T-rex Oil 10K/A 2007 Annual report (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No. 2

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

For the fiscal year ended March 31, 2007

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

For the transition period from __________ to __________

Commission file number: 000-51425

RANCHER ENERGY CORP.

(Exact name of registrant as specified in its charter)

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

999-18th Street, Suite 3400

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

(303) 629-1125

(Telephone number, including area code)

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

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

Title of each class

Common Stock, par value $0.00001 per share

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

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

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

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

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

Large accelerated filer £

Accelerated filer R

Non-accelerated filer £

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

Not Applicable.

EXPLANATORY NOTE

This Amendment No. 2 on Form 10-K/A (this “Amendment”) amends our Form 10-K for the fiscal year ended March 31, 2007, originally filed on June 29, 2007 (the “Original Annual Report”). This Amendment does not amend our Amendment No. 1 on Form 10-K/A for the fiscal year ended March 31, 2007 that was originally filed on July 27, 2007 to include the information required by Part III.

We are filing this Amendment to address matters that were raised by the Securities and Exchange Commission in their comment letter of August 17, 2007 as follows:

Item 1A - Risk Factors provides additional disclosures of the risks associated with our plan to conduct CO₂tertiary recovery operations on older fields that may be significantly depleted of oil, our plan to conduct 3-D seismic surveys to provide additional reservoir information on our fields, our failure to maintain effective internal control over financial reporting, and the removal of the reference to Daniel P. Foley as a member of our management team following his resignation as our Chief Financial Officer;

Item 6 - Selected Financial Data previously provided certain financial information on a combined basis and has been revised to provide required information solely on a separate-entity basis;

Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations previously provided certain financial information on a combined basis and has been revised to limit combined financial information to those items not affected by purchase adjustments (revenues, production taxes and lease operating expenses). In addition, discussion of remaining financial components has been limited to Rancher Energy Corp. We have also provided additional disclosure of the material uncertainties that are associated with the methods, assumptions and estimates regarding our critical accounting policies and estimates. Where applicable, we have also updated forward-looking statements; and

Item 9A - Controls and Procedures provides additional disclosure of the estimated overall costs of implementing corrective measures to address the described material weaknesses.

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

TABLE OF CONTENTS

		PAGE NO.

PART I		1
Item 1A.	Risk Factors.	1

PART II		9
Item 6.	Selected Financial Data.	9
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	11
Item 9A.	Controls and Procedures.	28

PART IV		35
Item 15.	Exhibits, Financial Statement Schedules.	35

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

PART I

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

Risks Related to our Industry, Business, and Strategy

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

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

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

Our long-term growth strategy is focused on our CO₂tertiary recovery operations. The crude oil production from our tertiary recovery projects depends on having access to sufficient amounts of CO₂. Our ability to produce this oil would be hindered if our supply of CO₂ were limited due to problems with the supply, delivery, and quality of the supplied CO₂, problems with our facilities, including compression equipment, or catastrophic pipeline failure. Our agreement with our current sole supplier of CO₂provides that before it delivers CO₂ to us, it may satisfy its own CO₂ needs. If we are not successful in obtaining the required amount of CO₂ to achieve crude oil production or the crude oil production in the future were to decline as a result of a decrease in delivered CO₂ supply, it could have a material adverse effect on our financial condition and results of operations and cash flows.

We plan to conduct our CO₂tertiary recovery operations on older fields that may be significantly depleted of oil, which could lead to an adverse impact on our future results.

We operate three fields in the Powder River Basin, Wyoming. In all three fields oil was discovered years ago and production has been ongoing. Our strategy is to substantially increase production and reserves in these fields by using CO₂injection and other 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 plan to conduct 3-D seismic surveys to provide additional reservoir information on our fields; however, there is no assurance those surveys will allow us to know conclusively if oil is present in economic quantities.

We plan to do various work prior to initiating CO₂injection in the oil fields that we have recently acquired. Among other things, we intend to conduct a 3-D seismic survey on the South Glenrock B and Big Muddy Fields in conjunction with our development program to better determine injection pattern locations and alignment. 3-D seismic surveys are used to provide additional information before undertaking oil operations. However, use of 3-D seismic is an interpretive tool and will not allow us to know conclusively if oil is present, and if present, if it is in economic quantities. Moreover, 3-D seismic survey data is frequently interpreted in different ways by different petroleum professionals. Other petroleum professionals may have materially different interpretations of the same seismic data than we do.

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

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

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

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

·	our proved reserves;

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

·	the prices at which the oil is sold; and

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

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

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

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

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

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

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

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

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

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

We may be unable to develop additional reserves.

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

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

Our success is dependent, in large part, on the continued services of John Works, our President & Chief Executive Officer, John Dobitz, our Senior Vice President, Engineering, and Andrew Casazza, our Chief Operating Officer. There is no guarantee that any of the members of our management team will remain employed by us. While we have employment agreements with them, their continued service cannot be assured. The loss of our senior executives could harm our business.

Oil operations are inherently risky.

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

We are subject to extensive government regulations.

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

·	the prevention of waste;

·	the discharge of materials into the environment;

·	the conservation of oil;

·	pollution;

·	permits for drilling operations;

·	underground gas injection permits;

·	drilling bonds; and

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

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

Government regulation and environmental risks could increase our costs.

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

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

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

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

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

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

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

Oil prices may be impacted adversely by new taxes.

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

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

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

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

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

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

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

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

Risks Related to our Common Stock

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

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

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

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

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

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

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

·	Actual or anticipated quarterly variations in our operating results;

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

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

·	Conditions generally affecting the oil & gas industry;

·	The success of our operating strategy; and

·	The operating and stock performance of other comparable companies.

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

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

Some of the information in this Amendment and in the Original 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 Amendment and in the Original Annual Report, provide examples of risks, uncertainties, and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements. The occurrence of the events described in these risk factors could have an adverse effect on our business, results of operations, and financial condition.

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 Item 9A of this report, we report the determination of our management that we have material weaknesses in our internal control over financial reporting. The determination was made by management that: (a) our operating environment did not sufficiently promote effective internal control over financial reporting throughout the organization, (b) we did not have a sufficient complement of personnel with appropriate training and experience in generally accepted accounting principles (GAAP), and (c) we did not adequately segregate duties of different personnel in our accounting department due to an insufficient complement of staff and inadequate management oversight. We are taking steps to remediate the material weaknesses. If we fail to correct the material weaknesses in our internal control over financial reporting, our business could be harmed and the stock price of our common stock could be adversely affected.

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

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

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

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

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

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

PART II

ITEM 6. SELECTED FINANCIAL DATA.

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

The following selected financial data reflects the following:

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

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

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

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

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

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

Total assets (as of period end)		81,478,031			46,557			4,749			-

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

Total assets (as of period end)		14,597,618			13,058,437

								For the Period from January 1, 2004 through August 31, 2004
Pre-Predecessor:
Revenues							$	440,383
Production taxes								204,454
Lease operating expenses								47,033
Excess of revenues over expenses								188,896

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

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

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

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

Organization

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

Oil & Gas Property Acquisitions

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

Cole Creek South Field and South Glenrock B Field Acquisitions

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

The total adjusted purchase price was allocated as follows:

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

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

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

The South Glenrock B Field is also located in Converse County, Wyoming. The field was discovered in 1950 by Conoco, Inc. Bisected by Interstate 25, the field produces from the Dakota and Muddy sandstone reservoirs that are draped over a structural nose with 2,000 feet of relief. Production is maintained by secondary recovery efforts that were initiated in 1961. In March 2007, production from the South Glenrock B Field was approximately 199 BOPD gross, and 152 BOPD net to our interests, of primarily 35 degree API sweet crude oil.

Big Muddy Field Acquisition

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

The total adjusted purchase price was allocated as follows:

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

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

Water flooding was initiated in the Frontier formation in 1957 and later expanded to the Dakota and Lakota formations. Over 800 completions have occurred in the field. At the current time, only a few wells are active. Production in March 2007 was approximately 18 BOPD gross, and 14 BOPD net to our interests, of primarily 36 degree API sweet crude oil.

Outlook for the Coming Year

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

	·	Borrow funds to implement our development plans;

	·	Construct a CO₂ pipeline;

	·	Initiate development activities in our fields; and

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

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

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

We plan to begin CO₂ development operations in the South Glenrock B Field, and preliminary development in the Big Muddy Field. We also plan to make capital expenditures relating to existing production in the three fields. If we obtain additional financing by October 2007, we plan to make capital expenditures for CO₂pipeline construction, field development, and CO₂purchases totaling approximately $90 million in the fiscal year ending March 31, 2008, and an additional $120 million in the fiscal year ending March 31, 2009. Of the fiscal year 2008 costs, about $65 million is projected for the South Glenrock B Field and Big Muddy Field projects, with about two-thirds of this cost for 3-D seismic, and well drilling and conversion for CO₂ injection, and the remainder for compressors and facilities. Since the acquisition of the three fields, other than the agreement with Anadarko for supply of CO₂, we have made no major capital expenditures nor any firm commitments for future capital expenditures to date.

Commitments

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

The primary term of the Purchase Contract commences upon the later of January 1, 2008, or the date of the first CO₂delivery, and terminates upon the earlier of the day on which we have taken and paid for the Total Contract Quantity, as defined, or 10 years from the commencement date. We have the right to terminate the Purchase Contract at any time with notice to Anadarko, subject to a termination payment as specified in the Purchase Contract.

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

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

Results of Operations, Including Combined Results

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

The following data includes:

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

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

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

Adjustments to eliminate the Predecessor’s revenues, production taxes and lease operating expenses for the three months ended March 31, 2006 from the Predecessor revenues, production taxes and lease operating expenses for the year ended December 31, 2006, so that the combined information reflects the revenues, production taxes and lease operating expenses for the fiscal year ended March 31, 2007; and

Combined revenues, production taxes and lease operating expenses for the years ended March 31, 2007, 2006 and 2005.

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

Operating expenses:
Production taxes		136,305			493,956			(120,313	)		509,948
Lease operating expenses		700,623			2,944,287			(574,756	)		3,070,154
Depreciation, depletion, and amortization		375,701			952,784
Impairment of unproved properties		734,383			-
Accretion expense		29,730			107,504
Exploration expense		333,919			-
General and administrative		4,501,737			567,524
Total operating expenses		6,812,398			5,066,055

		(5,650,579	)		(577,740	)

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

	$	(8,702,255	)	$	(577,740	)

Adjustments:

Revenue, production taxes, and lease operating expenses - represents oil production volumes, oil sales, production taxes, and lease operating expenses for the three months ended March 31, 2006 to derive combined oil production volumes, oil sales, production taxes, and lease operating expenses for the year ended March 31, 2007.

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

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

	$	(124,453	)	$	26,886

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

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

	$	(27,154	)	$	(78,415	)

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

Rancher Energy Corp.

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

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

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

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

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

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

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

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

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

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

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

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

Rancher Energy Corp. Combined With Predecessor and Pre-Predecessor

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

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

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

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

Liquidity and Capital Resources

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

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

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

We are making plans to seek a debt financing (Debt Financing) in an amount sufficient to fund our expected expenditures in furtherance of our EOR plans. In the interim, we will likely seek a bridge debt financing (Bridge Financing).

Completion of the Bridge Financing and Debt Financing will be subject to market conditions and Company-specific factors. Without receipt of proceeds from these facilities, the Company’s negative cash flow is projected to be covered by available cash through the third quarter of calendar year 2007. However, in the event we are not successful in raising either the Bridge Financing or the Debt Financing, we do not plan to allow negative monthly cash flow to remain at current levels. Rather, we plan to address the situation at that time by reducing staffing levels to reduce cash requirements and potentially, if available, by using proceeds of a senior revolving debt facility supported by our proved producing reserves to increase near-term production rates and cash flow.

Change in Financial Condition

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

Convertible Debt Transactions

Venture Capital First LLC

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

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

Private Placement - Convertible Notes Payable

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

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

Equity Transactions

Units Issued Pursuant to Regulation S

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

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

Warrant Modification - Warrants Issued Pursuant to Regulation S

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

Private Placement

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

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

Summary of Warrants

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

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

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

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

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

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

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

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

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

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

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

Cash Flows

The following is a summary of our comparative cash flows:

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

Analysis of Cash Flow Changes between 2007 and 2006

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

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

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

Capital Expenditures

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

	For the Year Ended March 31,
	2007		2006		2005

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

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

Schedule of Contractual Obligations

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

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

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

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

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

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

•

the quality and quantity of available data;

	•	the interpretation of that data;
	•	the accuracy of various mandated economic assumptions; and
	•	the judgment of the independent reserve engineer.

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

Successful efforts method. We use the successful efforts method of accounting for our oil and natural gas properties under Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies. Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether or not the well is economically productive or nonproductive.

If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in the Statement of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of the Statement of Cash Flows in the period in which the determination was made. If a determination cannot be made within one year of the exploration well being drilled and no other drilling or exploration activities to evaluate the discovery are firmly planned, all previously capitalized costs associated with the exploratory well would be expensed and shown as a non-cash adjustment to net income in the “Operating activities” section of the Statement of Cash Flows in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well would be classified as development or exploratory based on whether it is in a proved or unproved reservoir for determination of capital or expense. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures would be charged to expense.

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

Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of total proved developed reserves or proved reserves, as applicable. Natural gas volumes are converted to BOE at the rate of six Mcf to one barrel of oil. Significant revisions to reserve estimates can be and are made by our reserve engineers each year. Mostly these are the result of changes in price, but as reserve quantities are estimates, they can also change as more or better information is collected, especially in the case of estimates in newer fields. Downward revisions have the effect of increasing our DD&A rate, while upward revisions have the effect of decreasing our DD&A rate.

The costs of retired, sold or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to the accumulated DD&A reserve. Gains or losses from the disposal of other properties are recognized in the current period.

Valuation of long-lived and intangible assets. In accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, an impairment of capitalized costs of long-lived assets to be held and used, including proved oil and natural gas properties, must be assessed whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. Expected future net cash flows are based on existing proved reserve and production information and pricing assumptions that management believes are reasonable. Any impairment charge incurred is expensed and reduces our recorded basis in the asset pool. Management currently aggregates proved property for impairment testing for the Company using only one pool of assets due to the geologic similarity and proximity of the properties. The price assumptions used to calculate undiscounted cash flows are based on judgment. We use prices consistent with the prices used in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment while higher prices would have the opposite effect.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Currently, there are no equity conditions failures.

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

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

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

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

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

ITEM 9A. CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures.

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

Our estimate of the overall cost of implementing corrective measures is approximately $300,000. The costs will be incurred in three main areas, (i) outside consultant assistance in design and documentation, (ii) increased human resources to maintain controls and updates, and (iii) increased GAAP expertise through training and consultants.

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

Management’s Annual Report on Internal Control over Financial Reporting

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

·	Establish and maintain adequate internal control over financial reporting,

·	Assess the effectiveness of internal control over financing reporting,

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

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

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

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

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

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

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

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

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

The change in operating environment is evidenced by the following:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Changes in Internal Control over Financial Reporting

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

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Rancher Energy Corp.

Denver, Colorado

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

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

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

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

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

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

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

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

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

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

/s/ HEIN & ASSOCIATES LLP

Denver, Colorado

June 28, 2007

PART IV

ITEM 15. EXHIBITS, Financial Statement Schedules.

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

(3) Exhibits. The exhibits filed as part of this Amendment No. 2 on Form 10-K/A are reflected on the Exhibit Index following the signature page.

SIGNATURES

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

		RANCHER ENERGY CORP. (Registrant)

Date: September 7, 2007	By:	/s/ John Works
		John Works
		President, Chief Executive Officer, Principal Executive Officer, Chief Financial Officer, Principal Financial Officer, Director, Secretary, and Treasurer

EXHIBIT INDEX

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

E-1

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

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

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

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

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

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

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

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

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

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

E-2

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

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

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

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

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

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

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

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

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

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

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

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

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

(23)	Filed herewith.

E-3

T-rex Oil Inactive 10-K/A2007 FY Annual report (amended)