T-REX OIL, INC. - Quarter Report: 2009 June (Form 10-Q)

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 June 30, 2009

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark 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 x

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

Yes o No x

As of August 18, 2009, 119,516,723 shares of Rancher Energy Corp. common stock, $.00001 par value, were outstanding.

Rancher Energy Corp.

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements

	Unaudited Balance Sheets as of June 30, 2009 and March 31, 2009	03

	Unaudited Statements of Operations for the Three Months ended
	June 30, 2009 and 2008	05

	Unaudited Statement of Changes in Stockholders’ Equity as of
	June 30, 2009	06

	Unaudited Statements of Cash Flows for the Three Months ended
	June 30, 2009 and 2008	07

	Notes to Financial Statements	08

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25

Item 4.	Controls and Procedures	25

PART II - OTHER INFORMATION

Item 6.	Exhibits	26

SIGNATURES		29

PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements

Rancher Energy Corp.

Balance Sheets

(unaudited)

ASSETS

	June 30, 2009			March 31, 2009
Current assets:
Cash and cash equivalents	$	603,877		$	917,160
Accounts receivable and prepaid expenses		435,130			584,139
Derivative receivable		44,438			455,960
Total current assets		1,083,445			1,957,259

Oil and gas properties at cost (successful efforts method):
Unproved		53,077,682			53,328,147
Proved		19,371,487			20,631,487
Less: Accumulated depletion, depreciation, amortization and impairment		(42,068,978	)		(41,840,978	)
Net oil and gas properties		30,380,191			32,118,656

Other assets:
Furniture and equipment net of accumulated depreciation of $429,349 and $381,396, respectively		714,117			770,354
Deferred finance costs		959,411			387,414
Other assets		929,381			546,178
Total other assets		2,602,909			1,703,946
Total assets	$	34,066,545		$	35,779,861

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

Rancher Energy Corp.

Balance Sheets

(unaudited)

LIABILITIES AND STOCKHOLDERS’ EQUITY

	June 30, 2009			March 31, 2009
Current liabilities:
Accounts payable and accrued liabilities	$	931,009		$	816,808
Accrued oil and gas property costs		-			-
Asset retirement obligation		113,180			108,884
Note payable, net of unamortized discount of $-0- and $165,790, respectively		10,067,892			9,834,210
Total current liabilities		11,112,081			10,759,902

Long-term liabilities:
Asset retirement obligation		1,204,002			1,171,796
Total long-term liabilities		1,204,002			1,171,796

Contingencies (Note 6)

Stockholders’ equity:
Common stock, $0.00001 par value, 275,000,000 shares authorized June 30, 2009 and March 31, 2009; 119,516,700 and 119,016,700 shares issued and outstanding at June 30, 2009 and March 31, 2009, respectively		1,196			1,191
Additional paid-in capital		92,724,170			92,582,001
Accumulated deficit		(70,974,904	)		(68,735,029	)
Total stockholders’ equity		21,750,462			23,848,163

Total liabilities and stockholders’ equity	$	34,066,545		$	35,779,861

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

Rancher Energy Corp.

Statements of Operations

(unaudited)

	Three Months Ended June 30,
Revenues:	2009			2008
Revenues:
Oil & gas sales	$	696,295		$	1,898,967
Derivative gains (losses)		(316,409	)		(1,895,293	)
		379,886			3,674
Operating expenses:
Production taxes		88,844			230,283
Lease operating expenses		353,150			623,421
Depreciation, depletion and amortization		279,202			275,841
Accretion expense		36,502			46,276
Exploration expense		2,505			9,604
General and administrative		781,846			1,048,376
Total operating expenses		1,542,049			2,233,801

Loss from operations		(1,162,163	)		(2,230,127	)

Other income (expense):
Amortization of deferred finance costs and discount on note payable		(706,348	)		(1,309,175	)
Interest and other income		(371,569	)		(371,295
Interest expense		205			10,581

Total other income (expense)		(1,077,712	)		(1,669,889	)

Net loss	$	(2,239,875	)	$	(3,900,016	)

Basic and diluted net loss per share	$	(0.02	)	$	0.03	)

Basic and diluted weighted average shares outstanding		119,239,227			114,966,138

The accompanying notes are an integral part of these financial statements

Rancher Energy Corp.

Statement of Changes in Stockholders’ Equity

(Unaudited)

	Shares		Amount		Additional Paid-In Capital		Accumulated Deficit			Total Stockholders’ Equity
Balance, March 31, 2009		119,016,700	$	1,191	$	92,582,001	$	(68,735,029	)	$	23,848,163

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

Stock-based compensation		-		-		142,169		-			142,169

Net loss		-		-		-		(2,239,875	)		(2,239,875	)

Balance, June 30, 2009		119,516,700	$	1,196	$	92,724,170	$	(70,974,904	)	$	21,750,462

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

Rancher Energy Corp.

Statements of Cash Flows

(unaudited)

	Three Months Ended June 30,
	2009			2008
Cash flows from operating activities:
Net loss	$	(2,239,875	)	$	(3,900,016	)
Adjustments to reconcile net loss to cash used for operating activities:
Depreciation, depletion, and amortization		279,202			275,841
Accretion expense		36,502			46,276
Interest expense converted to short-term debt		67,892
Amortization of deferred financing costs and discount on note payable		706,348			1,309,176
Unrealized losses on derivative activities		411,522			1,544,814
Stock-based compensation expense		142,169			117,890
Services exchanged for common stock - directors		-			100,100
Loss on asset sale		-			8,525
Changes in operating assets and liabilities:
Accounts receivable and prepaid expenses		149,009			68,654
Other assets		9,274			-
Accounts payable and accrued liabilities		114,203			(752,818	)
Net cash used for operating activities		(323,754	)		(1,181,558	)

Cash flows from investing activities:
Capital expenditures for oil and gas properties		-			(189,579	)
Proceeds from sale of other assets		10,466			-
Increase in other assets		-			(158,063	)
Net cash used for investing activities		10,466			(347,642	)

Cash flows from financing activities:
Payment of deferred financing costs		-			(113,253	)
Proceeds from issuance of common stock upon exercise of stock options		5			2
Net cash used for financing activities		5			(113,251	)

Increase (decrease) in cash and cash equivalents		(313,283	)		(1,642,451	)
Cash and cash equivalents, beginning of period		917,160			6,842,365

Cash and cash equivalents, end of period	$	603,877		$	5,199,914

Non-cash investing and financing activities:
Cash paid for interest	$	371,569		$	371,280
Payables settled for oil and gas properties	$	-		$	30,372
Asset retirement asset and obligation	$	-		$	4,804
Deferred finance costs, conveyance of net profits interest	$	1,500,000		$	-

Rancher Energy Corp.

Notes to Financial Statements

Note 1 – Organization and Summary of Significant Accounting Policies

Organization

Rancher Energy Corp. (“Rancher Energy” or the “Company”) 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 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 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, 2009. The accompanying 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, 2009. 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 Statements of Operations, we have incurred a cumulative net loss of $71.0 million for the period from inception (February 4, 2004) to June 30, 2009 and have a working capital deficit of approximately $10.1 million as of June 30, 2009. The Company’s current cash reserves are sufficient to continue operations through the end of September 2009. We require significant additional funding to repay the short term debt in the amount of $10 million, scheduled to mature on October 15, 2009, to continue operations and for our planned oil and gas development operations. The Company’s ability to continue as going concern is dependent upon its ability to obtain additional funding in order to finance its planned operations. The Company is seeking to raise substantial financing through the sale of debt or equity, or to enter into a strategic partnering arrangement with an experienced industry operator to enable it to pay its short term debt, continue operations and to pursue its business plan. There is no assurance the Company will be successful in these efforts. If the Company is not successful in raising substantial funding or closing a strategic partnering transaction to address its cash needs and its short-term debt within the required timeframe, it may need to cease operations and its secured lender may foreclose on its properties and/or a bankruptcy filing could be made. If the Company enters the bankruptcy process, there is no assurance it will be successful in emerging from bankruptcy.

Use of Estimates in the Preparation of Financial Statements

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

Oil and Gas Producing Activities

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

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

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

The Company reviews its long-lived assets for impairments when events or changes in circumstances indicate that impairment may have occurred. The impairment test for proved properties compares the expected undiscounted future net cash flows on a property-by-property basis with the related net capitalized costs, including costs associated with asset retirement obligations, at the end of each reporting period. Expected future cash flows are calculated on all proved reserves using a discount rate and price forecasts selected by the Company’s management. The discount rate is a rate that management believes is representative of current market conditions. The price forecast is based on NYMEX strip pricing, adjusted for basis and quality differentials, for the first three to five years and is held constant thereafter. Operating costs are also adjusted as deemed appropriate for these estimates. When the net capitalized costs exceed the undiscounted future net revenues of a field, the cost of the field is reduced to fair value, which is determined using discounted future net revenues. An impairment allowance is provided on unproved property when the Company determines the property will not be developed or the carrying value is not realizable. The Company recognized no impairment of proved or unproved properties during the three months ended June 30, 2009 or 2008.

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.

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

Derivative losses are included in cash flows from operating activities in the accompanying Consolidated Statements of Cash Flows. The table below summarizes the realized and unrealized losses related to our derivative instruments for the three months ended June 30, 2009.

	Three Ended June 30,
	2009			2008
Realized gains (losses) on derivative instruments	$	95,113		$	(350,479	)
Unrealized losses on derivative instruments	$	(411,522	)	$	(1,544,814	)
Total realized and unrealized losses recorded	$	(316,409	)	$	(1,895,293	)

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 June 30, 2009 Due To (From) Company
Put	Nov 07—Oct 09		113,220		18,231	WTI NYMEX	$	65.00	$	44,438
Call	Nov 07—Oct 09		67,935		10,939	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 and the Company’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 June 30, 2009.

Net Profits Interest

The Company assigned a 10% Net Profits Interest (NPI) to its Lender, under the terms of the Eighth Amendment to the Term Credit Agreement (see NOTE 5 – Short-term Note Payable). Net profit is defined as the excess of the sum of crude oil proceeds plus hedge settlements, over the sum of lease operating, marketing, transportation and production tax expenses. The Company is obligated to pay to the Lender 10% of such excess, if any, on a monthly basis, so long as the NPI remains in effect. The Company records amounts due under the NPI as operating expense. For the three months ended June 30, 2009 the Company recognized $12,647 as NPI expense, including such amount as lease operating expense in its Statement of Operations.

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. The following table details the weighted-average dilutive and anti-dilutive securities related to stock options and warrants for the periods presented:

	For the Three Months Ended June 30,
	2009		2008
Dilutive		-		-
Anti-dilutive		64,892,304		77,401,402

Reclassification

Certain amounts in the 2008 financial statements have been reclassified to conform to the 2009 financial statement presentation. Such reclassifications had no effect on net loss.

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, 2009, and are supplemented in the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for the three months ended June 30, 2009. These unaudited financial statements and notes should be read in conjunction with the financial statements and notes included in the Annual Report on Form 10-K for the year ended March 31, 2009.

Recent Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements.” This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure related to the use of fair value measures in financial statements. In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active”, which clarified the application of SFAS No. 157 as it relates to the valuation of financial assets in a market that is not active for those financial assets. On April 1, 2008, we adopted without material impact on our consolidated financial statements the provisions of SFAS No. 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis. On April 1, 2009, we adopted the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include, among others, those nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. We do not expect the provisions of SFAS No. 157 related to these items to have a material impact on our consolidated financial statements (see Note 4).

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

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired, and establishes that acquisition costs will be generally expensed as incurred. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. On April 1, 2009 the FASB issued FSP FAS 141R-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP FAS 141R-1”). This FSP amends and clarifies SFAS No. 141R to address application issues related to initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The Company adopted SFAS No. 141R on April 1, 2009. The adoption of SFAS No. 141R did not have a material impact on our financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” which amends SFAS No. 133 by requiring expanded disclosures about an entity’s derivative instruments and hedging activities, but does not change SFAS No. 133’s scope or accounting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, The Company adopted SFAS No. 161 on January 1, 2009 and the adoption of SFAS No. 161 did not have an impact on the Company’s financial position or results of operations.

In June 2008, the Emerging Issues Task Force (“Task Force”) issued EITF 07-5, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock.” The objective of this Issue is to provide guidance for determining whether an equity-linked financial instrument (or embedded feature) is indexed to an entity’s own stock. The Task Force reached a consensus that contingent and other adjustment features in equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a “plain vanilla” option or forward pricing model and they do not increase the contract’s exposure to those variables. Additionally, denomination of an equity contract’s strike price in a currency other than the entity’s functional currency is inconsistent with equity indexation and precludes equity treatment. The Company adopted EITF 07-5 on April 1, 2009 and the adoption had no material effect on our financial position or results of operations.

On December 31, 2008, the SEC adopted a final rule that amends its oil and gas reporting requirements. The revised rules change the way oil and gas companies report their reserves in the financial statements. The rules are intended to reflect changes in the oil and gas industry since the original disclosures were adopted in 1978. Definitions were updated to be consistent with Petroleum Resource Management System (PRMS). Other key revisions include a change in pricing used to prepare reserve estimates, the inclusion of non-traditional resources in reserves, the allowance for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and significant new disclosures. The revised rules will be effective for our annual report on Form 10-K for the fiscal year ending March 31, 2010. The SEC is precluding application of the new rules in quarterly reports prior to the first annual report in which the revised disclosures are required and early adoption is not permitted. We are currently evaluating the effect the new rules will have on our financial reporting and anticipate that the following rule changes could have a significant impact on our results of operations as follows:

·	The price used in calculating reserves will change from a single-day closing price measured on the last day of the company’s fiscal year to a 12-month average price, and will affect our depletion and ceiling test calculations.

·	Several reserve definitions have changed that could revise the types of reserves that will be included in our year-end reserve report.

Many of our financial reporting disclosures could change as a result of the new rules.

In June 2009, the FASB issued SFAS No. 165, “Subsequent Events”. SFAS No.165 incorporates the subsequent events guidance contained in the auditing standards literature into authoritative accounting literature. It also requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. SFAS No.165 is effective for all interim and annual periods ending after June 15, 2009. The Company adopted SFAS No.165 upon its issuance and it had no material impact on our consolidated financial statements. See Note 10 — Subsequent Events for this new disclosure.

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162,” (“Codification”), as the single source of authoritative generally accepted accounting principles in the United States (“US GAAP”) for all non-governmental entities, with the exception of the SEC and its staff. The Codification, which launched July 1, 2009, changes the referencing and organization of accounting guidance and is effective for interim and annual periods ending after September 15, 2009. Since it is not intended to change or alter existing US GAAP, the Codification is not expected to have any impact on the Company’s financial condition or results of operations.

Note 2—Oil and Gas Properties

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

	June 30, 2009			March 31, 2009

Proved properties	$	19,371,487		$	20,631,487

Unproved properties excluded from DD&A		52,713,480			52,953,185
Equipment and other		364,202			374,962
Subtotal Unevaluated Properties		53,077,682			53,328,147
Total oil and gas properties		72,449,169			73,959,634
Less accumulated depletion, depreciation, amortization and impairment		(42,068,978	)		(41,840,978	)
	$	30,380,191		$	32,118,656

Assignment of Net Profits Interest and Overriding Royalty Interest

In conjunction with the issuance of short term debt in October 2007 (See Note 5),the Company assigned the Lender a 2% Overriding Royalty Interest (ORRI), proportionally reduced when the Company’s working interest is less than 100%, in all crude oil and natural gas produced from its three Powder River Basin fields. The Company estimated that the fair value of the ORRI granted to the Lender to be approximately $4,500,000 and recorded this amount as a debt

discount and a decrease of oil and gas properties. In October 2008 the Company extended the maturity date of the short term debt by six months. As partial consideration for the extension, the Company granted an increase the proportionate ORRI from 2% to 3%. The Company estimated that the fair value of the incremental ORRI granted to the Lender to be approximately $1,050,000 and has recorded this amount as a debt discount and a decrease of oil and gas properties. In June 2009 the Company extended the maturity date of the short term debt until October 15, 2009. As partial consideration for the extension, the Company assigned the Lender a 10% Net Profits Interest (the “NPI”) in all crude oil and natural gas produced from its three Powder River Basin fields. The Company estimated the fair value of the NPI to be approximately $1,500,000 and recorded this amount as deferred finance costs and a decrease of oil and gas properties.

Impairment of Unproved Properties

The Company recorded no impairment of unproved properties in the three months ended June 30, 2009 or 2008.

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.

A reconciliation of the Company’s asset retirement obligation liability during the three months ended June 30, 2009 and 2008 is as follows:

	2009		2008
Beginning asset retirement obligations	$	1,280,680	$	1,259,851
Liabilities incurred		-		7,916
Liabilities settled		-		-
Changes in estimates		-		(3,112	)
Accretion expense		36,502		46,276
Ending asset retirement obligation	$	1,317,182	$	1,310,931

Current	$	113,180	$	366,319
Long-term		1,204,002		944,612
	$	1,317,182	$	1,310,931

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 June 30, 2009 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Assets:
Derivative instrument	$	-	$	-	$	44,438
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. 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 June 30, 2009.

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

	Derivatives as of June 30,
	2009			2008
Balance as of April 1	$	455,960		$	(837,033	)
Total gains (losses) (realized or unrealized):
Included in earnings		(316,412	)		(1,895,293	)
Included in other comprehensive income		-			-
Purchased, issuances and settlements		(95,113	)		272,206
Transfers in and out of Level 3					-

Balance as of June 30		44,435		$	(2,460,120	)

Change in unrealized gains (losses) included in earnings relating to derivatives still held as of June 30	$	44,435		$	(2,460,120	)

Note 5 – Short-term Note Payable

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

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

Under the terms of the Eighth Amendment, all amounts outstanding under the Term Credit Agreement, as amended, bear interest at a rate equal to the greater of (a) 16% per annum and (b) the LIBOR rate, plus 6% per annum. Furthermore, the Eighth Amendment specifies that 4% of the interest rate shall be capitalized so that it is added to and becomes a part of the Principal Amount in lieu of payment in cash. Under the terms of the Term Credit Agreement, as amended, the Company is required to make monthly interest payments on the amounts outstanding but is not required to make any principal payments until the Maturity Date. The Company may prepay the amounts outstanding under the Term Credit Agreement at any time without penalty.

The Company’s obligations under the Term Credit Agreement, as amended, are collateralized by a first priority security interest in its properties and assets, including all rights under oil and gas leases in its three producing oil fields in the Powder River Basin of Wyoming and all of its equipment on those properties. Under the terms of the original Term Credit Agreement, the Company granted the Lender a 2% Overriding Royalty Interest (ORRI), proportionally reduced when the Company’s working interest is less than 100%, in all crude oil and natural gas produced from its three Powder River Basin fields. The First Amendment granted an increase in the proportionate overriding royalty interests (“ORRI”) assigned to the Lender from 2% to 3%. The Company estimated the fair value of the 2% ORRI granted to the Lender to be approximately $4,500,000 and the value of the increase ORRI to be approximately $1,050,000. These amounts were recorded as discounts to the Note Payable and as decreases of oil and gas properties. The Eighth Amendment granted a Conveyance of Net Profits to the Lender. The Company estimates the fair value of the 10% NPI to be approximately $1,500,000. This amount was recorded as deferred finance costs and is being amortized over the term of the Note, as amended. The Company recorded total amortization of discounts and deferred finance costs of $706,348 and $1,309,175 for the three month ended June 30, 2009 and 2008 respectively.

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

The Company is subject to various restrictive covenants under the Term 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 Term Credit Agreement) and (b) a loan-to-value ratio greater than 1.0 to 1.0 for the term of the loan. As of March 31, 2009, the Company was not in compliance with the loan-to-value ratio covenant, primarily due to a lower crude oil price deck used in computing the reserve value. The lender has waived this non-compliance from March 31, 2009 through the amended maturity date, October 15, 2009.

Note 6 – Contingencies

Threatened Litigation

On December 31, 2008, the Company received a letter from an attorney representing Sergei Stetsenko. Andrei Stytsenko, and other shareholders (the “Stytsenko Group”) stating that it was the opinion of the Stytsenko Group that the Company’s Directors and Executive Officers have acted negligently and contrary to their fiduciary duties. The letter threatens a lawsuit and demands that the Directors and Executive Officers return all cash and stock received from the Company, cease payment of any cash or stock compensation for their services, resign their positions as Directors and Executive Officers and call a shareholders’ meeting to elect Andrei Stytsenko as the sole director of the Company. No suit has been filed. The Company denies the allegations and believes they are without merit. In February 2009, the Company’s Board of Directors established a Special Committee of the Board (the “Special Committee”) to investigate the allegations. The Stytsenko Group has filed proxies with the SEC, proposing an alternate slate of directors for election at the Company’s next meeting of shareholders. The Company cannot predict the likelihood of a lawsuit being filed, its possible outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in any such lawsuit.

In a letter dated February 18, 2009 sent to each of the Company’s Directors, attorneys representing a group of persons who purchased approximately $1,800,000 of securities (in the aggregate) in the Company’s private placement offering commenced in late 2006, alleged that securities laws were violated in that offering. In April 2009, the Company entered into tolling agreements with the purchasers to toll the statutes of limitations applicable to any claims related to the private placement. The Company’s Board of Directors directed the Special Committee to investigate these allegations. The Company denies the allegations and believes they are without merit. The Company cannot predict the likelihood of a lawsuit being filed, its possible outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in any such lawsuit.

Note 7 – Income Taxes

As of June 30, 2009, 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 8—Common Stock

The Company’s capital stock as of June 30, 2009 and 2008 consists of 275,000,000 authorized shares of common stock, par value $0.00001 per share.

Issuance of Common Stock

For the Three Months Ended June 30, 2009

During the three months ended June 30, 2009, the Company issued 500,000 shares to an officer of the Company upon the exercise of stock options. No other shares of stock were issued during the period.

Note 9—Share-Based Compensation

Chief Executive Officer (CEO) Options

During the three months ended June 30, 2009, the Company’s CEO exercised options to acquire 500,000 shares of common stock, for a cumulative exercise price of $5.00 ($0.00001/share).

2006 Stock Incentive Plan

There were no options to purchase shares of common stock granted during the three months ended June 30, 2009. During the three months ended June 30, 2009, options to purchase 5,000 shares of common stock granted to employees expired. The options had exercise prices of $1.18.

Total estimated unrecognized compensation cost from unvested stock options as of June 30, 2009 was approximately $85,000 which the Company expects to recognize over three years. As of June 30, 2009 there were 571,000 options outstanding under the 2006 Stock Incentive Plan and 9,429,000 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 director appointed to the Board of Directors 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 three months ended June 30, 2009, $25,850 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.

Board members elected to forego stock compensation for the quarter ended June 30, 2009.

Note 10—Subsequent Events

The Company has evaluated subsequent events through August19, 2009, the filing date of this Form 10-Q. On August 7, 2009, the Company filed an Application for Financial Assistance under the U.S. Department of Energy Funding Opportunity Announcement No. DE-FOA-0000015, Carbon Capture and Sequestration from Industrial Sources and Innovative Concepts for Beneficial CO2 Use (the “FOA”). The Company applied for a grant under Phase 1 of the FOA, which if awarded, will be utilized to complete reservoir engineering studies, drilling and surface facility design and pipeline design and permitting for one of the Company’s Powder River Basin EOR oil fields The Company applied for a grant equal to 80% of the $4.65 million Phase 1 budget, or $3.72 million. The Company proposed, as its 20% cost share, a “contribution in kind” of costs previously incurred on pipeline, surface facilities and reservoir studies equal to $0.93 million. If the Company is awarded a Phase 1 Grant, it plans to apply for a Phase 2 grant in an amount of up to $175 million to undertake a comprehensive CO2 capture, transportation, EOR, and sequestration project in that field.

The Company believes its EOR project is well qualified for awards under the provisions of the FOA; however, there can be no assurance that the Company will obtain a Phase 1 grant, or if the Company does obtain a Phase 1 grant, there can be no assurance the Company will be successful in obtaining a Phase 2 grant. Further, there can be no assurance that if the Company obtains a Phase 2 grant, that its CO2 capture, transportation, EOR, and sequestration project will be technically or commercially successful.

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, 2009. 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.

Organization

We are an independent energy company that explores for and develops, produces, and markets oil and gas in North America. We were known as Metalex Resources, Inc. until April 2006 when our name was changed to Rancher Energy Corp. We operate three oil fields in the Powder River Basin, Wyoming. Our business plan is to use CO2 injection to increase oil production in these oil fields.

Outlook for the Coming Year

We must raise substantial financing by the end of September 2009 to be able to continue operations. Assuming we are successful in raising sufficient financing to meet our cash needs and repay our short-term debt due in October 2009, the following summarizes our goals and objectives for the next twelve months:

·	Maintain and enhance crude oil production from our existing wells;

·	Secure long term financing or strategic partnering arrangements with experienced industry partners to enable us to initiate development activities in our fields;

·	After securing financing or strategic partnering arrangements, renew discussions with ExxonMobil to ensure sufficient quantities of CO2 will be made available under the existing Sale and Purchase Agreement or negotiate a new contract with ExxonMobil for the supply of CO2 to our three oil fields.

·	Continue discussions with Anadarko to amend the Anadarko Purchase Contract to minimize or eliminate uncertainty.

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

In August 2009, we filed an Application for Financial Assistance under the U.S. Department of Energy Funding Opportunity Announcement No. DE-FOA-0000015, Carbon Capture and Sequestration from Industrial Sources and Innovative Concepts for Beneficial CO2 Use (the “FOA”). We applied for a grant under Phase 1 provisions of the FOA which if awarded, will be utilized to complete reservoir engineering studies, drilling and surface facility design and pipeline design and permitting for one of our Powder River Basin EOR oil fields. We requested a grant in the amount of $3.72 million, which is equal to 80% of the $4.65 million Phase 1 budget. In the application, we proposed, as our 20% cost share, a “contribution in kind” of costs previously incurred on pipeline, surface facilities and reservoir studies equal to $0.93 million. If we are awarded a Phase 1 Grant, we plan to apply for a Phase 2 grant in an amount of up to $175 million to undertake a comprehensive CO2 capture, transportation, EOR, and sequestration project in that field. We believe our EOR project is well qualified for awards under the provisions of the FOA; however, there is no assurance that we will obtain a Phase 1 grant, or if we do obtain a Phase 1 grant, there is no assurance we will be successful in obtaining a Phase 2 grant. Further, there is no assurance that if we obtain a Phase 2 grant, that our CO2 capture, transportation, EOR, and sequestration project will be technically or commercially successful.

Results of Operations

Three months ended June 30, 2009 Compared to Three Months June 30, 2007.

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

	Three Months Ended June 30,
	2009			2008
Revenues:
Oil production (in barrels)		13,135			16,083
Net oil price (per barrel)	$	53.01		$	118.07
Oil sales	$	696,295		$	1,898,967	)
Derivative losses		(316,409	)		(1,895,293	)
Total revenues		379,886			3,674

Operating expenses:
Production taxes		88,844			230,283
Lease operating expenses		353,150			623,421
Depreciation, depletion, amortization and accretion		279,202			275,841
Accretion expense		36,502			46,276
Exploration expense		2,505			9,604
General and administrative expense		781,846			1,048,376
Total operating expenses		1,542,049			2,233,801

Loss from operations		(1,162,163	)		(2,230,127	)

Other income (expense):
Interest expense and financing costs		(1,077,917	)		(1,680,470	)
Interest and other income		205			10,581
Total other income (expense)		(1,077,712	)		(1,669,889	)

Net loss	$	(2,239,875	)	$	(3,900,016	)

Overview. For the three months ended June 30, 2009, we reported a net loss of $2,239,875, or $0.02 per basic and fully-diluted share, compared to a net loss of $3,900,016 or $0.03 per basic and fully-diluted share, for the corresponding three months of 2008. Discussions of individually significant period to period variances follow.

Revenue, production taxes, and lease operating expenses. For the three months ended June 30, 2009, we recorded crude oil sales of $696,295 on 13,135 barrels of oil at an average price of $53.01, as compared to revenues of $1,898,967 on 16,083 barrels of oil at an average price of $118.07 per barrel in 2008. The year-to-year variance reflects a volume variance of $(348,079) and a price variance of $(854,592). The decreased volume in 2009 reflects the loss of several producing wells due to mechanical problems in late 2008 and early 2009, coupled with routine production decline from year to year. Production taxes (including ad valorem and property taxes) of $88,844 in 2009 as compared to $230,283 in 2008, remained constant at approximately 12.5% of crude oil sales revenues. Lease operating expenses decreased to $353,150 ($26.89/bbl) in 2009 as compared to $623,421 ($38.76/bbl) in 2008. The year to year variance reflects a volume variance of $114,273 and a cost variance of $155,998. The per barrel decrease in 2009 compared to 2008 reflects costs saving efforts undertaken to preserve capital, coupled with a lack of significant well or surface facility repair work in the 2009 quarter as compared to the 2008 quarter

Derivative losses.. In connection with short term debt financing entered into in October 2007, we entered into a crude oil derivative contract with an unrelated counterparty to set a price floor of $63 per barrel for 75% of our estimated crude oil production for the next two years, and a price ceiling of $83.50 for 45% of the same level of production. During the three months ended June 30, 2009 and 2008 we recorded total losses on the derivative activities of $316,409 and $1,895,293, respectively. The 2009 losses were comprised of $95,113 of realized gains and $411,552 of unrealized losses, compared to $350,479 of realized losses and $1,544,814 of unrealized losses for the comparable 2008 quarter.

Depreciation, depletion, amortization and accretion. For the three months ended June 30, 2009, we reflected total depreciation, depletion, and amortization of $279,202 comprised of $227,999 ($17.36/bbl) related to oil and gas properties, and $51,203 related to other assets. The comparable amounts for the 2008 period were $275,841comprised of $225,784 ($17.15/bbl), related to oil and gas properties, and $50,057 related to other assets) for the corresponding three months ended June 30, 2008.

General and administrative expense. For the three months ended June 30, 2009, we reflected general and administrative expenses of $781,846 as compared to $1,048,376 for the corresponding three months ended June 30, 2008. Period to period comparisons and explanations of significant variances follow:

	Three Months Ended
Expense Category	2009			2008			Discussion
Salaries, payroll taxes and benefits	$	285,500		$	400,100		Decrease reflects lower staff count in 2009 vs. 2008. 2009 period included 24 man-months, compared to 35 man-months in 2008 period
Consultants		29,600			125,400		Decrease reflects cost cutting measures, including decrease in contract accounting $53,400; contract land and operations, $22,100 and contract engineering, $19,000
Travel & entertainment		2,800			31,200		Cost cutting measure imposed.
IT		12,400			52,500		Cancelation of software maintenance agreements, $20,000; reduction in outside IT consulting and maintenance, $17,500
Legal fees		133,600			13,200		Increase reflects efforts to address threatened lawsuits, contested proxy contest, and numerous amendments to amend our Term Credit Agreement with our Lender.
Audit, SOX and tax compliance		34,800			77,600		Decrease reflects audit efficiencies in the third year of review and lower costs of SOX documentation and testing efforts.
Investor relations		-0-			33,600		Cancelation of contract with outside investor relation firm
Office rent, communication & other office expenses		133,300			198,600		Reduced staff count and cost saving measures enacted to conserve capital
Insurance		57,400			38,100		Increased premiums, primarily D&O insurance
Stock based compensation		142,100			143,700			-
Director fees		73,300			74,200			-
Field overhead recoveries		(123,000	)		(139,800	)	Fewer producing wells in 2009 as compared to 2008, generating overhead recoveries
TOTAL G&A	$	781,800		$	1,048,400

Interest expense and financing costs. For the three months ended June 30, 2009, we reflected interest expense and financing costs of $1,077,918 as compared to $1,680,470 for the corresponding three months ended June 30, 2008. The 2009 amount is comprised of interest paid on the Note Payable issued in October 2007, as amended, of $371,569 and amortization of deferred financing costs and discount on Note Payable of $706,348. Comparable amounts for the 2008 period were$371,280 of interest on the Note Payable and $1,309,190 of deferred finance discount amortization.

Liquidity and Capital Resources

Our current cash reserves are sufficient to continue operations through the end of September 2009. Our short-term debt is due in October 2009. If we are not successful in raising substantial funding or closing a strategic partnering transaction to address our cash needs and our short-term debt within the required timeframe, we may need to cease operations.

Going Concern

The report of our independent registered public accounting firm on the financial statements for the year ended March 31, 2009 and 2008 includes an explanatory paragraph relating to the uncertainty of our ability to continue as a going concern. We have incurred a cumulative net loss of $71.0 million for the period from inception (February 4, 2004) to June 30, 2009. As of June 30, 2009 we had cash on hand of $0.6 million, short term debt of $10.1 million and we

have a working capital deficit of approximately $10.0 million. Our short term debt in the amount of $10.1 million has a scheduled maturity date of October 15, 2009. We require significant additional funding to repay the short term debt and sustain our current operations. Our ability to continue the Company as a going concern is dependent upon our ability to obtain additional funding in order to pay our short term debt and finance our planned operations.

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

In October 2007, we issued $12,240,000 of short term debt the proceeds of which were intended to enhance our existing production and to provide cash reserves for operations. The debt was scheduled to mature on October 31, 2008. We had planned to secure longer term fixed rate financing to repay the short term debt and to commence our EOR development activities in the three fields of the Powder River Basin; however, due to difficulties in the capital debt markets, we have been unable to secure such financing. On October 22, 2008 we and the lender entered into an amendment to the credit agreement to, among other terms, extend the maturity date by six months, until April 30, 2009. In consideration for the extension and other terms, we made a principal payment of $2,240,000 reducing the outstanding balance to $10,000,000. Subsequent the end of our fiscal year we and the lender entered into a series amendments to the credit agreement ultimately extending the maturity date to October 15, 2009. We do not have cash available to repay this loan. If we are not successful in repaying this debt within the term of the loan, or default under the terms of the loan, the lender will be able to foreclose one or more of our three properties and other assets and we could lose the properties. A foreclosure could significantly reduce or eliminate our property interests or force us to alter our business strategy, which could involve the sale of properties or working interests in the properties. A foreclosure would adversely affect our results of operations and financial condition including a possible termination of business activities.

Beginning in March 2008, we reduced our level of staffing by laying off several employees whose positions were considered to be redundant based upon the anticipated closing of a farmout transaction with experienced industry operators. Neither the original nor a subsequently identified farmout transaction was completed; however we continued field and corporate operations utilizing the remaining staff and, on a very limited contract basis, the utilization of contract consultants. At that time our monthly oil and gas production revenue was adequate to cover monthly field operating costs, production taxes and general and administrative expenses; however, interest payments on short term debt and payments relating to our crude oil hedging position resulted in negative cash flow each month. Crude oil prices which collapsed commencing in August 2008 have recovered somewhat recently; however at current NYMEX strip prices our expected future cash flows from crude oil sale are inadequate to cover monthly field operating costs, production taxes and general and administrative expenses. This negative cash flow is offset to some extent by proceeds realized from our crude oil hedging position. This hedge expires in October 2009. Our current cash reserves are not adequate to fund our operations for the next fiscal year.

We have executed two agreements to purchase CO2 for use in EOR operations in our fields. Each contract contains provisions for a take or pay obligation for the purchase of CO2. ExxonMobil has given us notice of termination of their supply agreement. We disagree with their position and have notified them of our disagreement. As of the date of this Quarterly Report, we are currently in discussions with Anadarko to amend the Purchase Contract to minimize or eliminate certain uncertain provisions and terms of the agreement that are subject to differing interpretations. There is no assurance we will successfully complete any such amendment and in the event we do not, we will likely be unable to sustain operations or meet our obligations under the supply agreement

In August 2009, we filed an Application for Financial Assistance under the U.S. Department of Energy Funding Opportunity Announcement No. DE-FOA-0000015, Carbon Capture and Sequestration from Industrial Sources and Innovative Concepts for Beneficial CO2 Use (the “FOA”). We applied for a grant under Phase 1 provisions of the FOA which, if awarded, will be utilized to complete reservoir engineering studies, drilling and surface facility design and pipeline design and permitting for one of our Powder River Basin EOR oil fields. We requested a grant in the amount of $3.72 million, which is equal to 80% of the $4.65 million Phase 1 budget. In the application, we proposed, as our 20% cost share, a “contribution in kind” of costs previously incurred on pipeline, surface facilities and reservoir studies equal to $0.93 million. . If we are awarded a Phase 1 Grant, we plans to apply for a Phase 2 grant in an amount of up to $175 million to undertake a comprehensive CO2 capture, transportation, EOR, and sequestration project in that field. We believes our EOR project is well qualified for awards under the provisions of the FOA; however, there is no assurance that we will obtain a Phase 1 grant, or if we do obtain a Phase 1 grant, there is no assurance we will be successful in obtaining a Phase 2 grant. Further, there is no assurance that if we obtain a Phase 2 grant, that our CO2 capture, transportation, EOR, and sequestration project will be technically or commercially successful.

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

	For the Three Months Ended June 30,
	2009			2008
Cash flows from (used for):
Operating activities	$	(323,754	)	$	(1,181,558	)
Investing activities		10,466			(347,642	)
Financing activities		5			(113,250	)

Cash flows used for operating activities decreased substantially as a result of lower general and administrative and lease operating expenses as discussed above, coupled with realized derivative gains in the quarter

Investing activities ion 2009 reflect a modest positive cash flow resulting from the sale of surplus field equipment in the period, compared to oil and gas capital expenditures of $189,579 and expenditures to increase bonds of $158,063 in the 2008 period.

Cash flows from financing activities in 2009 reflect proceeds from the exercise of common stock options, compared to expenditures incurred on deferred financing costs in the 2008 period.

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 three months ended June 30, 2009, we reflected realized gains of $95,113 and unrealized gains of $411,522 from the hedging activity, as compared to realized losses of $350,479 and unrealized losses of $1,544,814 for the comparable 2008 period.

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

Critical Accounting Policies and Estimates

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 fiscal year ended March 31, 2009. 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 June 30, 2009.

Item 3. Quantitative and Qualitative Disclosure About Market Risk.

Commodity Price Risk

Because of our relatively low level of current oil and gas production, we are not exposed to a great degree of market risk relating to the pricing applicable to our oil production. However, our ability to raise additional capital at attractive pricing, our future revenues from oil and gas operations, our future profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. With increases to our production, exposure to this risk will become more significant. We expect commodity price volatility to continue. Under the terms of our Term Credit Agreement we entered into in October 2007, we were required hedge a portion of our expected future production.

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 October 15, 2009. Alternatively, market conditions may affect the availability of capital for prospective purchasers of our assets or equity.

Item 4T. 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, 2009 and as of the end of the period covered by this Quarterly Report 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 6. EXHIBITS.

Exhibit		Description
3.1		Amended and Restated Articles of Incorporation (1)

3.2		Articles of Correction (2)

3.3		Amended and Restated Bylaws (3)

4.1		Form of Stock Certificate for Fully Paid, Non-Assessable Common Stock of the Company (4)

4.2		Form of Registration Rights Agreement, dated December 21, 2006 (5)

4.3		Form of Warrant to Purchase Common Stock (5)

10.1		Employment Agreement between John Works and Rancher Energy Corp., dated June 1, 2006 (6)

10.2		Assignment Agreement between PIN Petroleum Partners Ltd. and Rancher Energy Corp., dated June 6, 2006 (6)

10.3		Loan Agreement between Enerex Capital Corp. and Rancher Energy Corp., dated June 6, 2006 (6)

10.4		Letter Agreement between NITEC LLC and Rancher Energy Corp., dated June 7, 2006 (6)

10.5		Loan Agreement between Venture Capital First LLC and Rancher Energy Corp., dated June 9, 2006 (7)

10.6		Exploration and Development Agreement between Big Snowy Resources, LP and Rancher Energy Corp., dated June 15, 2006 (6)

10.7		Assignment Agreement between PIN Petroleum Ltd. and Rancher Energy Corp., dated June 6, 2006 (6)

10.8		Rancher Energy Corp. 2006 Stock Incentive Plan (8)

10.9		Rancher Energy Corp. 2006 Stock Incentive Plan Form of Option Agreement (8)

10.10		Denver Place Office Lease between Rancher Energy Corp. and Denver Place Associates Limited Partnership, dated October 30, 2006 (9)

10.11		Amendment to Purchase and Sale Agreement between Wyoming Mineral Exploration, LLC and Rancher Energy Corp. (10)

10.12		Product Sale and Purchase Agreement by and between Rancher Energy Corp. and the Anadarko Petroleum Corporation, dated December 15, 2006(11)

10.13		Voting Agreement between Rancher Energy Corp. and Stockholders identified therein, dated as of December 13, 2006 (5)

10.14		Rancher Energy Corp. 2006 Stock Incentive Plan Form of Restricted Stock Agreement (12)

10.15		First Amendment to Employment Agreement by and between John Works and Rancher Energy Corp., dated March 14, 2007 (13)

10.16		Employment Agreement between Richard Kurtenbach and Rancher Energy Corp., dated August 3, 2007(14)

10.17		Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated as of October 16, 2007 (15)

10.18		Term Note made by Rancher Energy Corp. in favor of GasRock Capital LLC, dated October 16, 2007 (15)

10.19		Mortgage, Security Agreement, Financing Statement and Assignment of Production and Revenues from Rancher Energy Corp. to GasRock Capital LLC, dated as of October 16, 2007 (16)

10.20		Security Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated as of October 16, 2007 (15)

10.21		Conveyance of Overriding Royalty Interest by Rancher Energy Corp. in favor of GasRock Capital LLC, dated as of October 16, 2007 (15)

10.22		ISDA Master Agreement between Rancher Energy Corp. and BP Corporation North America Inc., dated as of October 16, 2007 (15)

10.23		Restricted Account and Securities Account Control Agreement by and among Rancher Energy Corp., GasRock Capital LLC, and Wells Fargo Bank, National Association, dated as of October 16, 2007 (15)

10.24		Intercreditor Agreement by and among Rancher Energy Corp., GasRock Capital LLC, and BP Corporation North America Inc., dated as of October 16, 2007 (15)

10.25		First Amendment to Denver Place Office lease between Rancher Energy Corp. and Denver Place Associates Limited Partnership, dated March 6, 2007 (13)

10.26		Carbon Dioxide Sale & Purchase Agreement between Rancher Energy Corp. and ExxonMobil Gas & Power Marketing Company, dated effective as of February 1, 2008 (Certain portions of this agreement have been redacted and have been filed separately with the Securities and Exchange Commission pursuant to a Confidential Treatment Request). (16)

10.27		Stay Bonus Agreements between Rancher Energy Corp. and John Works and Richard E. Kurtenbach and all of the Company’s employees, dated October 2, 2008. (17)

10.28		First Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated October 22, 2008. (18)

10.29		Assignment Agreement between Rancher Energy Corp. and Merit Energy Company, LLC, dated March 18, 2009. (19)

10.30		Termination of Carbon Dioxide Sale & Purchase Agreement between Rancher Energy Corp. and ExxonMobil Gas & Power Marketing Company, dated April 3, 2009. (20)

10.31		Second Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated April 30, 2009. (21)

10.32		Third Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 8, 2009. (22)

10.33		Fourth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 13, 2009. (23)

10.34		Fifth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 19, 2009. (24)

10.35		Sixth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 21, 2009. (25)

10.36		Seventh Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated May 27 2009. (26)

10.37		Eighth Amendment to Term Credit Agreement between Rancher Energy Corp. and GasRock Capital LLC, dated June 3, 2009. (27)

31.1		Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Executive Officer)*

31.2		Certification Pursuant to Rule 13a-14(a)/15d-14(a) (Chief Accounting Officer)*

32.1		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002*

32.2		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002*

* Filed herewith.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(17)	Incorporated by reference from our Current Report on Form 8-K filed on October 3, 2008.

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

(19)	Incorporated by reference from our Current Report on Form 8-K filed on March 24, 2009.

(20)	Incorporated by reference from our Current Report on Form 8-K filed on April 9, 2009.

(21)	Incorporated by reference from our Current Report on Form 8-K filed on April 30, 2009.

(22)	Incorporated by reference from our Current Report on Form 8-K filed on May 11, 2009.

(23)	Incorporated by reference from our Current Report on Form 8-K filed on May 14, 2009.

(24)	Incorporated by reference from our Current Report on Form 8-K filed on May 20, 2009.

(25)	Incorporated by reference from our Current Report on Form 8-K filed on May 22, 2009.

(26)	Incorporated by reference from our Current Report on Form 8-K filed on May 28, 2009.

(27)	Incorporated by reference from our Current Report on Form 8-K filed on June 5, 2009.

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: August 19, 2009	By:	/s/ John Works
		John Works, President, Chief Executive Officer,
		Chief Financial Officer, Secretary and Treasurer
		(Principal Executive Officer)

Dated: August 19, 2009	By:	/s/ Richard E. Kurtenbach
		Richard E. Kurtenbach, Chief Accounting Officer
		(Principal Accounting Officer)