
Financing activities	$	41,880		$	(2,341,470	)

Analysis of cash flow changes between 2009 and 2008

Cash flows used for operating activities decreased in 2010 as a result of lower general and administrative expenses as discussed above, the capitalization of a portion of interest expense under the terms of the amended Term Credit Agreement with our senior secured lender, and realized gains on derivative activity as compared to realized losses in 2009 .

Cash flows used for investing activities decreased in the 2009 period compared to the 2008 period as we expended significantly less on oil and gas properties, $33,000 in 2010 compared to $260,000 in 2009. In response to our lack of success in securing additional financing during the period, we have curtailed capital spending to the minimum required to maintain current levels of crude oil production.

Cash flows from financing activities in 2010 reflects the proceeds from the sale of convertible notes payable ($140,000 off set by the repayment of a portion of the debt incurred in 2007 ($98,000). Cash flows used for financing activities in 2009 includes the repayment of a portion of the debt incurred in 2007 ($2,240,000) and payments of deferred financing costs to complete requirements of the short term debt agreement.

Capital Expenditures

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

	For the Years Ended March 31,
	2010			2009

Exploration	$	19,181		$	20,108
Development		82,963			245,102
Acquisitions:
Unproved		-			-
Proved		-			-
Total	$	102,144		$	265,280

Capitalized costs associates with asset retirement obligations.	$	(18,747	)	$	10,481

Off-Balance Sheet Arrangements

Under the terms of the Term Credit Agreement entered into in October 2007 we were required hedge a portion of our expected production and we entered into a costless collar agreement for a portion of our anticipated future crude oil production. The costless collar contains a fixed floor price (put) and ceiling price (call). If the index price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. During the year ended March 31, 2009 we reflected realized gains of $98,377 and unrealized losses of $455,960 from the hedging activity, as compared to realized losses of $206,895 and unrealized gains of $1,227,567 for the comparable 2009 period.

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

Critical Accounting Policies and Estimates

We are engaged in the exploration, exploitation, development, acquisition, and production of natural gas and crude oil. Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our decisions, which affect the estimates we use, on historical experience and various other sources that are believed to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changing business conditions or unexpected circumstances. Policies we believe are critical to understanding our business operations and results of operations are detailed below. For additional information on our significant accounting policies see Note 1—Organization and Summary of Significant Accounting Policies, Note 3—Asset Retirement Obligations, and Note 9—Disclosures About Oil and Gas Producing Activities in the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2010 in Part IV, Item 15, of this Annual Report.

Oil and Gas reserve quantities. Estimated reserve quantities and the related estimates of future net cash flows are the most important estimates for an exploration and production company because they affect our perceived value, are used in comparative financial analysis ratios and are used as the basis for the most significant accounting estimates in our financial statements. This includes the periodic calculations of depletion, depreciation, and impairment for our proved oil and gas assets. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Future cash inflows and future production and development costs are determined by applying average beginning of month prices and benchmark costs, including transportation, quality, and basis differentials to the estimated quantities of oil and gas remaining to be produced as of the end of that period. Expected cash flows are reduced to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculation required by Financial Accounting Standards Board Accounting Standards Codification (FASB ASC) 932, “Disclosures About Oil and Gas Producing Activities," requires a 10% discount rate to be applied. Although reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves, which are prepared by independent reserve engineering consultants. We expect that periodic reserve estimates will change in the future as additional information becomes available or as oil and gas prices and operating and capital costs change. We evaluate and estimate our oil and gas reserves at March 31 of each year. For purposes of depletion, depreciation, and impairment, reserve quantities are adjusted at all interim periods for the estimated impact of additions and dispositions. Changes in depletion, depreciation, or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period that the reserve estimates change.

Successful efforts method of accounting. Generally accepted accounting principles provide for two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method. Both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities and a detailed description is included in Note 1– Organization and Summary of Significant Accounting Policies to the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2009 in Part IV, Item 15, of this Annual Report.

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

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

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

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 FASB ASC 740 “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 FASB ASC 718, “Share- Based Payments." This statement requires us to record expense associated with the fair value of stock-based compensation.

Commodity Derivatives. The Company accounts for derivative instruments or hedging activities under the provisions of FASB ASC 815, “Derivative and Hedging." FASB ASC 815 requires the Company to record derivative instruments at their fair value. The Company’s risk management strategy is to enter into commodity derivatives that set “price floors” and “price ceilings” for its crude oil production. The objective is to reduce the Company’s exposure to commodity price risk associated with expected crude oil production.

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

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

ITEM 9A(T). CONTROLS AND PROCEDURES

Controls and Procedures.

We conducted an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Accounting Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures also include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. We identified a material weakness in our internal control over financial reporting and, as a result of this material weakness, we concluded as of March 31, 2010 that our disclosure controls and procedures were not effective.

Management’s Annual Report on Internal Control Over Financial Reporting

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

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

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

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

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

Management assessed the effectiveness of the Company’s internal control over financial reporting as of March 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.

A material weakness is a control deficiency, or combination of control deficiencies, that result in more than a remote likelihood that a material misstatement of annual or interim financial statements will not be prevented or detected. As of March 31, 2010, the Company identified the following material weakness:

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

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

As a result of the aforementioned material weakness, management concluded that the Company’s internal control over financial reporting as of March 31, 2010 was not effective.

Management’s Planned Corrective Actions

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

Engage qualified accounting staff to prepare journal entries and note disclosures thereby enabling our Chief Accounting Officer the opportunity to independently review and authorize such entries and disclosures prior to entering the information into the accounts and financial statement disclosures,

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

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

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

Auditors Attestation

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

Changes in Internal Control over Financial Reporting

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

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Our current directors and executive officers, their respective positions and ages, and the year in which each director was first elected, are set forth in the following table.

Name	Age	Positions Held	Beginning of Term of Service
Jon C. Nicolaysen	63	Director, President, Chief Executive Officer	President and CEO Oct 2, 2009; Director Oct 27, 2009;
A.L. Sid Overton	69	Director, Chairman of the Board	Sep 30, 2009
Mathijs van Houweninge	44	Director	Sep 30, 2009
Jeffrey B. Bennett	55	Director	Sep 30, 2009
Richard Kurtenbach	55	Chief Accounting Officer	August 27, 2007

Rancher’s directors hold office until their successors are duly elected and qualified under Rancher’s bylaws. The directors named above will serve until the next annual meeting of Rancher’s stockholders. Thereafter, directors will be elected for one-year terms at the annual stockholders' meeting. Officers will hold their positions at the pleasure of the board of directors absent any employment agreement.

Prior to October 1, 2009 the following individuals served as officers and directors of the Company.

Name	Age	Positions Held	Date of Termination of Service
John Works	55	Director, President, Chief Executive Officer	Director Sept 30, 2009; President and CEO Oct 2, 2009;
William A. Anderson	69	Director	Sep 30, 2009
Joseph P McCoy	57	Director	Sep 30, 2009
Patrick M. Murray	65	Director	Sep 30, 2009
Myron (Mickey) M. Sheinfeld	78	Director	Sep 30, 2009
Mark Worthey	50	Director	Sep 30, 2009

Biographical Information

Jon Nicolaysen , President, CEO and Director

In 1985, Mr. Nicolaysen completed the Atlantic Businessman's Exchange Program. In 1986, he completed the W.K. Kellogg Foundations Fellowship Wyoming Agriculture Leadership Program. In 1970, he received an MS in Business Administration from the University of Wyoming, and in 1968, he earned his BS in Business Administration from Colorado College.

From 1970 to the present, Mr. Nicolaysen has been Vice President and President of Cole Creek Sheep Company, Inc., a cattle and sheep ranching and farming operation. From 1989 to June of 2009, he was president of Parkerton Ranch, Inc., a cattle and sheep ranching and farming operation. From 1988 to the present, he's been president of JK Minerals, Inc., an oil production and mineral leasing company. From 1995 to June 2009, he was the President of Cole Creek Outfitters, Inc., a guiding and hunting operation. From 1998 to the present he has been President, and was a founding member of, Seven Cross Ranches, LLC; Wcamp, FLLC; Sagebrush Land Management, FLLC, all of which are real estate development companies.

From 2001 to 2008, Mr. Nicolaysen was a unit operator for JK Minerals, Inc. From 2004 - 2007 Mr. Nicolaysen was an operator of Big Muddy Field for Wyoming Mineral Exploration, LLC., of which he was a founding member. From 2007 - 2008, he was a founding member of Muddy Mineral Exploration, LLC in Wyoming. From 2008 to May 1, 2009, he was a board member of Ameriwest Energy Corp.

Mr. Nicolaysen, and A.L. Sid Overton, Director and Chairman of the Board, are brothers-in-law.

A.L. Sid Overton, Director and Chairman of the Board of Directors

In 1964, Mr. Overton received his B.A. from the University of North Dakota. In 1966, he earned his L.L.B. from the University of North Dakota School of Law, and in 1969, he earned his J.D. from the University of North Dakota School of Law. Since 1998, Mr. Overton has worked as a lawyer for Overton & Associates, LLC. Mr Overton is the brother-in-law of Mr. Nicolaysen.

Mathijs van Houweninge, Director

Mr. van Houweninge studied Cognitive Artificial Intelligence at the University of Utrecht, The Netherlands. In 1998, he attended the Young Managers Programme at Insead Business School in Paris. In addition to being self-employed since 1992, Mr. van Houweninge was the founder and CEO of "Effective," a Dutch software and consultancy firm, from 1992 - 2002. From September 2007 to April 2008, Mr. van Houweninge was an associate at Advisor Falcon Capital in London. From May 2008 to December 2008, he was a Partner at Falcon Capital in London.

He currently serves as a Director of the following companies and organizations: Nieuwe Regentesseschool, a Dutch primary school (Utrecht, November 2004, non-profit); Blackwater Midstream Corp., a midstream gas storage facility (New Orleans, May 2008, listed); Cybercity 3D, a 3D modeling and marketing company (El Segundo, February 2008, non-listed); SkyPostal Networks, Inc., an air courier services company (Miami, April 2008, listed); IonIP bv, a network and business intelligence technology firm (Amsterdam, June 2008, non-listed); and Skillcity, an ICT support organization (Utrecht, August 2008, non-profit).

Jeffrey B. Bennett, Director

Mr. Bennett obtained a Bachelor's of Arts from Western State College of Colorado in 1979, majoring in Biology. Mr. Bennett has been a co-owner/partner in TCF Services, Inc. from 2005 to present and a co-owner/partner in Flame Energy, Inc. from May 2005 to present. He was Vice President of Operations of NQL Energy Services in Alberta, Canada from June 2003 through 2005. He was employed by Black Max Downhole Tools, Inc. from May 2001 through 2003, as a Region Manager. From 2000 to 2001, Mr. Bennett was operations manager for the western United States for Sharewell

Richard Kurtenbach – Chief Accounting Officer

Mr. Kurtenbach, became our Chief Accounting Officer on August 27, 2007. From April 2004 to August 2007, Mr. Kurtenbach was Vice President—Administration and Controller with publicly-traded Galaxy Energy Corporation where he was responsible for all administrative and accounting functions, including preparation of financial statements for SEC filings, internal controls and Sarbanes-Oxley compliance, financial modeling and management of joint interest activities for domestic and international drilling programs. From May 2003 to March 2004, Mr. Kurtenbach was Accounting Supervisor— Financial Reporting for Marathon Oil Company’s Powder River Business Unit, where he was responsible for the preparation and analysis of the Unit’s monthly and quarterly financial statements. From 2002 to 2003, Mr. Kurtenbach was self employed as a consultant to small energy companies advising management on financial, accounting auditing and taxation matters. From 1998 to 2001, Mr. Kurtenbach was the Finance and Administrative Manager for Hilton Petroleum, where he was responsible for the management of all financial, accounting and administrative matters for the Canadian publicly traded company. From 1985 to 1997, Mr. Kurtenbach was Manager—Commercial Services, American Region (1995-1997), Manager—Finance and Administration (1987-1995), and Financial Controller (1985-1987) at Ampolex (USA), Denver, Colorado, where he managed all financial accounting and administrative matters for the domestic and South American operations for the Australian publicly traded company. From 1983 to 1985, Mr. Kurtenbach was Controller of Phelps Dodge Fuel Development Corporation. From 1980 to 1983, Mr. Kurtenbach was Controller for Calvin Exploration Inc. in Denver, Colorado. From 1978 to 1980, Mr. Kurtenbach worked as a staff auditor at Price Waterhouse. Mr. Kurtenbach received a B.S. in Accounting from Illinois State University in Normal, Illinois (1978) and was licensed as a Certified Public Accountant in Illinois in 1978 and Colorado in 1981.

Former Officers and Directors

Andrei Stytsenko, 44, Director (From October 1, 2009 through October 21, 2009)

In 1996, Mr. Stytsenko received a degree in Petroleum Engineering from Ivano-Frankivsk (Ukraine) Technical Oil & Gas University. From March 2008 to present, he's been retired. From May 2006 - March 2008, Mr. Stytsenko was with Ensign Drilling in Calgary, Alberta. From February 2004 until mid-May 2006, Mr. Stytsenko served as founder, President, Principal Executive Officer, Treasurer, Principal Financial Officer, and Director of Metalex Resources, Inc., which changed its name to Rancher Energy Corp. in May 2006. From January 2000 until February 2004, Mr. Stytsenko was the secretary and a Director of Aberdene Mines Limited. From 1985 to 1996, Mr. Stytsenko was the managing supervisor for Ivano Frankovski Drilling Company, located in North Russia. Mr. Stytsenko's responsibilities included drilling holes up to 13,000 feet in depth for the exploration of oil and gas. From 1997 until 1998, Mr. Stytsenko was field supervisor for Booker Gold Exploration located in Vancouver, British Columbia. Mr. Stytsenko's responsibilities included core loding, assaying and mapping.

Silvia Soltan, 30, Director (From October 1, 2009 through October 21, 2009)

In 2001, Ms. Soltan received her BS of Arts and Science from the University of Toronto. From January 2002 until February 2005, Ms. Soltan has worked in Executive Customer Relations at IBM Canada Ltd. From December 2007 to the present, she has been President of Aden Solutions, Inc. Mr. Vaskevich, a director of the Company is Ms. Soltan’s husband.

Vladimir Vaskevich, 31, Director (From October 1, 2009 through October 21, 2009)

In 2005, Mr. Vaskevich received a diploma from the Sauder School of Business, UBC in Canada. From 2001 - 2006, Mr. Vaskevich was the President of Operations and a director of Centre City Health Recovery, Inc. From 2007 to the present, he has been President of Riverdale Mining, Inc. Ms. Soltan, a director of the Company, is Mr. Vaskevich’s wife.

We are managed under the direction of our Board of Directors. During the year ended March 19, 2010, the Board of Directors held 19 meetings. Each director attended greater than 75% of the meetings held for the period each was a director.

Committees of the Board of Directors

Audit Committee

The Company does not have an audit committee at this time.

Nominating Committee

The Company does not have a nominating committee at this time.

Compensation Committee.

The Company does not have a compensation committee at this time.

Compliance with Section 16(a) of the Securities Exchange Act of 1934

Section 16(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) requires our directors, executive officers and persons who own more than 10% of the Common Stock to file initial reports of ownership (Forms 3) and reports of changes in ownership of Common Stock (Forms 4 and Forms 5) with the Securities and Exchange Commission.

Based solely on a review of copies of such reports furnished to us and written representation that no other reports were required during the fiscal year ended March 31, 2010, we believe that all persons subject to the reporting requirements pursuant to Section 16(a) filed the required reports on a timely basis with the Securities and Exchange Commission (“SEC”).

Conflicts of Interest – General.

The Company’s directors and officers are, or may become, in their individual capacities, officers, directors, controlling shareholder and/or partners of other entities engaged in a variety of businesses. Thus, there exist potential conflicts of interest including, among other things, time, efforts and corporation opportunity, involved in participation with such other business entities.

Conflicts of Interest – Corporate Opportunities

Presently no requirement contained in the Company’s Articles of Incorporation, Bylaws, or minutes which requires officers and directors of the Company’s business to disclose to the Company business opportunities which come to their attention. The Company’s officers and directors do, however, have a fiduciary duty of loyalty to the Company to disclose to it any business opportunities which come to their attention, in their capacity as an officer and/or director or otherwise. Excluded from this duty would be opportunities which the person learns about through his involvement as an officer and director of another company. The Company has no intention of merging with or acquiring an affiliate, associate person or business opportunity from any affiliate or any client of any such person.

Code of Business Conduct and Ethics

We have adopted a Code of Business Conduct and Ethics for our directors, officers, and employees. The Board expects all directors, as well as officers and employees, to act ethically at all times and to adhere to the policies outlined in our Code of Business Conduct and Ethics. Copies of our Code of Business Conduct and Ethics are available by contacting the Chief Accounting Officer at the address or phone number contained in this annual report.

ITEM 11. EXECUTIVE COMPENSATION.

Summary Compensation Table

The following table sets forth in summary form the compensation received by our named executive officers who consist of the President and Chief Executive Officer, Chief Accounting Officer, and former President and Chief Executive Officer during the last two fiscal years.

Name & Position	Year		Salary ($)		Bonus ($)		Stock awards ($)		Option awards ($)		Non- equity incentive plan compensation ($) (A)		Non- qualified deferred compensation earnings ($)		All other compensation ($)		Total ($)

John Nicolayson, CEO & President (B)		2010 2009	$	60,423 0		0 0		0 0	$	63,363 0		0 0		0 0	$	3,000 0	$	129,073 0

John H. Works (D)		2010 2009		116,827 225,000		0 0		0 0		0 0		0 0		0 0		29,939 13,800		148,776 238,000

Richard E. Kurtenbach, Chief Accounting Officer (C)		2010 2009		170,569 175,000		0 0		0 0		8,909 0		0 0		0 0		4,780 11,800		186,268 186,800

(A) The amount in this column reflects the total grant date fair value for financial statement reporting purposes for awards granted in the fiscal year ended March 31, 2010, in accordance with FASB ASC 718 “Share Based Payments." Please refer to Note 10 of the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2010, for a discussion of the assumptions made in the valuation of the stock option awards.

(B) For Mr. Nicolaysen, Other Compensation represents auto allowances. Mr. Nicolaysen was appointed as Chief Executive Officer and President on October 2, 2009, and as a Director on October 27, 2009. He serves as a Director for no additional compensation.

(D) For Mr. Works Other Compensation represents auto allowances, contributions to his 401(k) accounts, and payment for accrued but unused vacation as of his termination. Mr. Works also served as a member of our Board of Directors for no additional compensation. Mr. Works’ employment with the Company was terminated on October 2, 2009.

Employment Agreements; Potential Payments Upon Termination or Change-in-Control

Employment Agreements

On October 27, 2009, we entered into an Executive Employment Agreement with Jon C. Nicolaysen to become our President and Chief Executive Officer. Pursuant to the agreement, Mr. Nicolaysen will receive a base salary of $120,000 per year. The base salary shall thereafter be increased annually at the greater of five percent or such other increase as may be approved by the Board of Directors. In addition Mr Nicolaysen: i) shall be eligible to receive incentive compensation or a bonus, payable solely in the discretion of the Board of Directors; ii) he shall be entitled to participate in all benefit programs established by the Company, and; iii) he shall be entitled to a Company-provided vehicle or a monthly allowance of $500. The Agreement may be terminated by either party upon fifteen days written notice. Also on October 27, 2009 we entered into a Management Retention Agreement with Mr. Nicolaysen, under which Mr. Nicolaysen was granted options to purchase 2,500,000 shares of the Company’s common stock at $0.035 per share. The Management Retention Agreement shall terminate the earlier of (i) one year; (ii) thirty days after the consummation of a Change in Control; (iii) thirty days following the confirmation of a Reorganization Plan, or: (iv) the ate that all obligations of the parties have been satisfied. See the table below for a description of the vesting provisions and term of the stock options.

On August 3, 2007, we entered into an employment agreement with Richard E. Kurtenbach to become our Chief Accounting Officer. Pursuant to the employment agreement, Mr. Kurtenbach received a base salary of $175,000 and a year end bonus to be determined by our Board of Directors. Mr. Kurtenbach began his employment with us on August 27, 2007 and he was granted on that date an option to purchase 450,000 shares of our common stock at an exercise price of $0.45 per share. The options vests annually over a three-year period from the date of grant, and are exercisable for a term of five years, subject to early termination of Mr. Kurtenbach’s employment with us. In addition, Mr. Kurtenbach was entitled to the coverage or benefits under any and all employee benefit plans maintained by us. The Employment Agreement with Mr. Kurtenbach expired on December 31, 2009. Effective January 1, 2010 Mr. Kurtenbach’s annual base salary was adjusted to $140,000.

We entered into an employment agreement with John H. Works, dated June 1, 2006, pursuant to which he agreed to become our President, Chief Executive Officer, and a member of our Board of Directors. The term of Mr. Works’ agreement was two years, beginning May 1, 2006. The agreement automatically renewed for two year terms unless prior to the commencement of the additional term: (i) either party gives thirty-days’ written notice of such party’s desire to terminate the agreement or (ii) the parties cannot agree to mutually acceptable terms for the additional term. We amended Mr. Works’ employment agreement on March 14, 2007 pursuant to which we paid him an annual salary of $225,000 per year. Under Mr. Works’ agreement as amended, we reimbursed him for out-of-pocket expenses incurred by him up to $10,000 per month and paid him an automobile allowance of $400 per month. In conjunction with his employment and as an incentive to become our President and Chief Executive Officer, we granted to Mr. Works, under his employment agreement, an option to purchase 4,000,000 shares of our common stock at a price of $0.00001 per share. The options vested 1,000,000 shares upon grant and vested 250,000 shares quarterly thereafter, beginning June 1, 2006 through May 31, 2009. Prior to his termination on October 2, 2009, all Mr. Works options had vested and had been exercised. Upon termination Mr. Works was paid $22,773 representing accrued but untaken vacation time. He received no additional termination pay.

Outstanding Equity Awards at Fiscal Year-end Table

The following table sets forth certain information regarding stock options held by the named executive officers as of March 31, 2009.

Name	Option Awards
	Number of Securities Underlying Unexercised Options (#) Exercisable			Number of Securities Underlying Unexercised Options (#) Non-exercisable		Option Exercise Price		Option Expiration Date

Jon C Nicolaysen (A)		250,000			2,250,000	$	0.035	10/27/19
Richard E. Kurtenbach		300,000	(B)		150,000	$	0.45	8/27/12
		35,000	(C)		315,000	$	0.035	10/27/14

(A)

Mr. Nicolaysen’s options vested 10% on the date of grant, October 27, 2009 and 90% on the earlier to occur of:

November 1, 2010;

ii)

The confirmation by the Bankruptcy Court of a Plan of Reorganization;

iii)

The dismissal from Chapter 11 Bankruptcy with the approval of the Court

iv)

An event of a merger, consolidation, sale of assets or other transaction which results in the holders of the Company’s common stock immediately before such transaction owning less than 50% of the common stock outstanding immediately after the transaction;

Any other form of change of control, or;

vi)

Voluntary termination for good reason.

(B)

Mr. Kurtenbach’s options vest 150,000 shares annually from August 27, 2008 through August 27, 2010.

(C)

Mr. Kurtenbach’s options vested 10% on the date of grant, October 27, 2009 and 90% on the earlier to occur of:

vii)

November 1, 2010;

viii)

The confirmation by the Bankruptcy Court of a Plan of Reorganization;

ix)

The dismissal from Chapter 11 Bankruptcy with the approval of the Court

xi)

Any other form of change of control, or;

xii)

Voluntary termination for good reason.

Director Compensation

During the year ended March 31, 2010, we compensated our non-employee Directors under two different compensation schemes. The first scheme was approved by the Board of Directors in April 2007. At a meeting of our shareholders on September 30, 2009 all six sitting Directors were replaced by a non-management slate of Directors. The new Board of Directors revised the compensation scheme for non-employee Directors. The two compensation schemes are discussed below.

Cash Compensation and Equity Compensation

Original Non-Employee Director Compensation Scheme All non-employee Directors received $45,000 annual compensation, which was paid quarterly in shares of our common stock and was priced at the fair market value at the end of each fiscal quarter represented by the closing price on the last trading day of the quarter. Each non-employee Director also received $6,000 per year, plus reasonable out of pocket expenses, to attend Board of Directors meetings. If a non-employee Director was a member of a committee, he received $4,000 per year for committee meetings. A committee chairman received $6,000 per year, except the audit committee chairman received $10,000 per year. Meeting payments were made quarterly and a Director could elect to receive stock in lieu of cash under the 2006 Stock Incentive Plan, which would be computed using the ratio of $1.50 of our common stock for each $1.00 to be paid in cash to the Director. Notwithstanding the existing non-employee Director compensation scheme, all non-employee directors voluntarily elected to forgo compensation for their service during the year ended March 31, 2009.

In addition to the above compensation, each non-employee director received in conjunction with his joining the Board of Directors a stock grant of 100,000 shares of our common stock that vested 20% (20,000 shares) on the date of grant and 20% per year thereafter, so long as the individuals continued to serve as Directors. Following the meeting of shareholders on September 30, 2009, at which all six sitting directors were not re-elected, the non-vested shares, 40,000 per prior director or 200,000 shares in total were cancelled.

Revised Non-Employee Director Compensation Scheme

The new Board of Directors elected at the meeting of shareholders on September 30, 2009 immediately rejected the existing non-employee director compensation scheme and implemented a new scheme under which non-employee each director would receive a cash payment of $5,000 per fiscal quarter. In addition under the terms of Management Retention Agreements entered into with each non-employee Director and the President and CEO, each member of the Board of Directors would be granted options to purchase 2,500,000 shares of the Company’s common stock at $0.035 per share.

The following table contains information pertaining to the compensation of our non-employee Directors during the fiscal year ended March 31, 2010.

Name	Fees Earned Or Paid In Cash		Stock Awards		Option Awards(A)		All Other Compensation		Total

A.L. Sid Overton	$	10,000	$	—	$	63,632	$	—	$	73,632
Mathijs van Houweninge	$	10,000	$	—	$	63,632	$	—	$	73,632
Jeffrey B. Bennett	$	10,000	$	—	$	63,632	$	—	$	73,632

William A. Anderson	$	—	$	—	$	—	$	—	$	—
Joseph P. McCoy	$	—	$	—	$	—	$	—	$	—
Patrick M. Murray	$	—	$	—	$	—	$	—	$	—
Myron M. Sheinfeld	$	—	$	—	$	—	$	—	$	—
Mark A. Worthey	$	—	$	—	$	—	$	—	$	—

(A)

Stock Awards compensation reflects the grant date fair value as measured in accordance with FASB ASC 718 “Share Based Payments." Please refer to Note 8 of the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2010, for a discussion of the assumptions made in the valuation of the stock option awards.

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

As of June 25, 2010 there were 119,316,700 shares of common stock outstanding. The following sets forth, as of June 25, 2010, the ownership of our common stock held by each person who beneficially owns more than 5% of our common stock, each of our directors, each executive officer, and all of our directors and executive officers as a group. Except as otherwise indicated, all shares are owned directly and the named person possesses sole voting and sole investment power with respect to all such shares. Shares not outstanding but deemed beneficially owned because a person or a member of a group has a right to acquire them within sixty (60) days after June 25, 2010 are treated as outstanding only when determining the amount and percentage owned by such person or such group.

Name and Address of Beneficial Owner	Number of Shares Beneficially Owned (1) (2)		Percent of Common Stock Outstanding (3)

Jon C. Nicolaysen Director, President, Chief Executive Officer (4) 999-18th Street, Suite 3400 Denver, Colorado 80202		4,450,000		3.73	%

A.L. Sid Overton (5) 999-18th Street, Suite 3400 Denver, Colorado 80202		3,750,000		3.14	%

Mathijs van Houweninge (6) 999-18th Street, Suite 3400 Denver, Colorado 80202		3,750,000		3.14	%

Jeffrey B. Bennett (7) 999-18th Street, Suite 3400 Denver, Colorado 80202		3,753,000		3.15	%

Richard E. Kurtenbach, Chief Accounting Officer 999-18th Street, Suite 3400 Denver, Colorado 80202 (8)		335,000		*

All Executive Officers and Directors as a Group (5 persons)		16,038,000		13.44	%

All 5% or Greater Shareholders

Sergei Stetsenko Paradeplatz 4 Zurich 8001 Switzerland		8,896,000		7.45	%

*Less than 1%

(1) Under SEC Rule 13d-3, a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares; and (ii) investment power, which includes the power to dispose or direct the disposition of shares. Certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons share the power to vote or the power to dispose of the shares). In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares (for example, upon exercise of an option) within 60 days of the date as of which the information is provided. In computing the percentage ownership of any person, the amount of shares outstanding is deemed to include the amount of shares beneficially owned by such person (and only such person) by reason of these acquisition rights. As a result, the percentage of outstanding shares of any person as shown in this table does not necessarily reflect the person’s actual ownership or voting power with respect to the number of shares of common stock actually outstanding on the date of this Annual Report.

(2) Except as indicated in the footnotes below, each person has sole voting and dispositive power over the shares indicated.

(3) Percentages are based on an aggregate 119,316,700 shares issued and outstanding as of June 25, 2010.

(4) Mr. Nicolayson holds 700,000 shares of common stock. In addition Mr. Nicolayson holds a $25,000 convertible promissory note, convertible into 1,250,000 shares of common stock at $0.02 per share and is convertible in whole or in part. Mr. Nicolayson also holds an option exercisable into 2,500,000 shares of common stock at $0.035 per share.

(5) Mr. Overton holds a $25,000 convertible promissory note, convertible into 1,250,000 shares of common stock at $0.02 per share and is convertible in whole or in part. Mr. Overton also holds an option exercisable into 2,500,000 shares of common stock at $0.035 per share.

(5) Mr. van Houweninge holds a $25,000 convertible promissory note, convertible into 1,250,000 shares of common stock at $0.02 per share and is convertible in whole or in part. Mr. van Houweninge also holds an option exercisable into 2,500,000 shares of common stock at $0.035 per share.

(7) Mr. Bennett holds 3,000 shares of common stock. In addition Mr. Bennett holds a $25,000 convertible promissory note, convertible into 1,250,000 shares of common stock at $0.02 per share and is convertible in whole or in part. Mr. Nicolayson also holds an option exercisable into 2,500,000 shares of common stock at $0.035 per share.

(8) Mr. Kurtenbach has options to purchase 450,000 and 300,000 shares of common stock at exercise prices of $0.45 and $0.035 per share, respectively. Of the total options issued to Mr. Kurtenbach, 300,000 of the $0.45 per share and 35,000 of the $0.035 per share options are exercisable within the next 60 days.

Equity Compensation Plan Information

The following table sets forth information as of March 31, 2010, with respect to compensation plans (including individual compensation arrangements) under which equity securities of the Company that are authorized for issuance, aggregated as follows:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)		Weighted- average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders		2,206,000	$	0.15		7,794,000
Equity compensation plans not approved by security holders		10,000,000	$	0.035		-
Total		12,206,000	$	0.06		7,794,000

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

Certain Related Transactions

On October 27, 2009, each of the four members of our Board of Directors loaned $25,000 for a total of $100,000 to the Company, under the terms of Convertible Promissory Notes (the “Notes”). The Notes as fully described in Note 7 - Convertible Promissory Notes Payable, of the Notes to Financial Statements of our audited financial statements for the fiscal year ended March 31, 2010, interest at the greater of 12% or prime plus 4%, mature on November 1, 2010and are convertible, at the holder’s option, into shares of the Company’s common stock at a conversion price of $0.02 per share.

During the year ended March 31, 2010, the Company incurred legal fees totaling $72,768 with Overton and Associates, LLC, a law firm in which Mr. Overton is a principal. The employment of Overton and Associates as special counsel has been approved by the Bankruptcy Court.

During the year ended March 31, 2010, the Company incurred engineering and oilfield operating consulting fees totaling $68,907 with TCF Services, Inc., an engineering consulting firm in which Mr. Bennett is a principal. The employment of TCF Services, Inc. has been approved by the Bankruptcy Court.

The Company has not implemented a formal written policy concerning the review of related party transactions, but compiles information about transactions between the Company and its directors and officers, their immediate family members, and their affiliated entities, including the nature of each transaction and the amount involved. The Board of Directors has responsibility for reviewing these transactions.

Director Independence

Our Board of Directors is comprised of four individuals. We have determined that three of our directors (Messrs. Overton, Bennett and van Houweninge) are each an “independent director” as defined under the published listing requirements of The NASDAQ Stock Market.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

Auditor’s Fees

The following table describes fees for professional audit services rendered by Hein, our principal accountant, for the audit of our annual financial statements for the years ended March 31, 2010 and March 31, 2009 and fees billed for other services rendered by Hein during the 2010 and 2009 fiscal years.

Type of Fee	Fiscal 2010		Fiscal 2009

Audit Fees (1)	$	74,093	$	117,396
Audit-Related Fees		-		-
Tax Fees (2)		10,464		10,000
All Other Fees		-		-
Total	$	84,557	$	127,396

1. Audit Fees include the aggregate fees incurred by us for professional services rendered by Hein for the audit of our annual financial statements and review of financial statements included in our Forms 10-Q for the 2010 and 2009 fiscal years.

2. Tax Fees include the aggregate fees incurred by us for professional services rendered by Hein for tax compliance and tax planning for the 2010 and 2009 fiscal years.

Pre-approval Policies and Procedures

The Board of Directors on an annual basis reviews audit and non-audit services performed by the independent auditor. All audit and non-audit services are preapproved by the Board of Directors, which considers, among other things, the possible effect of the performance of such services on the auditors' independence. The Board of Directors has considered the role of Hein in providing services to us for the fiscal years ended March 31, 2010 and March 31, 2009 and has concluded that such services are compatible with their independence as our auditors. In 2010 and 2009, 100% of the Audit Related Fees, Tax Fees and All Other Fees were pre-approved by the Board of Directors.

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

23.1		Consent of Ryder Scott Company, L.P., Independent Petroleum Engineers*
31.1		Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive Officer)*
31.2		Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting Officer)*
32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
99.1		Report of Ryder Scott Company, L.P., Independent Petroleum Engineer*

* Filed herewith.

EXHIBIT INDEX

23.1		Consent of Ryder Scott Company, L.P., Independent Petroleum Engineers*
31.1		Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive Officer)*
31.2		Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting Officer)*
32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
99.1		Report of Ryder Scott Company, L.P., Independent Petroleum Engineers*

* Filed herewith.

INDEX TO FINANCIAL STATEMENTS

Audited Financial Statements - Rancher Energy Corp.

Report of Independent Registered Public Accounting Firm	F-2

Balance Sheets as of March 31, 2010 and 2009	F-3

Statements of Operations for the Years Ended March 31, 2010 and 2009	F-4

Statement of Changes in Stockholders’ Equity (Deficit) for the Years Ended March 31, 2010, 2009	F-5

Statements of Cash Flows for the Years Ended March 31, 2010 and 2009	F-6

Notes to Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Rancher Energy Corp.

We have audited the accompanying balance sheets of Rancher Energy Corp. (the “Company” ) as of March 31, 2010 and 2009, and the related statements of operations, changes in stockholders’ equity and cash flows for each of the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Rancher Energy Corp. as of March 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years then ended, in conformity with U.S. generally accepted accounting principles.

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, on October 28, 2009 the Company filed a voluntary petition under Chapter 11 of the U.S. Bankruptcy Code. Uncertainties inherent in the Bankruptcy process, as well as recurring losses from operations raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We were not engaged to examine management’s assertion about the effectiveness of Rancher Energy Corp.’s internal control over financial reporting as of March 31, 2010 included in the accompanying Management Report on Internal Controls and, accordingly, we do not express an opinion thereon.

HEIN & ASSOCIATES LLP

Denver, Colorado

July 12, 2010

F-2

Rancher Energy Corp.

(Debtor-in-Possession)

Balance Sheets

	March 31,
	2010			2009
ASSETS

Current assets:
Cash and cash equivalents	$	372,286		$	917,160
Accounts receivable and prepaid expenses		615,602			584,139
Derivative receivable		-			455,960
Total current assets		987,888			1,957,259

Oil and gas properties (successful efforts method):
Unproved		53,030,814			53,328,147
Proved		19,432,703			20,631,487
Less: Accumulated depletion, depreciation, amortization and impairment		(56,355,224	)		(41,840,978	)
Net oil and gas properties		16,108,293			32,118,656

Furniture and equipment, net of accumulated depreciation of $568,529 and $381,396 respectively		574,938			770,354
Other assets		914,097			933,592
Total other assets		1,489,035			1,703,946

Total assets	$	18,585,216		$	35,779,861

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities – post petition	$	1,698,488		$	185,972
Asset retirement obligation		174,332			108,884
Note payable, net of unamortized discount of $-0- and $165,790, respectively		10,089,987			9,834,210
Total current liabilities		11,962,807			10,129.066

Long-term liabilities:
Asset retirement obligation		1,255,497			1,171,796
Total long-term liabilities		1,255,497			1,171,796

Total liabilities not subject to compromise		13,218,304			11,300,862

Liabilities subject to compromise		1,336,133			630,836

Total liabilities		14,554,437			11,931,698

Commitments and contingencies (Notes 2,3,6 and 8)

Stockholders’ equity:
Common stock, $0.00001 par value, 275,000,000 and 100,000,000 shares authorized at March 31, 2010 and 2009 ; 119,316,700 and 119,016,700 shares issued and outstanding at March 31, 2010 and 2009, respectively		1,194			1,191
Additional paid-in capital		93,025,876			92,582,001
Accumulated deficit		(88,996,291	)		(68,735,029	)
Total stockholders’ equity		4,030,779			23,848,163

Total liabilities and stockholders’ equity	$	18,585,216		$	35,779,861

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

F-3

Rancher Energy Corp.

(Debtor-in-Possession)

Statements of Operations

	For the Year Ended March 31,
	2010			2009
Revenue:
Oil and gas sales	$	3,585,738		$	5,140,660
Gains (losses) on derivative activities		(357,582	)		1,020,672
Total revenues		3,228,156			6,161,332
Operating expenses:
Production taxes		573,992			647,755
Lease operating		1,723,015			2,423,015
Depreciation, depletion, and amortization		1,178,986			1,196,970
Impairment of unproved properties		13,525,642			39,050,000
Accretion on discount of asset retirement obligations		167,896			158,009
Exploration		19,181			20,108
General and administrative		2,490,453			3,631,580
Total operating expenses		19,679,165			47,127,437

Loss from operations		(16,451,009	)		(40,966,105	)

Other income (expense):
Amortization of deferred financing costs and discount on note payable		(1,770,789	)		(4,021,767	)
Interest expense		(1,732,360	)		(1,369,957	)
Interest and other income		3,487			16,488
Total other income (expense)		(3,499,662	)		(5,375,236	)

Loss before reorganization items	$	(19,950,671	)		(46,341,341	)

Reorganization items:
Professional and legal fees		310,591			-

Net loss	$	(20,261,262	)	$	(46,341,341	)

Basic and diluted net loss per share	$	(0.17	)	$	(0.40	)

Basic and diluted weighted average shares outstanding		119,347,248			116,398,755

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

F-4

Rancher Energy Corp.

(Debtor-in-Possession)

Statement of Changes in Stockholders’ Equity

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

Balance March 31, 2008		114,878,341		$	1,150		$	91,790,181	$	(22,393,688	)	$	69,397,643

Common stock issued on exercise of stock options		750,000			7			-		-			7

Common stock issued to directors for services rendered		3,388,359			34			217,466		-			217,500

Stock-based compensation		-			-			574,354		-			574,354

Net loss		-			-			-		(46,341,341	)		(46,341,341	)

Balance March 31, 2009		119,016,700		$	1,191		$	92,582,001	$	(68,735,029	)	$	23,848,163

Common stock issued on exercise of stock options		500,000			5			-		-			5

Common stock issued to directors for services rendered		-			-			51,700		-			51,700

Cancellation of non vested restricted stock		(200,000	)		(2	)		2		-			-

Discount on convertible notes due to beneficial conversion feature		-			-			105,000		-			105,000

Stock-based compensation		-			-			287,173		-			287,173

Net loss		-			-			-		(20,261,262	)		(20,261,262	)

Balance March 31, 2010		119,316,700		$	1,194		$	93,025,876	$	(88,996,291	)	$	4,030,779

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

F-5

Rancher Energy Corp.

(Debtor-in-Possession)

Statements of Cash Flows

	For the Year Ended March 31,
	2010			2009
Cash flows from operating activities:
Net loss	$	(20,261,262	)	$	(46,341,341	)
Adjustments to reconcile net loss to net cash used for operating activities:
Depreciation, depletion, and amortization		1,178,986			1,196,970
Impairment of unproved properties		13,525,642			39,050,000
Reorganization items, net		310,591			-
Interest expense – convertible notes beneficial conversion feature		105,000			-
Interest expense added to principle balance		188,112			-
Accretion expense		167,896			158,009
Asset retirement obligations settled		-			(147,662	)
Stock-based compensation expense		287,173			470,953
Amortization of deferred financing costs and discount on notes payable		1,665,789			4,021,767
Unrealized (gains) losses on crude oil hedges		455,960			(1,227,567	)
Common stock issued for services, directors		51,700			320,900
Loss on sale of assets		-			39,972
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses		(31,463	)		586,501
Accounts payable and accrued liabilities		1,826,879			(1,093,445	)
Other		77,142			-
Net cash used for operating activities, before reorganization items		(451,855	)		(2,964,943	)

Cash effect of reorganization items		(110,154	)		-

Net cash used by operating activities		(562,009	)		(2,964,943	)

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(32,760	)		(260,735	)
Proceeds from sales of assets		8,015			-
Increase in other assets		-			(358,056	)
Net cash used for investing activities		(24,745	)		(618,791	)

Cash flows from financing activities:
Increase in deferred financing costs		-			(101,478	)
Proceeds from borrowings		140,000			-
Proceeds from issuance of common stock upon exercise of stock options		5			7
Repayment of debt		(98,125	)		(2,240,000	)
Net cash provided by (used for) financing activities		41,880			(2,341,471	)

Decrease in cash and cash equivalents		(544,874	)		(5,925,205	)
Cash and cash equivalents, beginning of year		917,160			6,842,365
Cash and cash equivalents, end of year	$	372,286		$	917,160
Supplemental Statement of Cash Flow Information:
Cash paid for interest	$	613,479			1,369,733
Non-cash investing and financing activities:
Payables for purchase of oil and gas properties	$	-		$	53,799
Asset retirement asset and obligation	$	(18,747	)	$	10,481
Discount on note payable, conveyance of overriding royalty and net profits interests	$	1,500,000		$	1,050,000

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

F-6

Rancher Energy Corp.

(Debtor-in-Possession)

Notes to Financial Statements

Note 1—Organization and Summary of Significant Accounting Policies

Organization

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

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

Bankruptcy Filing

On October 28, 2009, the Company filed a voluntary petition (the “petition”) for relief in the United States Bankruptcy Court, District of Colorado under Chapter 11 of Title 11 of the U.S. Bankruptcy Code (the “Bankruptcy Court”). The Company will continue to operate its business as “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Code and orders of the Bankruptcy Court. See Note 2 “Proceedings Under Chapter 11 of the Bankruptcy Code” for details regarding the Bankruptcy filing and the Chapter 11 case.

The accompanying financial statements have been prepared on the basis of accounting principles applicable to a going concern, which contemplates the realization of assets and extinguishment of liabilities in the normal course of business. However, the petition raises substantial doubt about the Company’s ability to remain a going concern. The Company’s continuation as a going concern may be contingent upon, among other things, its ability (i) to obtain Debtor-in-Possession financing; (ii) to reduce administrative, operating and interest costs and liabilities through the bankruptcy process; (iii) to generate sufficient cash flow from operations; (iv) to obtain confirmation of a plan of reorganization under the Bankruptcy Code; and (v) to obtain financing to facilitate an exit from bankruptcy. The Company is currently evaluating various courses of action to address the operational and liquidity issues it is facing and has begun the process of improving operations. There can be no assurance that any of these efforts will be successful. The accompanying financial statements do not include any adjustments that might result should we be unable to continue as a going concern. In the event the Company’s restructuring activities are not successful and it is required to liquidate, additional significant adjustments in the carrying value of assets and liabilities, the revenues and expenses reported and the balance sheet classifications used may be necessary.

Financial Accounting Standards Board (FASB) Accounting Standards Codification (FASB ASC) 852 "Financial Reporting During Reorganization Proceedings," which is applicable to companies in Chapter 11, generally does not change the manner in which financial statements are prepared. However, it does require that the financial statements for periods subsequent to the filing of a Chapter 11 case distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Revenues, expenses, realized gains and losses, and provisions for losses that can be directly associated with the reorganization and restructuring of the business must be reported separately as reorganization items in the statements of operations. The balance sheet must distinguish pre-petition liabilities subject to compromise from both those pre-petition liabilities that are not subject to compromise and from post-petition liabilities. Liabilities that may be affected by a plan of reorganization must be reported at the amounts expected to be allowed, even if they may settled for lesser amounts. In addition, cash provided by reorganization items, if any, must be disclosed separately in the statement of cash flows. The Company adopted FASB ASC 852-10 effective on October 28, 2009 and will segregate those items as outlined above for all reporting periods subsequent to such date.

Use of Estimates in the Preparation of Financial Statements

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

F-7

Revenue Recognition

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

Cash and Cash Equivalents

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

Concentration of Credit Risk

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

Oil and Gas Producing Activities

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

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

The Company complies with FASB ASC 932, “Extractive Activities – Oil and Gas." The Company currently does not have any existing capitalized exploratory well costs, and has therefore determined that no suspended well costs should be impaired.

The Company reviews its long-lived assets for impairments when events or changes in circumstances indicate that impairment may have occurred. The impairment test for proved properties compares the expected undiscounted future net cash flows on a property-by-property basis with the related net capitalized costs, including costs associated with asset retirement obligations, at the end of each reporting period. Expected future cash flows are calculated on all proved reserves using a discount rate and price forecasts selected by the Company’s management. The discount rate is a rate that management believes is representative of current market conditions. The price forecast is based on NYMEX strip pricing, adjusted for basis and quality differentials, for the first three to five years and is held constant thereafter. Operating costs are also adjusted as deemed appropriate for these estimates. When the net capitalized costs exceed the undiscounted future net revenues of a field, the cost of the field is reduced to fair value, which is determined using discounted future net revenues. An impairment allowance is provided on unproved property when the Company determines the property will not be developed or the carrying value is not realizable. Recent global market conditions and declining commodity price volatility have negatively impacted the valuation of the Company’s unproved oil and gas properties. During the years ended March 31, 2010 and 2009, the Company recognized impairment of $13,525,000 and $39,050,000, respectively, representing the excess of the carrying value over the estimated realizable value of such properties. Following the recognition of impairment in the year ended March 31, 2010, the net book value of the Company’s unproved properties is $-0-.

F-8

Sales of Proved and Unproved Properties

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

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

Net Profits Interest

The Company assigned a 10% Net Profits Interest (NPI) to its Lender, under the terms of the Eighth Amendment to the Term Credit Agreement (see Note 6 – Short-term Note Payable). Net profit is defined as the excess of the sum of crude oil proceeds plus hedge settlements, over the sum of lease operating, marketing, transportation and production tax expenses. The Company is obligated to pay to the Lender 10% of such excess, if any, on a monthly basis, so long as the NPI remains in effect. The Company records amounts due under the NPI as operating expense. For the year ended March 31, 2010, the Company recognized $150,280 as NPI expense, including such amount as lease operating expense in its Statement of Operations.

Capitalized Interest

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

Other Property and Equipment

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

Deferred Financing Costs

Costs incurred in connection with the Company’s debt issuances are capitalized and amortized over the term of the debt, which approximates the effective interest method. Amortization of deferred financing costs of $1,500,000 and $610,006 was recognized for the years ended March 31, 2010 and 2009, respectively, and has been charged to operations as an expense in the Statement of Operations.

Fair Value of Financial Instruments

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

Income Taxes

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

F-9

The Company adopted the provisions of FASB ASC 740, “Income Taxes” on April 1, 2007. FASB ASC 740 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FASB ASC 740 and in subsequent periods. The adoption of FASB ASC 740 had an immaterial impact on the Company’s financial position and did not result in unrecognized tax benefits being recorded. Subsequent to adoption, there have been no changes to the Company’s assessment of uncertain tax positions. Accordingly, no corresponding interest and penalties have been accrued. The Company’s policy is to recognize penalties and interest, if any, related to uncertain tax positions as general and administrative expense. The Company files income tax returns in the U.S. Federal jurisdiction and various states. The Company’s tax years of 2004 and forward are subject to examination by the Federal and state taxing authorities.

Net Loss per Share

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

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

F-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,
	2010		2009
Dilutive		-		-
Anti-dilutive		60,111,454		69,091,225

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:

Stock Based Payment

	For the Year Ended March 31,
	2010			2009

Net loss	$	(20,261,262	)	$	(46,341,341	)

Basic weighted average common shares outstanding		119,347,248			116,398,755

Basic and diluted net loss per common share	$	(0.17	)	$	(0.40	)

The Company recognizes compensation cost for stock-based awards based on estimated fair value of the award and records compensation expense over the requisite service period. See Note 10 “Share-Based Compensation” herein, for further discussion.

Commodity Derivatives

The Company accounts for derivative instruments or hedging activities under the provisions of FASB ASC 815 “Derivatives and Hedging." FASB ASC 815 requires the Company to record derivative instruments at their fair value. The Company’s risk management strategy is to enter into commodity derivatives that set “price floors” and “price ceilings” for its crude oil production. The objective is to reduce the Company’s exposure to commodity price risk associated with expected crude oil production.

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

The table below summarizes the realized and unrealized losses related to the Company’s derivative instruments for the years ended March 31, 2010 and 2009.

	Year Ended March 31,
	2010			2009
Realized gains (losses) on derivative instruments	$	98,378		$	(206,895	)
Unrealized gains (losses) on derivative instruments		(455,960	)		(1,227,567	)
Total realized and unrealized gains (losses) recorded	$	(357,582	)	$	(1,020,672

The Company’s sole derivative instrument expired during the year ended March 31, 2010, and the Company has no hedge positions as of that date.

F-11

Major Customers

For the years ended March 31, 2010 and 2009, one customer accounted for 100% of the Company’s oil and gas sales. The loss of that customer would not be expected to have a material adverse effect upon our sales and would not be expected to reduce the competition for our oil production, which in turn would not be expected to negatively impact the price we receive. As of March 31, 2010 and 2009 accounts receivable from this customer account for 79% and 60%, respectively of the Company’s total accounts receivable.

Industry Segment and Geographic Information

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

Off—Balance Sheet Arrangements

As part of its ongoing business, the Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (SPEs), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. From February 4, 2004 (inception) through March 31, 2010, the Company has not been involved in any unconsolidated SPE transactions.

Reclassification

Certain amounts in the 2009 financial statements have been reclassified to conform to the 2010 financial statement presentation. Such reclassifications had no effect on net loss.

Recent Accounting Pronouncements

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (ASC 855) to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. ASC 855 is effective for interim and annual reporting periods ending after June 15, 2009. The Company adopted the provisions of ASC 855 for the interim period ended June 30, 2009. There was no impact on the Company’s operating results, financial position or cash flows.

In June 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-01, “Generally Accepted Accounting Principles” (ASU 2009-01). ASU 2009-01 establishes “The FASB Accounting Standards Codification,” or Codification, which became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. ASU 2009-01 is effective for interim and annual periods ending after September 15, 2009. The Company adopted the provisions of ASU 2009-01 for the interim period ended December 31, 2009. There was no impact on the Company’s operating results, financial position or cash flows.

In August 2009, the FASB issued ASU No. 2009-05, “Fair Value Measurements and Disclosures” (ASU 2009-05). ASU 2009-05 amends Subtopic 820-10, “Fair Value Measurements and Disclosures” , to provide guidance on the fair value measurement of liabilities. ASU 2009-05 provides clarification for circumstances in which a quoted price in an active market for the identical liability is not available. ASU 2009-05 is effective for interim and annual periods beginning after August 26, 2009. The Company adopted the provisions of ASU 2009-05 for the Interim period ended September 30, 2009. There was no impact on the Company’s operating results, financial position or cash flows.

F-12

In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting (ASC 2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by Release No. 33-8995 are now required to price proved oil and gas reserves using the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning for financial statements for fiscal years ending on or after December 31, 2009. The impact on the Company’s operating results, financial position and cash flows has been recorded in the financial statements; additional disclosures were added to the accompanying notes to the consolidated financial statements for the Company’s supplemental oil and gas disclosure. See Note 12 - Disclosures about Oil and Gas Producing Activities for more details.

In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 “Oil and Gas Estimations and Disclosures” (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-3, as discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Company adopted ASU 2010-03 effective December 31, 2009. The Company does not believe that provisions of the new guidance, other than pricing, significantly impacted the reserve estimates or consolidated financial statements. The Company does not believe that it is practicable to estimate the effect of applying the new rules on net loss or the amount recorded for depreciation, depletion and amortization for the year ended March 31, 2010.

Note 2 - Proceedings Under Chapter 11 of the Bankruptcy Code

As discussed in Note 1 above, on October 28, 2009 (the "Petition Date"), the Company filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court. The petition was filed in order to enable the Company to pursue reorganization efforts under Chapter 11 of the Bankruptcy Code. The Company continues to operate its business as debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In general, as debtor-in-possession, the Company is authorized under Chapter 11 to continue to operate as an ongoing business, but may not engage in transactions outside of the ordinary course of business without the prior approval of the Bankruptcy Court.

No assurance can be provided as to what values, if any, will be ascribed in the bankruptcy proceedings to the Company’s pre-petition liabilities, common stock and other securities. Based upon the status of the Company's plan of reorganization, we currently believe that it is uncertain whether holders of our securities will receive any payment in respect of such securities.

Subject to certain exceptions under the Bankruptcy Code, the Bankruptcy Filing automatically enjoins, or stays, the continuation of any judicial or administrative proceedings or other actions against the Company or its property to recover on, collect or secure a claim arising prior to the Petition Date. Thus, for example, creditor actions to obtain possession of property from the Company, or to create, perfect or enforce any lien against the property of the Company, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

F-13

In order to successfully exit Chapter 11 bankruptcy, the Company will need to propose, and obtain Bankruptcy Court confirmation of, a plan of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization would, among other things, resolve the Debtors' pre-petition obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to exit from bankruptcy. The Company had the exclusive right for 120 days after the Petition Date to file a plan of reorganization and 60 additional days to obtain necessary acceptances. On May 26, 2010, the Company filed its second motion to extend exclusive period to file a reorganization plan through August 24, 2010 and the exclusive period to solicit acceptance of a plan through October 22, 2010. The motion is currently under consideration by the Bankruptcy Court. If the Company's exclusivity period lapses, any party in interest may file a plan of reorganization for the Company. In addition to the need for Bankruptcy Court confirmation and satisfaction of Bankruptcy Code requirements, a plan of reorganization must be accepted as described below by holders of impaired claims and equity interests in order to become effective. A Company’s Chapter 11 plan of reorganization will have to be accepted by holders of claims against and equity interests in the Company if (i) at least one-half in number and two-thirds in dollar amount of claims actually voting in each impaired class of claims have voted to accept the plan and (ii) at least two-thirds in amount of equity interests actually voting in each impaired class of equity interests has voted to accept the plan. Under circumstances specified in the so-called "cramdown" provisions of section 1129(b) of the Bankruptcy Code, the Bankruptcy Court may confirm a plan even if such plan has not been accepted by all impaired classes of claims and equity interests. A class of claims or equity interests that does not receive or retain any property under the plan on account of such claims or interests is deemed to have voted to reject the plan. The precise requirements and evidentiary showing for confirming a plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests in the rejecting class — i.e. , secured claims or unsecured claims, subordinated or senior claims, preferred or common stock.

Under section 365 of the Bankruptcy Code, the Company may assume, assume and assign, or reject executory contracts and unexpired leases, including real property and equipment leases, subject to the approval of the Bankruptcy Court and certain other conditions. Rejection constitutes a court-authorized breach of the lease or contract in question and, subject to certain exceptions, relieves the Company of its future obligations under such lease or contract but creates a deemed pre-petition claim for damages caused by such breach or rejection. Parties whose contracts or leases are rejected may file claims against the Company for damages. Generally, the assumption of an executory contract or unexpired lease requires the Company to cure all prior defaults under such executory contract or unexpired lease, including all pre-petition arrearages, and to provide adequate assurance of future performance. In this regard, the Company expects that liabilities subject to compromise and resolution in the Bankruptcy Cases will arise in the future as a result of damage claims created by the Company's rejection of various executory contracts and unexpired leases. Conversely, the Company would expect that the assumption of certain executory contracts and unexpired leases may convert liabilities shown in our financial statements as subject to compromise to post-petition liabilities. Due to the uncertain nature of many of the potential claims, the Company is unable to project the magnitude of such claims with any degree of certainty.

The Bankruptcy Court established a March 5, 2010 deadline for the filing of proofs of claim under the Bankruptcy Code, requiring the Company's creditors to submit claims for liabilities not paid and for damages incurred. There may be differences between the amounts at which any such liabilities are recorded in the Company's financial statements and the amount claimed by the Company's creditors. Significant litigation may be required to resolve any such disputes or discrepancies.

There can be no assurance that a reorganization plan will be proposed by the Company or confirmed by the Bankruptcy Court, or that any such plan will be consummated.

As a result of the Bankruptcy Filing, realization of assets and liquidation of liabilities are subject to uncertainty. While operating as a debtor-in-possession under the protection of Chapter 11, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, the Company may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in the condensed financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our financial statements. Our historical financial statements do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

The adverse publicity associated with the Bankruptcy Filing and the resulting uncertainty regarding the Company's future prospects may hinder the Company's ongoing business activities and its ability to operate, fund and execute its business plan by impairing relations with property owners and potential lessees, vendors and service providers; negatively impacting the ability of the Company to attract, retain and compensate key executives and employees and to retain employees generally; limiting the Company's ability to obtain trade credit; and limiting the Company's ability to maintain and exploit existing properties and acquire and develop new properties.

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, post-petition liabilities and pre-petition liabilities must be satisfied in full before shareholders of the Company are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery, if any, to creditors and shareholders of the Company will not be determined until confirmation and consummation of a plan of reorganization. No assurance can be given as to what values, if any, will be ascribed in the Bankruptcy Cases to each of these constituencies or what types or amounts of distributions, if any, they would receive.

F-14

Reorganization Items

Reorganization items represent the direct and incremental costs related to the Company's Chapter 11 case, such as professional fees incurred, net of interest income earned on accumulated cash during the Chapter 11 process. These restructuring activities may result in additional charges and other adjustments for expected allowed claims (including claims that have been allowed by the Court) and other reorganization items that could be material to the Company’s financial position or results of operations in any given period.

Liabilities Subject to Compromise

Liabilities subject to compromise at March 31, 2010 and 2009 include the following pre-petition liabilities:

	2010		2009
Accounts payable, trade	$	164,390	$	-
Other payables and accrued liabilities		265,516		105,985
Property and advalorem taxes payable		766,227		524,851
Convertible notes payable		140,000		-

Total liabilities subject to compromise	$	1,336,133	$	630,836

Note 3—Oil and Gas Properties

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

	As of March 31,
	2010			2009
Proved properties	$	19,432,703		$	20,631,487
Unproved properties excluded from DD&A		52,716,480			52,953,185
Equipment and other		314,334			374,962
Total oil and gas properties		72,463,517			73,959,634
Less accumulated depletion, depreciation, amortization and impairment		(56,355,224	)		(41,840,978	)
	$	16,108,293		$	32,118,656

Assignment of Overriding Royalty and Net Profits Interest

In conjunction with the issuance of short term debt in October 2007 (See Note 6 – Short Term Note Payable),the Company assigned the Lender a 2% Overriding Royalty Interest (ORRI), proportionally reduced when the Company’s working interest is less than 100%, in all crude oil and natural gas produced from its three Powder River Basin fields. The Company estimated the fair value of the ORRI granted to the Lender to be approximately $4,500,000 and recorded this amount as a debt discount and a decrease of oil and gas properties. In October 2008 the Lender and the Company agreed to an extension of the maturity date of the short term debt by six months. As partial consideration for the extension, the Company granted an increase the proportionate ORRI from 2% to 3%. The Company estimated the fair value of the incremental ORRI granted to the Lender to be approximately $1,050,000 and has recorded this amount as a debt discount and a decrease of oil and gas properties. On June 3, 2009 the Lender and the Company extended the maturity date of the short term debt until October 15, 2009. As partial consideration for the extension, the Company assigned the Lender a 10% Net Profits Interest (the “NPI”) in all crude oil and natural gas produced from its three Powder River Basin fields. The Company estimated the fair value of the NPI to be approximately $1,500,000 and recorded this amount as deferred finance costs and a decrease of oil and gas properties.

F-15

Carbon Dioxide (“CO2”) Enhanced Oil Recovery Project

The Company’s business plan at the time of the acquisition of its oil and gas properties was to conduct an enhanced oil recovery project by injecting CO2 into the productive formations in the fields. This plan required a significant amount of capital to drill additional wells, and construct facilities to inject and recycle the CO2. To ensure an adequate supply of CO2 the Company entered into two separate supply agreements, one with Anadarko Petroleum Corporation and the other with ExxonMobil Corporation to deliver CO2 to the Company’s fields. The Company has been unsuccessful in raising sufficient capital to commence the enhanced oil recovery project or to take delivery of the contracted volume of CO2. On April 3, 2009 ExxonMobil informed the Company, that ExxonMobil was terminating, effective immediately, CO2 supply agreement. ExxonMobil’s termination is based on the Company not providing performance assurances in the form of a letter of credit. In connection with the Company’s bankruptcy petition the Company rejected the supply agreement with Anadarko. The Company currently does not have a CO2 supply agreement.

Impairment of Unproved Properties

In conjunction with the regular periodic assessment of impairment of unproved properties, the Company assessed the carrying value of its unproved properties giving consideration to volatility of commodity prices and the difficulties encountered in raising capital to develop the properties. Accordingly, during the years ended March 31, 2010 and 2009 the Company recorded impairment expense on unproved properties of $13,525,000 and $39,050,000, reflecting the excess of the carrying value over estimated realizable value of the assets. The amounts charged to impairment in 2010 represented the remaining book value of the Company’s unproved properties leaving a $-0 net book value for unproved properties as 0f March 31, 2010.

Note 4—Asset Retirement Obligations

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

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

A reconciliation of the Company’s asset retirement obligation liability during the years ended March 31, 2010 and 2009 is as follows:

	2010			2009
Beginning asset retirement obligation	$	1,280,680		$	1,259,851
Liabilities incurred		-			-
Liabilities settled		-			(147,662	)
Changes in estimates		(18,747	)		10,482
Accretion expense		167,896			158,009
Ending asset retirement obligation	$	1,429,829		$	1,280,680

Current	$	174,332		$	108,884
Long-term		1,255,497			1,171,796
	$	1,429,829		$	1,280,680

F-16

Note 5 Fair Value Measurements

On April 1, 2008, the Company adopted FASB ASC 820, “Fair Value Measurements and Disclosures,” which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The Statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices are available in active markets for identical assets or liabilities;

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

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

FASB ASC 820 requires financial assets and liabilities to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. As of March 31, 2010 the Company had no derivative or other financial assets or liabilities required to be reported at fair value. In accordance with FSP 157-2, the Company has not applied the provisions of ASC 820 to its asset retirement obligations.

The Company’s sole derivative financial instrument was a participating cap costless collar agreement. The instrument expired in October 2009. The fair value of the costless collar agreement was determined based on both observable and unobservable pricing inputs and therefore, the data sources utilized in these valuation models are considered level 3 inputs in the fair value hierarchy. In the Company’s adoption of FASB ASC 820, it considered the impact of counterparty credit risk in the valuation of its assets and its own credit risk in the valuation of its liabilities that are presented at fair value. The Company established the fair value of its derivative instruments using a published index price, the Black-Scholes option-pricing model and other factors including volatility, time value and the counterparty’s credit adjusted risk free interest rate.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 3 in the fair value hierarchy for the year ended March 31, 2010:

Balance as of April 1, 2009, asset, (liability)	$	(455,960	)
Total gains (losses) (realized or unrealized):
Included in earnings		(357,582	)
Included in other comprehensive income
Purchases, issuances and settlements		(98,378	)
Transfers in and out of Level 3

Balance as of March 31, 2010	$	-

Change in unrealized gains (losses) included in earnings relating to derivatives still held as of March 31, 2010	$	-

Note 6—Short Term Note Payable

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

F-17

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

Under the terms of the Eighth Amendment, all amounts outstanding under the Term Credit Agreement, as amended, bear interest at a rate equal to the greater of (a) 16% per annum and (b) the LIBOR rate, plus 6% per annum. Furthermore, the Eighth Amendment specifies that 4% of the interest rate shall be capitalized so that it is added to and becomes a part of the Principal Amount in lieu of payment in cash. Under the terms of the Term Credit Agreement, as amended, the Company was required to make monthly interest payments on the amounts outstanding but was not required to make any principal payments until the Maturity Date.

The Company’s obligations under the Term Credit Agreement, as amended, are collateralized by a first priority security interest in its properties and assets, including all rights under oil and gas leases in its three producing oil fields in the Powder River Basin of Wyoming and all of its equipment on those properties. Under the terms of the original Term Credit Agreement, the Company granted the Lender a 2% Overriding Royalty Interest (ORRI), proportionally reduced when the Company’s working interest is less than 100%, in all crude oil and natural gas produced from its three Powder River Basin fields. The First Amendment granted an increase in the proportionate ORRI assigned to the Lender from 2% to 3%. The Company estimated the fair value of the 2% ORRI granted to the Lender to be approximately $4,500,000 and the value of the increase ORRI to be approximately $1,050,000. These amounts were recorded as discounts to the Note Payable and as decreases of oil and gas properties. The Eighth Amendment granted a Conveyance of Net Profits to the Lender. The Company estimated the fair value of the 10% NPI to be approximately $1,500,000. This amount was recorded as deferred finance costs and was amortized over the term of the Note, as amended. The Company recorded total amortization of discounts and deferred finance costs of $1,770,789 and $4,021,767 for the years ended March 31, 2010 and 2009 respectively.

As noted above, the Note Payable issued by the Company on October 16, 2007, matured on October 15, 2009. Payment of the principal balance of approximately $10,188,000, plus accrued interest, was not made on the maturity date, and therefore, an event of default occurred under the Term Credit Agreement, as amended. On November 16, 2009, the Lender presented to the Company a Notice of Event of Default, a Demand for Payment and a Notice of Intent to Foreclose, collectively “the Notice”). The Notice declared all of the obligations immediately due and payable and demanded that the Company promptly pay to Lender all of the obligations within ten days of receipt of the Notice, and states that if the Company fails to pay the obligations in full as demanded, the Lender intends to foreclose on the secured properties under the provisions of the Term Credit Agreement and other agreements. Effective as the date of the Notice, interest under the Credit agreement will accrue at the default rate, and the percentage of net revenue to be applied for debt service and other obligations shall be 100%.

On October 16, 2009 the Lender gave instructions to the Company’s bank (the “Instruction”) that under the terms of the Restricted Account and Securities Control Agreement executed in conjunction with the Term Credit Agreement, as of the date of the Instruction, the Company shall no longer have access to any funds held in identified accounts, and the Lender now has exclusive right to direct the disposition of such funds. On October 21, 2009 the Company’s bank transferred the all remaining funds, $98,415, from the Company’s account to the Lender. That amount has been applied against the principle resulting in an outstanding principle balance of approximately $10,090,000 as of March 31, 2010.

As discussed in Note 1 and Note 2 above, on October 28, 2009, the Company filed a voluntary petition (the “petition”) for relief in the United States Bankruptcy Court, District of Colorado under Chapter 11 of Title 11 of the U.S. Bankruptcy Code. (the “Bankruptcy Court”). Subject to certain exceptions under the Bankruptcy Code, the Bankruptcy Filing automatically enjoins, or stays, the continuation of any judicial or administrative proceedings or other actions against the Company or its property to recover on, collect or secure a claim arising prior to the Petition Date. Thus, for example, creditor actions to obtain possession of property from the Company, or to create, perfect or enforce any lien against the property of the Company, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

See Note 8 - Commitments and Contingencies for additional information regarding an adversary action filed by the Company against the Lender in an effort to avoid certain of the interests previously assigned to the Lender.

F-18

Note 7– Convertible Promissory Notes Payable

On October 27, 2009, the Company issued Convertible Promissory Notes (the “Promissory Notes”) totaling $140,000. One hundred thousand dollars of the Promissory Notes were issued to officers and/or directors ($25,000 each). The remainder of the Promissory Notes were issued to shareholders. The Promissory Notes bear interest at an annual rate equal to the greater of (i) 12%, or (ii) the prime rate (as published in the Wall Street Journal) plus 3%. The Promissory Notes mature on November 1, 2010, and all obligations and payments due under the Promissory Notes are subordinate to the Company’s senior debt. Principal and accrued interest are due on the maturity date. The Promissory Notes are convertible, at the holder’s option, into shares of the Company’s common stock at a conversion price of $0.02 per share, at any time during the term of the Promissory Notes. Promissory Notes in the amount of $140,000 are included in Liabilities subject to compromise in the accompanying Balance Sheet.

In accordance with ASC 470 “Debt with Conversion and Other Options” the Company recognized the advantageous value of conversion rights attached to the Promissory Notes. Such rights give the note holder the ability to convert the Promissory Note into common stock at a price per share that is less than the trading price to the public on the day of issuance. The beneficial value in an amount of $105,000, is calculated as the intrinsic value (the market price of the stock at the commitment date in excess of the conversion price) of the beneficial conversion feature of the Promissory Notes and is recorded as interest expense in the accompanying Statements of Operations and as additional paid in capital in the accompanying Balance Sheet.

Note 8—Commitments and Contingencies

Commitments

The Company leased office space under a non-cancelable operating lease that was scheduled to expire on July 31, 2012. In October 2009, in connection with the Company’s bankruptcy petition the Company rejected the office lease. Subsequently the Company reached agreement with the building owner, to continue to occupy the office space on a month to month basis at a significantly reduced rental rate. The building owner has filed a Proof of Claim in the Bankruptcy Court in the amount of $398,128. The Company continues to accrue the full amount of rent expense in accordance with the original lease. As of March 31, 2010 the amount accrued is $129,775.

The Company had entered into CO2 supply agreements with Anadarko and ExxonMobil as discussed in Note 2 above, Each of the CO2 supply agreements contain “take or-pay” provisions under which the Company would be required to accept delivery of certain quantities of CO2 or make cash payments to the sellers in specified amounts. The Exxon Mobil agreement was terminated by ExxonMobil in April 2009. The Anadarko agreement was rejected by the Company in connection with its bankruptcy petition. Anadarko has filed a Proof of Claim with the Bankruptcy Court, in the amount of $54.75 million which they claim represents the termination payment, the value of the overriding royalty interests to be granted to Anadarko and the value of any greenhouse gas reduction rights that would have been conveyed to Anadarko under the terms of the supply agreement. The Company believes Anadarko’s claim is without merit and anticipates vigorously prosecuting an objection to the claim. The Company cannot predict the likelihood any objection to this claim, its possible outcome, or estimate a range of possible loss, if any, that could result in the event of an adverse ruling in any claims objection proceeding. Accordingly, and in accordance with ASC 450, “Contingencies” the Company has not recorded a loss contingency relating to this issue.

Contingencies

As discussed in NOTE 2 - Proceedings Under Chapter 11 of the Bankruptcy Code, the Company is operating as debtor in possession under the provisions of the Bankruptcy Code.

Pending Litigation

On February 12, 2020 the Company filed an adversary action in the Bankruptcy Court against the holder of the senior secured note payable (see NOTE 6 – Short Term Note Payable) seeking to avoid certain ownership interests assigned to the Lender in connection with the Term Credit Agreement and amendments thereto. On March 18, 2010 the Lender filed a motion with the Court to dismiss the complaint. The Company filed its response to the Lender’s motion on March 31, 2010 and oral arguments were made in the Bankruptcy Court on May 10, 2010. The complaint and motions are now under review by the Court.

The lawsuit is in the early stages and the Company is unable to predict a likely outcome or estimate the possible benefit should the Company prevail in the litigation.

Threatened Litigation

In a letter dated February 18, 2009 sent to each of our Directors, attorneys representing a group of persons who purchased approximately $1,800,000 of securities (in the aggregate) in our private placement offering commenced in late 2006 alleged that securities laws were violated in that offering. In April 2009 the Company entered into tolling agreements with the purchasers to toll the statutes of limitations applicable to any claims related to the private placement. The claimants have filed Proofs of Claim with the Bankruptcy Court in the amount of $2,001,050 purported to be damages attributable to the alleged securities violations. These claims are possibly subject to the imposition of section 510 of the Bankruptcy Code, with the result that these claims may be subordinated even in allowed. Accordingly, the Company has not yet determined how such claims might be treated under a proposed plan of reorganization and, therefore, how vigorously the amount of the claims should be contested. Nor can the company predict the likelihood of a lawsuit being filed, its possible outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in any such lawsuit. Accordingly, and in accordance with ASC 450, the Company has not recorded a loss contingency relating to this issue.

F-19

Other

Under the terms of the Term Credit Agreement, See Note 6- Short Term Note Payable, the Company is obligated to reimburse the Lender for all expenses, including reasonable legal fees incurred in connection with the administration, amendment enforcement of the Agreement or Lender’s rights and remedies under the Loan Documents. In connection with the Company’s bankruptcy proceedings, the Lender has incurred legal fees and other expenses that could be covered by the above provisions. As of the date of filing this annual report, the Company has received no formal notification of the amount or nature of such costs, nor can we estimate a range of possible amounts to be reimbursed under the provisions. Accordingly, the Company has not recorded a loss contingency relating to this issue.

Note 9—Stockholders’ Equity

The Company’s capital stock as of March 31, 2010 and 2009 consists of 275,000,000 authorized shares of common stock, par value $0.00001 per share.

Issuance of Common Stock

For the Year Ended March 31, 2010

During the year ended March 31, 2010, activity in the Company’s common stock consisted of the following:

issued 500,000 shares to an officer of the Company upon the exercise of stock options;

cancelled 200,000 of non-vested shares previously issued to directors

For the Year Ended March 31, 2009

During the year ended March 31, 2009, activity in the Company’s common stock consisted of the following:

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

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

Warrants

In connection with sale of common stock and other securities in the fiscal year ended March 31, 2007, the Company issued warrants to purchase shares of common stock. The following is a summary of warrants outstanding as of March 31, 2010:

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

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	1,445,733	$	1.50	March 30, 2012

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

Total warrants outstanding at March 31, 2010	54,632,565

F-20

Registration and Other Payment Arrangements

In connection with the private placement sale of the Company’s common stock and other securities during the fiscal year ended March 31, 2007, the Company entered into Registration Rights Agreements (the “Agreements”) under which the Company agreed to register for resale the shares of common stock issued in the private placement as well as the shares underlying the other securities. Under the terms of the Agreements the Company must pay the holders of the registrable securities issued in the private placement, liquidated damages if the registration statement that was filed in conjunction with the private placement was not declared effective by the U.S. Securities and Exchange Commission (SEC) within 150 days of the closing of the private placement (December 21, 2006). The liquidated damages were due on or before the day of the failure (May 20, 2007) and every 30 days thereafter, or three business days after the failure is cured, if earlier. The amount due was 1% of the aggregate purchase price, or $794,000 per month. If the Company fails to make the payments timely, interest accrues at a rate of 1.5% per month. Payments pursuant to the Registration Rights Agreement and the private placement agreement are limited to 24% of the aggregate purchase price, or $19,057,000 in total. The payment may be made in cash, notes, or shares of common stock, at the Company’s option, as long as the Company does not have an equity condition failure. The Company’s registration statement was not declared effective prior to the May 20, 2007 failure date and pursuant to the terms of the Registration Rights Agreement, the Company opted to pay the liquidated damages in shares of common stock. During the period of non-compliance, from May 20, 2007 until the date the registration statement was declared effective, October 31, 2007, the Company opted to pay the liquidated damages in shares of common stock issuing a total of 9,731,569 shares of common stock valued at $5,463,412.

Since that date the registration statement was declared effective, October 31, 2007,Company has maintained the effectiveness of the registration statement and complied with all other provisions of the Registration Rights Agreement. No further liquidated damages have been assessed or paid. In accordance with FASB ASC 815, ”Derivatives and Hedging” as of the date of this Annual Report, the Company believes the likelihood it will incur additional obligations to pay liquidated damages is remote, as defined in FASB ASC 450 “Contingencies." Accordingly as of March 31, 2010 and 2009, the Company has not recorded a liability for future liquidated damages under the Registration Rights Agreement.

Note 10—Share-Based Compensation

Share-based awards to employees and directors are accounted for under FASB ASC 718 “Share-Based Payment. FASB ASC 718 requires companies to recognize share-based payments to employees as compensation expense using a fair value method. Under the fair value recognition provisions of FASB ASC 718, stock-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as an expense over the service period on a straight-line basis, which generally represents the vesting period. The Company did not recognize a tax benefit from the stock compensation expense because it is more likely than not that the related deferred tax assets, which have been reduced by a full valuation allowance, will not be realized.

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

Prior to the adoption of FASB ASC 718, the Company reflected tax benefits from deductions resulting from the exercise of stock options as operating activities in the statements of cash flows. FASB ASC 718 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 FASB ASC 718. As a result of the Company’s net operating losses, the excess tax benefits, which would otherwise be available to reduce income taxes payable, have the effect of increasing the Company’s net operating loss carry forwards. Accordingly, because the Company is not able to realize these excess tax benefits, such benefits have not been recognized in the statements of cash flows for the years ended March 31, 2010 and 2009.

Chief Executive Officer (CEO) and Non Executive Director Option Grants

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

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 date of grant of the options. The combined value was allocated between the value of the common stock and the value of the warrant. The value of one common share from this analysis ($0.4235) was used to calculate the resulting compensation expense under the provisions of SFAS 123(R). The assumptions used in the valuation of the CEO options were as follows:

Volatility		87.00	%
Expected option term	One 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 $105,875 and $423,500 for the fiscal years ended March 31, 2010 and 2009, respectively. All compensation expense related to the CEO’s options had been recognized prior to the termination of the CEO on October 2, 2009.

On October 27, 2009 in conjunction with the execution of Management Retention Agreements (the “Retention Agreement”), the Company’s new CEO and each of the Company’s three non-executive directors was granted options to purchase 2,500,000 share of the Company’s common stock at an exercise price of $0.035 per share. The options expire on December 31, 2019 and are exercisable 10% on the date of grant and 90% on or after the earliest to occur of: i) November 1, 2010; ii) the confirmation by the court of a Reorganization Plan for the company filed with the Unites States Bankruptcy Court; iii) the dismissal of the Company from Chapter 11 Bankruptcy with approval of the court; iv) an event of merger, consolidation, sale of assets or other transaction which results in the holders of the Company’s common stock immediately after such transaction owning less the 50% of the stock outstanding immediately before the transactions,:v) any other change of Control as described in the Retention Agreement, or vi) a Voluntary Termination for Good Reason, as set forth in the Retention Agreement.

The Company determined the fair value of the options to be $0.0255 per underlying common share. The value was determined by using the Black-Scholes valuation model using the following assumptions:

Volatility		125.14	%
Expected option term	3 years
Risk-free interest rate		5.22	%
Expected dividend yield		0.00	%

The Company recognized stock based compensation expense relating to the new CEO’s and non-executive Director’s options of $121,000 for the year ended March 31, 2010 and expects to recognize the remaining compensation expense of $134,000 relating to the unvested options over the next seven months.

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, 2010 options to purchase 1,700,000 of the Company’s stock were granted to two employees and one non employee under the 2006 Stock Incentive Plan. During the year ended March 31, 2009 no options were granted under the 2006 Stock Incentive Plan.

F-22

The fair value of the options granted during fiscal 2010, 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		125.14	%
Expected option term	3 years
Risk-free interest rate		5.22	%
Expected dividend yield		0.00	%

The expected volatility was based the volatility of the Company’s common stock for a period of time equivalent to the expected term. The expected term of options granted was estimated in accordance with the simplified method prescribed in SEC Staff Accounting Bulletin (“SAB”) No. 107 and SAB No 110. The risk free rate was based on the three-year U.S Treasury note rate

The following table summarizes stock option activity for the year ended March 31, 2010 and 2009:

	2010					2009
	Number of Options			Weighted Average Exercise Price		Number of Options			Weighted Average Exercise Price
Outstanding at beginning of year
Non-qualified		500,000		$	0.00001		1,250,000		$	0.00001
2006 Plan		576,000		$	0.612		1,431,000		$	1.74
Granted
Non-qualified		10,000,000		$	0.035		-			-
2006 Plan		1,700,000		$	0.035		-			-
Exercised
Non-qualified		(500,000	)	$	0.00001		(750,000	)	$	0.00001
2006 Plan		-			-		-			-
Cancelled
Non-qualified		-			-		-			-
2006 Plan		(70,000	)	$	0.984		(855,000	)	$	1.73
Outstanding at March 31
Non-qualified		10,000,000		$	0.035		500,000		$	0.00001
2006 Plan		2,206,000		$	0.154		576,000		$	0.612
Exercisable at March 31
Non-qualified		1,000,000		$	0.035		250,000		$	0.00001
2006 Plan		515,667		$	0.400		210,000		$	0.71

The following table summarizes information related to the outstanding and vested options as of March 31, 2010:

	Outstanding Options			Vested Options
Number of Shares
Non-qualified		10,000,000			1,000,000
2006 Plan		2,206,000			515,667
Weighted Average Remaining Contractual Life
Non-qualified	4.6 years			4.6 years
2006 Plan	4.1 years			3.1 years
Weighted Average Exercise Price
Non-qualified	$	0.035		$	0.035
2006 Plan	$	0.154		$	0.400
Aggregate Intrinsic Value
Non-qualified	$	(200,000	)	$	(20,000	)
2006 Plan	$	(306,490	)	$	(198,602	)

F-23

The following table summarizes changes in the unvested options for the years ended March 31, 2010 and 2009:

	Number of Options			Weighted Average Grant Date Fair Value

Non-vested, April 1, 2008
Non-qualified		1,250,000		$	0.42
2006 Plan		1,001,000		$	0.50
Total		2,251,000			0.46
Granted—
Non-qualified		-			-
2006 Plan		-			-
Total		-			-

Vested—
Non-qualified		(1,000,000	)	$	0.42
2006 Plan		(190,000	)	$	0.28
Total		(1,190,000	)	$	0.40

Cancelled		(445,000	)	$	0.78
Plan
Non-vested, March 31, 2009
Non-qualified		250,000		$	0.42
2006 Plan		366,000		$	0.27
Total		616,000		$	0.33

Granted—
Non-qualified		10,000,000		$	0.02545
2006 Plan		1,700,000		$	0.02545
Total		11,700,000		$	0.02545

Vested—
Non-qualified		(1,250,000	)	$	0.10506
2006 Plan		(338,334	)	$	0.13791
Total		(1,588,334	)	$	0.01121

Cancelled
2006 Plan		(37,333	)	$	0.4996
Non-vested, March 31, 2010
Non-qualified		9,000,000		$	0.02545
2006 Plan		1,690,333		$	0.04514
Total		10,690,333		$	0.02856

The total intrinsic value, calculated as the difference between the exercise price and the market price on the date of exercise of all options exercised during the years ended March 31, 2010 and 2009, was approximately $9,700 and $16,700, respectively. The Company received $5 and $8 from stock options exercised during the year ended March 31, 2010 and 2009, respectively. The Company did not realize any tax deductions related to the exercise of stock options during year.

Total estimated unrecognized compensation cost from unvested stock options as of March 31, 2010 was approximately $41,000 which the Company expects to recognize within the next year

F-24

Note 11—Income Taxes

The effective income tax rate for the years ended March 31, 2010 and 2009 differs from the U.S. Federal statutory income tax rate due to the following:

	For the Year Ended March 31,
	2010			2009

Federal statutory income tax rate	$	7,092,000		$	16,219,000
State income taxes, net of Federal benefit		21,000			49,000
Permanent items		(168,000	)		(18,000	)
Other		68,000			(34,000	)
Change in valuation allowance		(7,013,000	)		(16,216,000	)
	$	-		$	-

The components of the deferred tax assets and liabilities as of March 31, 2010 and 2009 are as follows:

	For the Year Ended March 31,
	2010			2009

Long-term deferred tax assets:
Federal net operating loss carryforwards	$	11,663,000		$	9,266,000
Asset retirement obligation		502,000			449,000
Stock-based compensation		714,000			616,000
Accrued vacation		6,000			22,000
Unrealized hedging losses (gains)		-			(160,000	)
Property , plant and equipment		17,797,000			13,475,000
Valuation allowance		(30,682,000	)		(23,668,000	)
Net long-term deferred tax assets	$	-		$	-

The Company has approximately $ 33,224,000 net operating loss carryover as of March 31, 2010. The net operating losses begin to expire in 2024.

The Company has provided a full valuation allowance for the deferred tax assets as of March 31, 2010 an 2009, based on the likelihood of the realization of the deferred tax assets.

Note 12—Disclosures about Oil and Gas Producing Activities

Costs Incurred in Oil and Gas Producing Activities:

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

	For the Year Ended March 31,
	2010			2009

Exploration	$	19,181		$	20,108
Development		82,963			245,172
Acquisitions:		-			-
Unproved		-			-
Proved		-			-
Total	$	102,144		$	265,280

Costs associated with asset retirement obligations	$	(18,747	)	$	10,481

F-25

Oil and Gas Reserve Quantities (Unaudited):

For the years ended March 31, 2010 and 2009, Ryder Scott Company, L.P. prepared the reserve information for the Company’s Cole Creek South, South Glenrock B, South Glenrock A, and Big Muddy Fields in the Powder River Basin.

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

Proved oil and gas reserves, as defined in Regulation S-X., Rule 4-10(a)(22), proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. All of the Company’s proved reserves are located in the continental United States.

Presented below is a summary of the changes in estimated oil reserves (in barrels) of the Company for the years ended March 31, 2010 and 2009 (the Company does not have any natural gas reserves).

Total proved:	2010			2009
Beginning of year		1,166,702			1,300,396
Purchases, sales and assignments of minerals in-place		(51,235	)		-
Production		(56,818	)		(66,308	)
Revisions of previous estimates		(207,470	)		(67,386
End of year		851,179			1,166,702
Proved developed reserves:		815,138			955,151

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

FASB ASC 932, “Disclosures about Oil and Gas Producing Activities” 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.

In 2010, future cash inflows were determined by applying average first day of month prices received for the previous year, including transportation, quality, and basis differentials (“net prices," and production and development costs in effect at year-end to the year-end estimated quantities of oil and gas to be produced in the future. In 2009, in accordance with the guidelines then in effect, future cash flows were determined by applying end-of-year net prices, production costs and development costs to quantities of oil and gas to be produced in the future. Each property the Company operates is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

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

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process. The price, as adjusted for transportation, quality, and basis differentials, used in the calculation of the standardized measure was $61.66 and $44.75 per barrel of oil for the years ended March 31, 2010 and 2009, respectively. The Company does produce marketable quantities of natural gas.

F-26

The following summary sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in ASC 932:

	As of March 31, 2010			As of March 31, 2009

Future cash inflows	$	54,752,000		$	52,217,000
Future production costs		(34,313,000	)		(29,024,000	)
Future development costs		(600,000	)		(2,007,000	)
Future income taxes		-			-
Future net cash flows		19,839,000			21,186,000
10% annual discount		(10,089,000	)		(12,462,000	)
Standardized measure of discounted future net cash flows	$	9,750,000		$	8,724,000

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

	For the year ended March 31, 2010			For the year ended March 31, 2009

Standardized measure of discounted future net cash flows, beginning of year	$	8,724,000		$	30,928,000
Sales of oil and gas produced, net of production costs		(1,522,000	)		(2,070,000	)
Net changes in prices and production costs		3,114,000			(20,285,000	)
Purchase, sales and assignments of minerals in-place		(661,000	)		-
Revisions of previous quantity estimates		(2,675,000	)		(666,000	)
Changes in future development costs		828,000			-
Accretion of discount		872,000			3,093,000
Changes in timing and other		1,070,000			(2,276,000	)
Standardized measure of discounted future net cash flows, end of year	$	9,750,000		$	8,724,000

F-27

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 13th day of July, 2010.

RANCHER ENERGY CORP.

/s/ Jon C. Nicolaysen

Jon C. Nicolaysen, President, Chief Executive Officer,

Principal Executive Officer,

Director

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/ Jon C. Nicolaysen
Jon C. Nicolaysen	President, Chief Executive Officer, Director	7/13/2010

/s/Richard Kurtenbach
Richard E. Kurtenbach	Chief Accounting Officer and Principal Accounting Officer	7/13/2010

/s/ A.L. Sid Overton
A.L. Sid Overton	Director	7/13/2010

/s/ Mathijs van Houweninge
Mathijs van Houweninge	Secretary, Treasurer, Director	7/13/2010

/s/ Jeffrey B. Bennett
Jeffrey B. Bennett	Director	7/13/2010