T-REX OIL, INC. - Quarter Report: 2008 December (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the quarterly period ended December 31, 2008

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

For the transition period from _____________ to ___________________.

Commission file number: 000-51425

Rancher Energy Corp.

(Exact name of registrant as specified in its charter)

Nevada	98-0422451
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
999 - 18th Street, Suite 3400 Denver, CO 80202 (Address of principal executive offices) (303) 629-1125 (Registrant’s telephone number, including area code)

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

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

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

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

As of January 19, 2009, 119,016,723 shares of Rancher Energy Corp. common stock, $.00001 par value, were outstanding.

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Rancher Energy Corp.

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	PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of December 31, 2008 and March 31, 2008	03

	Consolidated Statements of Operations for the Three Months and Nine Months ended December 31, 2008 and 2007	05

	Consolidated Statement of Changes in Stockholders’ Equity as of December 31, 2008	06

	Consolidated Statements of Cash Flows for the Nine Months ended December 31, 2008 and 2007	07

	Notes to Consolidated Financial Statements	08

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25

Item 4.	Controls and Procedures	26

	PART II - OTHER INFORMATION

Item 1A.	Risk Factors	26

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	26

Item 6.	Exhibits	27

SIGNATURES		29

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PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements

Rancher Energy Corp.

Consolidated Balance Sheets

ASSETS

	December 31, 2008			March 31, 2008

Current assets:
Cash and cash equivalents	$	1,431,589		$	6,842,365
Accounts receivable and prepaid expenses		621,072			1,170,641
Derivative receivable		731,183			—
Total current assets		2,783,844			8,013,006

Oil and gas properties at cost (successful efforts method):
Unproved		53,319,816			54,058,073
Proved		20,642,182			20,734,143
Less: Accumulated depletion, depreciation, amortization and impairment		(41,615,882	)		(1,531,619	)
Net oil and gas properties		32,346,116			73,260,597

Other assets:
Furniture and equipment net of accumulated depreciation of $333,743 and $277,420, respectively		818,007			997,196
Other assets		1,015,637			1,300,382
Total other assets		1,833,644			2,297,578
Total assets	$	36,963,604		$	83,571,181

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

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Rancher Energy Corp.

Consolidated Balance Sheets

LIABILITIES AND STOCKHOLDERS’ EQUITY

	December 31, 2008			March 31, 2008

Current liabilities:
Accounts payable and accrued liabilities	$	703,765		$	2,114,204
Accrued oil and gas property costs		250,000			250,000
Asset retirement obligation		320,768			337,685
Note payable, net of unamortized discount of $663,158 and $2,527,550, respectively		9,336,842			9,712,450
Derivative liability		—			590,480
Total current liabilities		10,611,375			13,004,819

Long-term liabilities:
Derivative liability		—			246,553
Asset retirement obligation		952,686			922,166
Total long-term liabilities		952,686			1,168,719

Commitments and contingencies		—			—

Stockholders’ equity:
Common stock, $0.00001 par value, 275,000,000 shares authorized; 119,016,700 and 114,878,341 shares issued and outstanding at December 31 and March 31, 2008, respectively		1,191			1,150
Additional paid-in capital		92,438,678			91,790,181
Accumulated deficit		(67,040,326	)		(22,393,688	)
Total stockholders’ equity		25,399,543			69,397,643

Total liabilities and stockholders’ equity	$	36,963,604		$	83,571,181

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

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Rancher Energy Corp.

Consolidated Statements of Operations

	Three Months Ended December 31,						Nine Months Ended December 31,
	2008			2007			2008			2007

Revenues:
Oil & gas sales	$	746,967		$	1,704,267		$	4,641,836		$	4,685,373
Derivative gains (losses)		1,586,911			(636,109	)		997,169			(636,109	)
		2,333,878			1,068,158			5,639,005			4,049,264
Operating expenses:											—
Production taxes		90,940			207,588			564,590			570,239
Lease operating expenses		831,559			808,091			2,004,422			2,087,753
Depreciation, depletion and amortization		350,847			330,612			928,395			1,030,868
Impairment		32,500,000			—			39,300,000			—
Accretion expense		40,661			(11,221	)		117,771			66,387
Exploration expense		4,293			55,945			13,896			186,772
General and administrative		780,261			1,735,482			2,788,415			5,788,574
Total operating expenses		34,598,561			3,126,497			45,717,489			9,730,593

Loss from operations		(32,264,683	)		(2,058,339	)		(40,078,484	)		(5,681,329	)

Other income (expense):
Liquidated damages pursuant to registration rights arrangement		—			—			—			(2,645,393	)
Amortization of deferred finance costs and discount on note payable		(848,696	)		(901,456	)		(3,524,399	)		(1,000,709	)
Interest and other income		6,811			95,982			26,129			169,846
Interest expense		(323,190	)		(441,528	)		(1,069,884	)		(554,708	)

Total other income (expense)		(1,165,075	)		(1,247,002	)		(4,568,154	)		(4,030,964	)

Net loss	$	(33,429,758	)	$	(3,305,341	)	$	(44,646,638	)	$	($9,712,293	)

Basic and diluted net loss per share	$	(0.29	)	$	(0.03	)	$	(0.39	)	$	(0.09	)

Basic and diluted weighted average shares outstanding		116,196,049			113,471,032			115,541,973			108,425,299

The accompanying notes are an integral part of these financial statements

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Rancher Energy Corp.

Consolidated Statement of Changes in Stockholders’ Equity

(Unaudited)

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

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

Stock issued upon exercise of stock options		750,000		7		—		—			7

Common stock exchanged for services – non-employee directors		3,388,359		34		217,466		—			217,500

Stock-based compensation		—		—		353,481		—			353,481

Amortization of deferred compensation		—		—		77,550		—			77,550

Net loss		—		—		—		(44,646,638	)		(44,646,638	)

Balance, December 31, 2008		119,016,700	$	1,191	$	92,438,678	$	(67,040,326	)	$	25,399,543

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

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Rancher Energy Corp.

Consolidated Statements of Cash Flows

	Nine Months Ended December 31,
	2008			2007
Cash flows from operating activities:
Net loss	$	(44,646,638	)	$	(9,712,293	)
Adjustments to reconcile net loss to cash used for operating activities:
Loss on sale of assets		35,797			—
Depreciation, depletion, and amortization		928,395			1,030,868
Impairment of unproved properties		39,300,000			—
Accretion Expense		117,771			66,387
Settlement of asset retirement obligation		(146,401	)		(18,318	)
Liquidated damages pursuant to registration rights arrangement		—			2,645,393
Imputed interest on registration rights arrangement payments		—			112,489
Amortization of deferred financing costs and discount on note payable		3,524,398			1,132,050

Unrealized (gains) losses on crude oil hedges		(836,907	)		578,435
Stock-based compensation expense		353,481			864,143
Restricted stock compensation expense		77,550			180,950
Services exchanged for common stock – non-employee directors		217,500			222,750
Services exchanged for common stock – non-employee		—			112,500
Changes in operating assets and liabilities:
Accounts receivable		(420,232	)		(260,853	)
Prepaid expenses		238,616			(560,321	)
Other assets		—
Accounts payable and accrued liabilities		(1,142,448	)		45,758
Net cash used for operating activities		(2,399,118	)		(3,560,062	)

Cash flows from investing activities:
Capital expenditures for oil and gas properties		(230,087	)		(2,087,871	)
Proceeds from conveyance of unproved oil and gas properties		—			491,500
Increase in other assets		(440,101	)		(797,432	)
Net cash used for investing activities		(670,188	)		(2,393,803	)

Cash flows from financing activities:
Payment of deferred financing costs		(101,478	)		(862,577	)
Proceeds from borrowings		—			12,240,000
Proceeds from issuance of common stock upon exercise of stock options		8			15
Repayment of debt		(2,240,000	)		—
Payment of offering costs		—			(300,365	)
Net cash provided by (used for) financing activities		(2,341,470	)		11,077,073

Increase (decrease) in cash and cash equivalents		(5,410,776	)		5,123,208
Cash and cash equivalents, beginning of period		6,842,365			5,129,883

Cash and cash equivalents, end of period	$	1,431,589		$	10,253,091

Supplemental schedule of additional cash flow information and non-cash investing and financing activities:
Cash paid for interest	$	1,069,733		$	442,108
Payables settled for oil and gas properties	$	53,799		$	118,023
Asset retirement asset and obligation	$	43,493		$	18,743
Common stock issued on payment of liquidated damages pursuant to registration rights arrangement		—		$	5,463,412
Discount on note payable, conveyance of overriding royalty interest	$	1,050,000		$	4,500,000

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Rancher Energy Corp.

Notes to Consolidated Financial Statements

Note 1 – Organization and Summary of Significant Accounting Policies

Organization

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

Basis of Presentation

The accompanying unaudited consolidated financial statements include the accounts of the Company’s wholly owned subsidiary, Rancher Energy Wyoming, LLC, a Wyoming limited liability company that was formed on April 24, 2007. In management’s opinion, the Company has made all adjustments, consisting of only normal recurring adjustments, necessary for a fair presentation of financial position, results of operations, and cash flows. The consolidated financial statements should be read in conjunction with financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2008. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information. They do not include all information and notes required by generally accepted accounting principles for complete financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2008. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

The accompanying financial statements have been prepared on the basis of accounting principles applicable to a going concern, which contemplates the realization of assets and extinguishment of liabilities in the normal course of business. As shown in the accompanying financial statements, the Company has incurred a cumulative net loss of $67.0 million for the period from inception (February 4, 2004) to December 31, 2008, and it has a working capital deficit of approximately $7.8 million as of December 31, 2008. On October 22, 2008, the Company made a principal payment on its short term debt, scheduled to mature on October 31, 2008, and extended the maturity of the remaining $10,000,000 balance until April 30, 2009. The Company will require significant additional funding to repay this debt on the new maturity date, and for its planned oil and gas development operations. The Company’s ability to continue the Company as a going concern is dependent upon its ability to obtain additional funding in order to finance its planned operations. The accompanying financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

Use of Estimates in the Preparation of Financial Statements

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

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Oil and Gas Producing Activities

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

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

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

The Company reviews its long-lived assets for impairments when events or changes in circumstances indicate that impairment may have occurred. The impairment test for proved properties compares the expected undiscounted future net cash flows on a property-by-property basis with the related net capitalized costs, including costs associated with asset retirement obligations, at the end of each reporting period. Expected future cash flows are calculated on all proved reserves using a discount rate and price forecasts selected by the Company’s management. The discount rate is a rate that management believes is representative of current market conditions. The price forecast is based on NYMEX strip pricing, adjusted for basis and quality differentials, for the first three to five years and is held constant thereafter. Operating costs are also adjusted as deemed appropriate for these estimates. When the net capitalized costs exceed the undiscounted future net revenues of a field, the cost of the field is reduced to fair value, which is determined using discounted future net revenues. The Company has recorded no impairment on its proved properties. An impairment allowance is provided on unproved property when the Company determines the property will not be developed or the carrying value is not realizable. Recent global market conditions and declining commodity prices have negatively impacted the valuation of the Company’s unproved oil and gas properties. During the nine months ended December 31, 2008 the Company recognized impairment of unproved properties of $39,300,000, representing the excess of the carrying value over the estimated realizable value of such property.

Capitalized Interest

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

Commodity Derivatives

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

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

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

The table below summarizes the realized and unrealized losses related to the Company’s derivative instruments for the three and nine months ended December 31, 2008 and 2007.

	Three Months Ended December 31,					Nine Months Ended December 31,
	2008		2007			2008			2007
Realized gains (losses) on derivative instruments	$	144,285	$	(57,674	)	$	(505,623	)	$	(57,674	)
Unrealized gains (losses) on derivative instruments		1,442,626		(578,435	)		1,502,792		$	(578,435	)
Total realized and unrealized gains (losses) recorded	$	1,586,911	$	(636,109	)	$	997,169		$	(636,109	)

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

Contract Feature	Contract Term	Total Volume Hedged (Bbls)		Remaining Volume Hedged (Bbls)		Index	Fixed Price ($/Bbl)		Position at December 31, 2008 Due To (From) Company
Put	Nov 07—Oct 09		113,220		45,611	WTI NYMEX	$	65.00	$	739,183
Call	Nov 07—Oct 09		67,935		27,368	WTI NYMEX	$	83.50		—

The Company established the fair value of its derivative instruments using a published index price, the Black-Scholes option-pricing model and other factors including volatility, time value and the counterparty’s credit adjusted risk free interest rate. The actual contribution to the Company’s future results of operations will be based on the market prices at the time of settlement and may be more or less than the value estimates used at December 31, 2008.

Other Significant Accounting Policies

Other accounting policies followed by the Company are set forth in Note 1 to the Consolidated Financial Statements included in its Annual Report on Form 10-K for the year ended March 31, 2008, and are supplemented in the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for the nine months ended December 31, 2008. These unaudited consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in the Annual Report on Form 10-K for the year ended March 31, 2008.

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Net Loss Per Share

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

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

The treasury stock method is used to measure the dilutive impact of stock options and warrants. For the nine months ended December 31, 2008 and 2007, anti-dilutive stock options and warrants of 70,314,465 and 80,473,550, respectively have been omitted from the earnings per share computation.

Reclassification

Certain amounts in the 2007 financial statements have been reclassified to conform to the 2008 financial statement presentation. Such reclassification had no effect on net loss.

Recent Accounting Pronouncements

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

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

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired, and establishes that acquisition costs will be generally expensed as incurred. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008, which will be the Company’s year beginning April 1, 2009. The Company is currently evaluating the potential impact, if any, of the adoption of SFAS No. 141R on its future financial reporting.

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In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—Amendments of ARB No. 51.” SFAS No. 160 states that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which corresponds to the Company’s year beginning January 1, 2009. The Company is currently evaluating the potential impact, if any, of the adoption of SFAS No. 160 on its future financial reporting.

On March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” which amends SFAS No. 133 by requiring expanded disclosures about an entity’s derivative instruments and hedging activities, but does not change SFAS No. 133’s scope or accounting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption permitted. The Company is currently evaluating the potential impact, if any, of the adoption of SFAS No. 161 on its future financial reporting.

In May 2008, the FASB issued FSP 14-1 "Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) ". FSP 14-1 requires the issuer of certain convertible debt instruments that may be settled in cash (or other assets) on conversion to separately account for the liability (debt) and equity (conversion option) components of the instrument in a manner that reflects the issuer's non-convertible debt borrowing rate. FSP 14-1 is effective for fiscal years beginning after December 15, 2008, on a retroactive basis. The Company has not yet determined the impact that the implementation of FSP 14-1 will have on its consolidated financial position, results of operations or cash flows.

Other recent accounting pronouncements issued by the FASB (including its Emerging Issues Task Force), the AICPA, and the SEC did not, or are not believed by management to have a material impact on the Company’s present or future consolidated financial statements.

Note 2 – Oil and Gas Properties

Acquisitions

In December 2006 and January 2007 the Company purchased oil and gas properties in Wyoming’s Powder River Basin area, consisting of the Cole Creek South Field, the South Glenrock B Field and the Big Muddy Field. The total purchase price for the three fields was $71.8 million plus acquisition and closing costs of $1.6 million. The Company’s business plan includes the injection of CO2 into its three oil fields and the Company has entered into two separate CO2 agreements as more fully described in the Company’s Annual Report on Form 10-K for the year ended March 31, 2008.

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

	December 31,			March 31,
	2008			2008
Proved properties	$	20,642,182		$	20,734,143

Unproved properties excluded from DD&A		52,948,655			53,655,471
Equipment and other		371,161			402,602
Subtotal Unevaluated Properties		53,319,816			54,058,073
Total oil and gas properties		73,961,998			74,792,216
Less accumulated depletion, depreciation, amortization and impairment		(41,615,882	)		(1,531,619	)
	$	32,346,116		$	73,260,597

Impairment of Unproved Properties

In conjunction with the periodic assessment of impairment of unproved properties, the Company re-evaluated the carrying value of its unproved properties giving consideration to lower commodity prices and the difficulties encountered in raising capital to develop the properties. Accordingly, during the nine months ended December 31, 2008 the Company recorded $39,300,000 of impairment expense on unproved properties, reflecting the excess of the carrying value over estimated realizable value of the assets. The Company recognized no impairment in the corresponding periods of 2007.

Exploration of Strategic Alternatives

In August 2008, the Company retained Growth Capital Partners, L.P. as its financial advisor to assist in exploring financing and other strategic alternatives, including the possible sale of the Company. We have been unsuccessful in completing a strategic transaction. Our ability to survive will be dependent upon completing a strategic transaction; however, there is no assurance any such transaction will be completed.

Note 3 – Asset Retirement Obligations

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

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

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A reconciliation of the Company’s asset retirement obligation liability during the nine months ended December 31 is as follows:

	2008			2007
Balance, April 1	$	1,259,851		$	1,221,567
Liabilities incurred		—
Liabilities settled		(147,661	)		(18,318	)
Changes in estimates		43,493			—
Accretion expense		117,771			66,387
Balance, December 30	$	1,273,454		$	1,269,636

Current	$	320,768		$	564,308
Long-term		952,686			705,328

	$	1,273,454		$	1,269,636

Note 4 – Fair Value Measurements

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

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

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

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

SFAS No. 157 requires financial assets and liabilities to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Assets:
Derivative instrument	$	—	$	—	$	731,183
Liabilities:

The Company’s sole derivative financial instrument is a participating cap costless collar agreement. The fair value of the costless collar agreement is determined based on both observable and unobservable pricing inputs and therefore, the data sources utilized in these valuation models are considered level 3 inputs in the fair value hierarchy. In the Company's adoption of SFAS No. 157, it considered the impact of counterparty credit risk in the valuation of its assets and its own credit risk in the valuation of its liabilities that are presented at fair value.

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

	Derivatives				Total
Balance as of April 1, 2008, asset, (liability)		$	(836,907	)		$	(836,907	)
Total gains (losses) (realized or unrealized):
Included in earnings			997,169				997,169
Included in other comprehensive income
Purchases, issuances and settlements			680,223				680,223
Transfers in and out of Level 3

Balance as of December 31, 2008		$	840,485			$	840,485

Change in unrealized gains (losses) included in earnings relating to derivatives still held as of December 31, 2008		$	1,677,392			$	1,677,392

Note 5 – Short-term Note Payable

On October 16, 2007, the Company borrowed $12,240,000 pursuant to a Term Credit Agreement (the “Credit Agreement”) with a financial institution (the Lender), which was amended on October 22, 2008 (the “First Amendment”) . The First Amendment extended for six months the maturity date under the Term Credit Agreement of October 31, 2008 to April 30, 2009. In consideration of the six month extension and other terms included in First Amendment, the Company made a principal payment to the Lender in the amount of $2,240,000, resulting in a new loan balance of $10,000,000, and granted an increase in the proportionate overriding royalty interests (“ORRI”) assigned to the Lender from 2% to 3%. Under the terms of the First Amendment, the Company has the right to buy back one-third (1/3) of the ORRI at a repurchase price calculated to ensure that total payments by the Company to the Lender of principal, interest, ORRI revenues, and ORRI repurchase price will equal 140% of the original loan amount. The Company also has the right to apply the three months interest held in escrow under the terms of the original Term Credit Agreement, against the final three months interest payments due in February, March and April, 2009.

All amounts outstanding under the Credit Agreement, as amended, are due and payable on

April 30, 2009 with interest at a rate equal to the greater of (a) 12% per annum and (b) the one-month LIBOR rate plus 6% per annum. The Company is required to make monthly interest payments on the amounts outstanding under the Credit Agreement, but is not required to make any principal payments until the maturity date. The Company may prepay the amounts outstanding under the Credit Agreement at any time without penalty.

The Company’s obligations under the Credit Agreement are collateralized by a first priority security interest in its properties and assets, including all rights under oil and gas leases in its three producing oil fields in the Powder River Basin of Wyoming and all of its equipment on those properties. Under the terms of the original Credit agreement, the Company granted the Lender a 2% Overriding Royalty Interest (ORRI), proportionally reduced when the Company’s working interest is less than 100%, in all crude oil and natural gas produced from its three Powder River Basin fields. The Company estimated that the fair value of the ORRI granted to the Lender was approximately $4,500,000 and has recorded this amount as a discount to the Note Payable and as a decrease of oil and gas properties. Under the terms of the First Amendment the Company granted an additional 1% ORRI, proportionally reduced when the Company’s working interest is less than 100%, in all crude oil and natural gas produced from its three fields. The Company estimated that the fair value of the ORRI granted to the Lender was approximately $1,050,000 and has recorded this amount as a discount to the Note Payable and as a decrease of oil and gas properties. Amortization of the discount based upon the effective interest method in the amount of $752,965 and $2,914,392 is included in the Company’s statements of operations as amortization of deferred financing costs and discount on note payable for the three and nine months ended December 31, 2008, respectively. As long as any of its obligations remain outstanding under the Credit Agreement, the Company will be required to grant the same ORRI to the Lender on any new working interests acquired after closing. Prior to the maturity date, the Company may re-acquire 1/3 of the ORRI granted to the Lender at a repurchase price calculated to ensure that total payments by the Company to the Lender of principal, interest, ORRI revenues, and ORRI repurchase price will equal 140% of the loan amount.

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

The Company is subject to various restrictive covenants under the Credit Agreement, including limitations on its ability to sell properties and assets, pay dividends, extend credit, amend material contracts, incur indebtedness, provide guarantees, effect mergers or acquisitions (other than to change its state of incorporation), cancel claims, create liens, create subsidiaries, amend its formation documents, make investments, enter into transactions with its affiliates, and enter into swap agreements. The Company must maintain (a) a current ratio of at least 1.0 (excluding from the calculation of current liabilities any loans outstanding under the Credit Agreement) and (b) a loan-to-value ratio greater than 1.0 to 1.0 for the term of the loan. As of December 31, 2008 the Company is in compliance with all covenants under the Credit Agreement.

Note 6 – Income Taxes

As of December 31, 2008, because the Company believes that it is more likely than not that its net deferred tax assets, consisting primarily of net operating losses, will not be utilized in the future, the Company has fully provided for a valuation of its net deferred tax assets.

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

Note 7 – Common Stock

The Company’s capital stock as of December 31, 2008 and 2007 consists of 275,000,000 authorized shares of common stock, par value $0.00001 per share.

Issuance of Common Stock

For the Nine Months Ended December 31, 2008

During the nine months ended December 31, 2008, the Company issued common stock as follows:

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

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

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Note 8 – Share-Based Compensation

Chief Executive Officer (CEO) Options

During the nine months ended December 31, 2008, the Company’s CEO exercised options to acquire 750,000 shares of common stock, for a cumulative exercise price of $7.50 ($0.00001/share).

2006 Stock Incentive Plan

There were no options to purchase shares of common stock granted during the nine months ended December 31, 2008. During the nine months ended December 31, 2008, options to purchase 852,667 shares of common stock granted to employees expired. The options had exercise prices of $1.18 to $1.75.

Total estimated unrecognized compensation cost from unvested stock options as of December 31, 2008 was approximately $103,000 which the Company expects to recognize over 3.3 years. As of December 31, 2008 there were 577,000 options outstanding under the 2006 Stock Incentive Plan and 9,423,000 options are available for issuance.

Restricted Stock Award

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

On May 22, 2007, the Company issued 400,000 shares of common stock to the four new board members, and on June 26, 2007, the Company issued 100,000 shares of common stock to the remaining independent Board member. Pursuant to the vesting discussed above, for the nine months ended December 31, 2008, $77,550 has been reflected as a charge to general and administrative expense in the statement of operations, with a corresponding credit to additional paid-in capital.

Board of Director Fees

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

For the nine months ended December 31, 2008, board members elected to receive 3,388,359 shares of common stock, respectively, in lieu of cash, ranging in value from $0.31 to $0.03 per share, representing the closing price of the Company’s stock on the date of grant. Total compensation for the nine months ended December 31, 2008 of $218,500 has been reflected as a charge to general and administrative expense in the statement of operations, with a corresponding credit to common stock and additional paid-in capital.

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

Forward-Looking Statements

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

·	business strategy;

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

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

·	water availability and waterflood production targets;

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

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

·	inventories, projects, and programs;

·	other anticipated capital expenditures and budgets;

·	future cash flows and borrowings;

·	the availability and terms of financing;

·	oil reserves;

·	reservoir response to water and CO2 injection;

·	ability to obtain permits and governmental approvals;

·	technology;

·	financial strategy;

·	realized oil prices;

·	production;

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

·	availability and costs of drilling rigs and field services;

·	future operating results;

·	plans, objectives, expectations, and intentions; and

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

The forward-looking statements contained in this Quarterly Report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” section and elsewhere in our Annual Report on Form 10-K for the year ended March 31, 2008. All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Organization

Rancher Energy is an independent energy company which explores for and develops, produces, and markets oil and gas in North America. Prior to April 2006, Rancher Energy, 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. We operate three fields in the Powder River Basin, Wyoming, which is located in the Rocky Mountain region of the United States. The fields were acquired in December 2006 and January 2007 and are known as the South Glenrock B Field, the Big Muddy Field, and the Cole Creek South Field. Our business plan in acquiring the three fields was to substantially increase production by using waterflood, CO 2 injection and other enhanced oil recovery (EOR) techniques. All three fields currently produce some oil and we believe that, subject to financing, they are good candidates for EOR techniques, waterflood or CO2 tertiary recovery.

To fund the acquisition of the three fields and our operating expenses, from June 2006 through January 2007, we sold $89.3 million of our securities in two private placements. In December 2006, we also entered into an agreement with Anadarko Petroleum Corporation to supply us with CO2 needed to conduct CO2 tertiary recovery operations in our three fields. In February 2008, we entered into a Carbon Dioxide Sale and Purchase Agreement with ExxonMobil Gas and Power Marketing (ExxonMobil), a division of ExxonMobil Corporation, to supply additional CO2 to the three fields. We are seeking financing or strategic joint venture partners to enable us to construct a pipeline to deliver CO2 to our fields and to drill additional wells and construct necessary infrastructure improvements in order to implement EOR techniques.

Company Goals

The following summarizes our goals for the next three months:

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

	●	Minimize operating and administration costs.

We need substantial additional funding or to enter into another type of strategic transaction to be able to repay our short term debt and to continue operations. Our other goals are to enhance production from our existing wells, amend our two CO2 supply agreements and initiate development activities in our fields.

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

On August 7, 2008, we retained Growth Capital Partners, L.P. as the Company’s financial advisor to consider financing and other strategic alternatives, including the possible sale of the Company. We have been unsuccessful in completing a strategic transaction. Our ability to survive will be dependent upon completing a strategic transaction; however, there is no assurance that any transaction will be completed.

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Liquidity and Capital Resources

Going Concern

The report of our independent registered public accounting firm on the financial statements for the year ended March 31, 2008 includes an explanatory paragraph relating to the uncertainty of our ability to continue as a going concern. We have incurred a cumulative net loss of $ 67.0 million for the period from inception (February 4, 2004) to December 31, 2008. At December 31, 2008 we had cash on hand of $1.4 million, short term debt of $10 million and a working capital deficit of approximately $7.8 million. The debt is currently scheduled to mature on April 30, 2009. We require significant additional funding to repay the short term debt and to sustain our operations. Our ability to continue the Company as a going concern is dependent upon our ability to obtain additional funding in order to pay our short term debt and finance our planned operations.

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

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

Beginning in March 2008, we reduced our level of staffing by laying off several employees whose positions were considered to be redundant based upon the anticipated closing of a farmout transaction with experienced industry operators. Neither the original nor a subsequently identified farmout transaction was completed; however we continued field and corporate operations utilizing the remaining staff and, on a very limited contract basis, the utilization of contract consultants. At that time our monthly oil and gas production revenue was adequate to cover monthly field operating costs, production taxes and general and administrative expenses; however, interest payments on short term debt and payments relating to our crude oil hedging position resulted in negative cash flow each month. The collapse of crude oil prices commencing in August 2008 and continuing to date has exacerbated the situation, such that at current NYMEX strip prices our expected future cash flows from crude oil sale are inadequate to cover monthly field operating costs, production taxes and general and administrative expenses. This negative cash flow is offset to some extent by proceeds realized from our crude oil hedging position. This hedge expires in October 2009.

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We have executed two agreements to purchase CO2 for use in EOR operations in our fields. These supply agreements are discussed in more detail in our Form 10-K for the year ended March 31, 2008, filed with the Securities and Exchange Commission on June 30, 2008. Both supply contracts are problematic in the current low commodity price environment and we have commenced discussions with both suppliers regarding amendments to the contracts to make them economically viable for us. There is no assurance we will successfully complete any such amendments and in the event we do not, we will likely be unable to sustain operations or meet our obligations under the supply agreements.

Results of Operations

Three Months Ended December 31, 2008 Compared to Three Months December 31, 2007.

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

	Three Months Ended December 31,
	2008			2007
Revenues:
Oil production (in barrels)		16,997			22,020
Net oil price (per barrel)	$	44.00		$	77.40
Oil sales	$	746,967		$	1,704,267
Gains (Losses) on derivative activities, net		1,586,911			(636,109	)
Total revenues		2,333,878			1,068,158

Operating expenses:
Production taxes		90,940			207,588
Lease operating expenses		831,559			808,091
Depreciation, depletion, amortization and accretion		391,508			319,391
Impairment of proved properties		32,500,000			—

Exploration expense		4,293			55,945
General and administrative expense		780,261			1,735,482
Total operating expenses		34,598,561			3,126,497

Loss from operations		(32,264,683	)		(2,058,339	)

Other income (expense):

Interest expense and financing costs		(1,171,886	)		(1,342,984	)
Interest and other income		6,811			95,982
Total other expense		(1,165,075	)		(1,247,002	)

Net loss	$	(33,429,758	)	$	(3,305,341	)

Overview. For the three months ended December 31, 2008, we reported a net loss of $33,429,758, or $0.29 per basic and fully-diluted share, compared to a net loss of $3,305,341, or $ 0.03 per basic and fully-diluted share, for the corresponding three months of 2007. Discussions of individually significant period to period variances follow.

Revenue, production taxes, and lease operating expenses. For the three months ended December 31, 2008, we recorded crude oil sales of $746,967 on 16,977 barrels of oil at an average price of $44.00, as compared to revenues of $1,704,267 on 22,020 barrels of oil at an average price of $77.40 per barrel in 2007. The period-to period variance reflects a volume variance of $(390,310)and a price variance of $(566,991) The decreased volume in 2008 reflects mechanical production problems resulting in a reduction in the number of producing wells and curtailed production from other wells while flowline and other well repairs were carried out, coupled with overall production decline from year to year. Production taxes (including ad valorem taxes) of $90,940 in 2008 as compared to $ 207,588 in 2007 remained constant at 12% of crude oil sales revenues. Lease operating expenses in 2008 of $831,559 or $48.98/bbl showed an increase from the prior year, $808,091 or $36.70/bbl, reflecting the significant amounts of downhole repair and other well work carried on in 2008 versus very little such work conducted in 2007.

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Gains (losses) on risk management activities. In connection with short term debt financing entered into in October 2007 we entered into a crude oil derivative contract with an unrelated counterparty to set a price floor of $65 per barrel for 75% of our estimated crude oil production for the next two years, and a price ceiling of $83.50 for 45% of the same level of production. During the three months ended December 31, 2008 we recorded total gains on the derivative activities of $1,586,911, comprised of $144,285 of realized gains and $1,442,627 of unrealized gains of reflecting the reversal of previously recorded unrealized losses. For the comparable 2007 periods we recorded derivative losses of $636,196 comprised of recognized losses of $57,674 and unrealized losses of $578,435

Depreciation, depletion and amortization. For the three months ended December 31, 2008, we reflected depreciation, depletion, and amortization and accretion of $391,508, made up of $305,210, ($17.98/bbl), related to oil and gas properties, $45,637 related to other assets, and accretion of the asset retirement obligation of $40,661 as compared to $319,391 made up of $282,928, $12.84/bbl, related to oil and gas properties, $47,684 related to other assets and accretion of the asset retirement obligation of $(11,221) for the corresponding three months ended December 31, 2007. The period-to period increase in dollars per barrel primarily reflects the increased base of proved property costs being amortized over a lower reserve base in 2008 as compared to 2007.

Impairment of unproved properties. As of December 31, 2008 and in conjunction with the periodic assessment of impairment of unproved properties, we re-evaluated the carrying value of our unproved properties giving consideration to lower crude oil prices and the difficulties encountered in securing capital to develop the properties. Accordingly, during the three months ended December 31, 2008 we recorded $32,500,000 of impairment expense of unproved properties, reflecting the excess of the carrying value over estimated realizable value of the assets. No such impairment was recognized during the three months ended December 31, 2007.

General and administrative expense. For the three months ended December 31, 2008, we reflected general and administrative expenses of $780,261 as compared to $1,735,482 for the corresponding three months ended December 31, 2007. The decrease reflects a general lower level of activity in 2008 compared to 2007 and staff reductions carried out in March and April of 2008. As of December 31, 2008 we had six employees in the corporate office and three in the field office in Wyoming as compared to seventeen and six, respectively, as of December 31, 2007. Salaries and benefit costs for the three months ended December 31, 2008 were $305,338 as compared to $805,073 for the same period in 2007. Stock-based compensation expense was reduced to $143,553 in 2008 as compared to $394,209 in 2007 reflecting the expiration of stock options previously held by terminated employees. In addition to personnel related cost reductions we implemented cost saving measures in several other cost categories including: 1) lower accounting and financial reporting contractor fees of $18,671 in 2008 compared to $116,657 in 2007 ; 2) lower travel and entertainment costs of $5,362 in 2008 compared to $27,611 in 2007; 3) lower investor relations fees of $15,784 in 2008 compared to $27,220 in 2007; 4) lower recruiting fees of zero in 2008 compared to $22,050 in 2007; and 5) lower audit and tax compliance fees of $26,886 in 2008 as compared to $76,289 in 2007. We continue to initiate efforts to minimize general and administrative expenses including the recent engagement a commercial real estate broker to sublease or otherwise market the excess office space we have following our staff reductions earlier this year.

Interest expense and financing costs. For the three months ended December 31, 2008, we reflected interest expense and financing costs of $1,171,886 as compared to $1,342,984 for the corresponding three months ended December 31, 2007. The 2008 amount is comprised of interest paid on the Note Payable issued in October 2007 of $323,093 and amortization of deferred financing costs and discount on notes payable of $848,793.The 2007 amount is comprised of $441,422 of interest paid on the Note Payable and $901,562 of amortization of deferred financing costs and discount on Note Payable.

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Nine Months Ended December 31, 2008 Compared to Nine Months December 31, 2007.

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

	Nine Months Ended December 31,
	2008			2007
Revenues:
Oil production (in barrels)		51,239			68,076
Net oil price (per barrel)	$	90.59		$	68.83
Oil sales	$	4,641,836		$	4,685,373
Gains (losses) on derivative activities, net		997,169			(636,109	)
Total revenues		5,639,005			4,049,264

Operating expenses:
Production taxes		564,590			570,239
Lease operating expenses		2,004,422			2,087,753
Depreciation, depletion, amortization and accretion		1,046,166			1,097,255
Impairment of unproved properties		39,300,000			—

Exploration expense		13,896			186,772
General and administrative expense		2,788,415			5,788,574
Total operating expenses		45,717,489			9,730,593

Loss from operations		(40,078,484	)		(5,681,329	)

Other income (expense):
Liquidated damages pursuant to registration rights arrangement					(2,645,393	)
Interest expense and financing costs		(4,594,283	)		(1,555,417	)
Interest and other income		26,129			169,846
Total other expense		(4,568,154	)		(4,030,964	)

Net loss	$	(44,646,638	)	$	(9,712,293	)

Overview. For the nine months ended December 31, 2008, we reported a net loss of $44,646,638, or $0.39 per basic and fully-diluted share, compared to a net loss of $9,712,293 or $(0.09) per basic and fully-diluted share, for the corresponding nine months of 2007. Discussions of individually significant period to period variances follow.

Revenue, production taxes, and lease operating expenses. For the nine months ended December 31, 2008, we recorded crude oil sales of $4,641,836 on 51,239 barrels of oil at an average price of $90.59 as compared to revenues of $4,685,373 on 68,076 barrels of oil at an average price of $68.83 per barrel in 2007. The period-to period variance reflects a volume variance of $(1,158,817) and a price variance of $1,115,279. The decreased volume in 2008 reflects mechanical production problems resulting in a reduction in the number of producing wells and curtailed production from other wells while flowline and other well repairs were carried out, coupled with overall production decline from period-to-period. Production taxes (including ad valorem taxes) of $564,590 in 2008 as compared to $570,239 in 2007 remained constant at % of crude oil sales revenues. Lease operating expenses decreased to $2,004,422 ($39.12/bbl) in 2008 compared to $2,087,753 ($30.67/bbl) in 2007. The period to period lease operating expense variance is comprised of volume variance of $516,356 and a cost variance of $(433,025). The higher per barrel costs in 2008 reflect the significant amounts of downhole repair and other well work carried on in 2008 in an effort to slow production decline, versus very little such work conducted in 2007.

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Gains (losses) on risk management activities. In connection with short term debt financing entered into in October 2007 we entered into a crude oil derivative contract with an unrelated counterparty to set a price floor of $65 per barrel for 75% of our estimated crude oil production for the next two years, and a price ceiling of $83.50 for 45% of the same level of production. During the nine months ended December 31, 2008 we recorded total gains on the derivative activities of $997,169, comprised of $505,623 of realized losses and $1,502,792 of unrealized gains reflecting the reversal of previously recorded unrealized losses. For the comparable 2007 periods we recorded derivative losses of $636,196 comprised of recognized losses of $57,674 and unrealized losses of $578,435

Depreciation, depletion and, amortization. For the nine months ended December 31, 2008, we reflected depreciation, depletion, and amortization and accretion of $1,046,166, made up of $784,263, ($15.31/bbl), related to oil and gas properties, $144,132 related to other assets), and accretion of the asset retirement obligation of $117,771 as compared to $1,097,255 made up of $902,058, ($13.25/bbl), related to oil and gas properties, $128,810 related to other assets and accretion of the asset retirement obligation of $66,387 for the corresponding three months ended December 31, 2007. The period-to period increase in dollars per barrel primarily reflects the increased base of proved property costs being amortized over a lower reserve base in 2008 as compared to 2007Impairment of unproved properties. As of December 31, 2008 and in conjunction with the periodic assessment of impairment of unproved properties, we-evaluated the carrying value of our unproved properties giving consideration to lower crude oil prices and the difficulties encountered in securing capital to develop the properties. Accordingly, during the nine months ended December 31, 2008 we recorded $39,300,000 of impairment expense of unproved properties, reflecting the excess of the carrying value over estimated realizable value of the assets. No such impairment was recognized during the nine months ended December 31, 2007.

General and administrative expense. For the nine months ended December 31, 2008, we reflected general and administrative expenses of $ 2,788,415 as compared to $5,788,574 for the corresponding nine months ended December 31, 2007. The decrease reflects a general lower level of activity in 2008 compared to 2007 and staff reductions carried out in March and April of 2008. As of December 31, 2008 we had six employees in the corporate office and three in the field office in Wyoming as compared to seventeen and six, respectively, as of December 31, 2007. Salaries and benefit costs for the nine months ended December 31, 2008 were $1,007,380 as compared to $2,215,634 for the same period in 2007. Stock-based compensation expense was reduced to $648,531 in 2008 as compared to $1,045,093 in 2007 reflecting the expiration of stock options previously held by terminated employees. In addition to personnel related cost reductions we implemented cost saving measures in several other cost categories including: 1) lower accounting and financial reporting contractor fees of $116,257 in 2008 compared to $462,730 in 2007; 2) lower IT consulting and systems costs of $95,388 in 2008 compared to $165,584 in 2007; 3) lower investor relations fees of $ 67,260 in 2008 compared to $119,304 in 2007; 4) lower recruiting fees of zero in 2008 compared to $263,270 in 2007; 5) lower travel and entertainment expenses of $62,398 in 2008 compared to $160,217 in 2007; and 6) lower legal fees of $234,999 in 2008 as compared to $293,491 in 2007 In addition audit, tax compliance and Sarbanes Oxley fees were reduced to $191,773 in 2008 from $522,318 in 2007. These cost savings were partially offset by higher office rent expense of $300,909 in 2008 compared to $188,855 in 2007 reflecting a full nine months of higher rent on the larger office space we occupied in August 2007. We continue to initiate efforts to minimize general and administrative expenses including the recent engagement a commercial real estate broker to sublease or otherwise market the excess office space we have following our staff reductions earlier this year.

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

Interest expense and financing costs. For the nine months ended December 31, 2008, we reflected interest expense and financing costs of $4,594,282 as compared to $1,555,417 for the corresponding nine months ended December 31, 2007. The 2008 amount is comprised of interest paid on the Note Payable issued in October 2007 of $1,069,733 and amortization of deferred financing costs and discount on notes payable of $3,524,549.The 2007 amount is comprised of $442,108 of interest paid on the Note Payable and $1,13,309 of amortization of deferred financing costs and discount on Note Payable.

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

	For the Nine Months Ended December 31,
	2008			2007
Cash flows from:
Operating activities	$	(2,399,188	)	$	(3,560,062	)
Investing activities	$	(670,188	)	$	(2,393,803	)
Financing activities	$	(2,341,470	)	$	11,077,073

Cash flows used for operating activities decreased as a result of lower general and administrative expenses as discussed above, partially offset by payments to settle derivative activity losses and interest expense incurred in connection with the October 2007 short term financing.

Cash flows used for investing activities decreased in the 2008 period compared to the 2007 period as we expended significantly less on oil and gas properties, $230,000 in 2008 compared to $2,088,000 in 2007. In response to our lack of success in securing additional financing during the period, we have curtailed capital spending to the minimum required to maintain current levels of crude oil production.

Cash flows used for financing activities in 2008 includes the repayment of a portion of the debt incurred in 2007 ($2,240,000) and financing costs incurred to complete requirements of the short term debt agreement . The source of cash in 2007 represents the proceeds for the short term debt, net of offering and finance costs.

Off-Balance Sheet Arrangements

Under the terms of the Term Credit Agreement entered into in October 2007 we were required to hedge a portion of our expected production and we entered into a costless collar agreement for a portion of our anticipated future crude oil production. The costless collar contains a fixed floor price (put) and ceiling price (call). If the index price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. During the nine months ended December 31, 2008 we reflected realized losses of $506,623 and unrealized gains of $1,502,792 from the hedging activity, compared to realized losses of $57,674 and unrealized losses of $578,435 for the comparable period of 2007..

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

Critical Accounting Policies and Estimates

Critical accounting policies and estimates are provided in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, to the Annual Report on Form 10-K for the year ended March 31, 2008. Additional footnote disclosures are provided in Notes to Consolidated Financial Statements in Part I, Financial Information, Item 1, Financial Statements to this Quarterly Report on Form 10-Q for the three months ended December 31, 2008.

Item 3. Quantitative and Qualitative Disclosure About Market Risk.

Commodity Price Risk

Our revenues could be subject to significant fluctuation based on pricing applicable to our oil production. However, because of our relatively low level of current oil and gas production, we have not been exposed to a great degree of market risk. Our ability to raise additional capital at attractive pricing, our future revenues from oil and gas operations, our future profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. With increases to our production, exposure to this risk will become more significant. We expect commodity price volatility to continue. In connection with our short term financing in October 2007, we entered into an oil hedge agreement covering approximately 75% of our proved developed producing reserves scheduled to be produced during a two-year period. Terms of future debt facilities may also require that we hedge a portion of our expected future production.

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Financial Market Risk

The debt and equity markets have recently exhibited adverse conditions. The unprecedented volatility and upheaval in the capital markets may impact our ability to refinance or extend our existing short term debt when it matures on April 30, 2009. Alternatively, market conditions may affect the availability of capital for prospective purchasers of our assets or equity as contemplated under our arrangement with Growth Capital.

Item 4. Controls and Procedures.

Disclosure Controls and Procedures

We conducted an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Accounting Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures also include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. We identified a material weakness in our internal control over financial reporting and, as a result of this material weakness, we concluded as of March 31, 2008 and as of the end of the period covered by this Quarterly Report on Form 10-Q, that our disclosure controls and procedures were not effective.

Changes in Internal Control over Financial Reporting

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

PART II. OTHER INFORMATION.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

On December 31, 2008, pursuant to our compensation arrangement with our non-employee directors, we issued 2,653,845 shares of our common stock in the aggregate under our 2006 Stock Incentive Plan to our non-employee directors for their service on our Board of Directors and for attending board and committee meetings, as the case may be. More specifically, we issued to the following directors the shares specified: (i) William A. Anderson 634,615 shares; (ii) Joseph P. McCoy, 721,154 shares; (iii) Patrick M. Murray, 432,692 shares; (iv) Myron M. Sheinfeld, 432,692 shares, and (v) Mark Worthey, 432,692 shares.

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

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Item 6. EXHIBITS.

Exhibit	Description
3.1	Amended and Restated Articles of Incorporation (17)
3.2	Articles of Correction (22)
3.3	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 and 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	Denver Place Office Lease between Rancher Energy Corp. and Denver Place Associates Limited Partnership, dated October 30, 2006 (8)
10.14	Finder’s Fee Agreement between Falcon Capital and Rancher Energy Corp. (10)
10.15	Amendment to Purchase and Sale Agreement between Wyoming Mineral Exploration, LLC and Rancher Energy Corp. (11)
10.16	Letter Agreement between Certain Unit Holders and Rancher Energy Corp., dated December 8, 2006 (2)
10.17	Letter Agreement between Certain Option Holders and Rancher Energy Corp., dated December 13, 2006 (2)
10.18	Product Sale and Purchase Contract by and between Rancher Energy Corp. and the Anadarko Petroleum Corporation, dated December 15, 2006 (12)
10.19	Amendment to Purchase and Sale Agreement between Nielson and Associates, Inc. and Rancher Energy Corp. (13)
10.20	Securities Purchase Agreement by and among Rancher Energy Corp. and the Buyers identified therein, dated December 21, 2006 (3)
10.21	Lock-Up Agreement between Rancher Energy Corp. and Stockholders identified therein, dated December 21, 2006 (3)
10.22	Voting Agreement between Rancher Energy Corp. and Stockholders identified therein, dated as of December 13, 2006 (3)
10.23	Form of Convertible Note (14)

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Exhibit	Description
10.24	First Amendment to Securities Purchase Agreement by and among Rancher Energy Corp. and the Buyers identified therein, dated as of January 18, 2007 (16)
10.25	Rancher Energy Corp. 2006 Stock Incentive Plan Form of Restricted Stock Agreement (17)
10.26	First Amendment to Employment Agreement by and between John Works and Rancher Energy Corp., dated March 14, 2007 (18)
10.27	Employment Agreement between Richard Kurtenbach and Rancher Energy Corp., dated August 3, 2007(19)
10.28	Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated as of October 16, 2007 (20)
10.29	Term Note made by Rancher Energy Corp. in favor of GasRock Capital LLC, dated October 16, 2007 (20)
10.30	Mortgage, Security Agreement, Financing Statement and Assignment of Production and Revenues from Rancher Energy Corp. to GasRock Capital LLC, dated as of October 16, 2007 (20)
10.31	Security Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated as of October 16, 2007 (20)
10.32	Conveyance of Overriding Royalty Interest by Rancher Energy Corp. in favor of GasRock Capital LLC, dated as of October 16, 2007 (20)
10.33	ISDA Master Agreement between Rancher Energy Corp. and BP Corporation North America Inc., dated as of October 16, 2007 (20)
10.34	Restricted Account and Securities Account Control Agreement by and among Rancher Energy Corp., GasRock Capital LLC, and Wells Fargo Bank, National Association, dated as of October 16, 2007 (20)
10.35	Intercreditor Agreement by and among Rancher Energy Corp., GasRock Capital LLC, and BP Corporation North America Inc., dated as of October 16, 2007 (21)
10.36	First Amendment to Denver Place Office lease between Rancher Energy Corp. and Denver Place Associates Limited Partnership, dated March 6, 2007. (18)
10.37	Carbon Dioxide Sale & Purchase Agreement between Rancher Energy corp. and ExxonMobil Gas & Power Marketing Company, dated February 14, 2008 (Certain portions of this agreement have been redacted and have been filed separately with the Securities and Exchange Commission pursuant to a Confidential Treatment Request). (21)
10.38	Letter Agreement between Rancher Energy Corp. and Growth Capital Partners, LP(22)
10.39	First Amendment to Term Credit Agreement, dated October 22, 2008(23)
31.1	Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive Officer)
31.2	Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting Officer)
32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

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

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

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

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

(6) Incorporated by reference from our Quarterly Report on Form 10-Q/A filed on August 28, 2006.

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

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

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

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

(11) Incorporated by reference from our Current Report on Form 8-K/A filed on November 14, 2006.

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

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

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

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

(16) Incorporated by reference from our Current Report on Form 8-K filed on January 25, 2007.

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

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

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

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

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

(22) Incorporated by reference from our Current Report on Form 8-K filed on August 7, 2008.

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

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SIGNATURES

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

	RANCHER ENERGY CORP., Registrant

Dated: February 17, 2009	By:	/s/ John Works
		John Works, President, Chief Executive Officer,
		Chief Financial Officer, Secretary and Treasurer
		(Principal Executive Officer)

Dated: February 17, 2009	By:	/s/ Richard E. Kurtenbach
		Richard E. Kurtenbach, Chief Accounting Officer
		(Principal Accounting Officer)

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