NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited interim financial statements of Red Mountain have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the Securities and Exchange Commission (“SEC”), and should be read in conjunction with the audited financial statements and notes thereto contained in the Company’s audited financial report filed as part of Form 8-K/A, as filed on October 24, 2011. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of the financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.

Liquidity

The Company expects to make significant capital expenditures in the foreseeable future relating to drilling existing proved and undeveloped reserves and the acquisition of other producing oil and gas properties. Management believes they will be successful in obtaining adequate sources of cash to fund its anticipated capital expenditures through the end of fiscal year 2012 and to follow through with plans for continued investments in oil and gas properties.

The Company's success, in part, depends on its ability to generate additional financing and on its ability to effectively manage growth and develop proven reserves. It is anticipated that these exploration activities together with others that may be entered into may impose financial requirements which may exceed the existing working capital of the Company. Management may raise additional equity and/or debt capital. However, if additional financing is not available, the Company may be compelled to reduce the scope of its business activities. The unaudited interim financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

Principles of Consolidation

The consolidated financial statements include the accounts of Red Mountain and its wholly-owned subsidiaries, Black Rock and RMR Operating, LLC. All significant intercompany balances and transactions have been eliminated. The Company also has a 14.6% interest in Cross Border Resources Inc. (“Cross Border”), which has not been consolidated into its financial statements.

Use of Estimates

In the course of preparing the condensed consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in impairment of oil and gas properties; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of investment in Cross Border and Bamco note receivable and (8) accrued liabilities. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

The Company considers all highly liquid instruments with an original maturity of less than 90 days to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable from joint interest owners consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, trade, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. The Company provides for a reserve against receivables for estimated losses that may result from a customer's inability or unwillingness to pay. The allowance for doubtful accounts is estimated primarily based upon historical write-off percentages, known problem accounts, and current economic conditions. Accounts are written off against the allowance for doubtful accounts when the Company determines that amounts are not collectable. Recoveries of previously written-off accounts are recorded when collected. As of August 31, 2011, there was no reserve established as all amounts were deemed collectible.

Investments

The Company carries its investments in equity securities at fair value, based on quoted market prices when available. Security transactions are recorded on a trade date basis. Realized gains and losses are determined by the specific identification method and are included in income. Unrealized gains and losses on securities available-for-sale are reported as a component of accumulated other comprehensive income.

Management determines the appropriate classification of its investments at the time of purchase and reevaluates such determination at each balance sheet date. Equity securities are classified as "available-for-sale." At August 31, 2011, the Company had no trading securities or investments in debt securities that it plans to hold to maturity.

Oil and Gas Properties

Effective June 1, 2011, the Company follows the successful efforts method of accounting for its oil and gas producing activities. The change in accounting principle has been applied retroactively to prior periods. See Note 3 for further discussion. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If management determines that the wells do not have proved reserves, the costs are charged to expense. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. No interest was capitalized during the periods presented.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income. A sale of a significant property is treated as discontinued operations.

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six mcf of gas to one bbl of oil. Depreciation and depletion expense for oil and gas producing property and related equipment was $280,407 and $160,150 for the three months ended August 31, 2011 and 2010, respectively.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. The Company recorded no unproved property impairment during the quarter ended August 31, 2011.

Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company will recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. No impairment was determined necessary.

It is common for operators of oil and gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. The Company records these advance payments in prepaid and other current assets in its property account and release this account when the actual expenditure is later billed to it by the operator.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Estimates of Proved Oil and Gas Reserves

Estimates of our proved reserves are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

The Company’s proved reserve information was predominately based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

In accordance with SEC requirements, beginning December 31, 2009, the Company based the estimated discounted future net cash flows from proved reserves on the unweighted arithmetic average of the prior 12-month commodity prices as of the first day of each of the months constituting the period and costs on the date of the estimate. In prior years, such estimates had been based on year end prices and costs. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.

The estimates of proved reserves materially impact depreciation and depletion expense. If the estimates of proved reserves decline, the rate at which we record depreciation and depletion expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields.

Revenue Recognition

Revenues are recognized when hydrocarbons have been delivered, the customer has taken title and payment is reasonably assured.

Income Taxes

Income tax expense was as follows:

	Three Months Ended			Three Months Ended
	August 31, 2010			August 31, 2011
Income tax expense		-			-
Effective tax rate		0.00	%		0.00	%

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the three months ended August 31, 2010, our overall effective tax rate differed from the statutory rate of 35% because we operated as a partnership not subject to income tax during that period.

For the three months ended August 31, 2011, our overall effective tax rate differed from the statutory rate of 35% because of our change in tax status and valuation allowances offsetting deferred tax assets.

The Company changed it's tax status from a partnership to a corporation effective June 1, 2011. This conversion required the Company to recognize income tax expense and deferred tax liabilities of $522,593 on the date of the change. The Company recorded an offsetting income tax benefit of $1,668,645 based on deferred tax assets generated during the three months ended August 31, 2011. The net deferred tax asset was fully reserved resulting in no net income tax expense for the period.

Pro forma income tax expense represents the tax effects that would have been reported had the Company been subject to U.S. federal and state income taxes as a corporation for all periods presented.

The following table presents the computation of the pro forma income tax expense:

	Three Months Ended
	August 31, 2010
Income before Income Taxes		569,169
Effective pro forma income tax rate		34	%
Pro forma Income Tax Expense (Benefit)		193,517

Asset Retirement Obligations

The Company provides for future asset retirement obligations on its resource properties and facilities based on estimates established by current legislation and industry practices. The asset retirement obligation is initially measured at fair value and capitalized to oil and gas properties as an asset retirement cost that is depleted over the units of production. The obligation is accreted through accretion expense until it is settled. The fair value of the obligation is estimated by discounting expected future cash outflows to settle the asset retirement obligations using a credit-adjusted risk-free interest rate. The Company recognizes revisions to either the timing or the amount of the original estimate of undiscounted cash outflows as increases or decreases to the asset retirement obligation.

The significant assumptions used to develop the expected liability during the period are as follows:

Average gross cost to remediate individual well sites	$	75,000 - 100,000
Average gross salvage value expected from individual well sites remediated	$	15,000 - 25,000
Expected inflation rate for oil field service costs		4.50	%
Credit adjusted risk-free interest rate		7.25	%

Actual retirement costs will be recorded against the obligation when incurred. Any difference between the recorded asset retirement obligations and the actual retirement costs incurred is recorded as a gain or loss in the settlement period. Three new well obligations were recognized in the first quarter. A change in estimate resulted from a change in well lives for the Madera oil wells.

Balance at June 1, 2011	$	239,536
Liabilities incurred		53,577
Change in estimate		(35,807	)
Liabilities settled
Accretion expense		4,342
Balance at August 31, 2011		261,648

Comprehensive Income (Loss)

Comprehensive income (loss) includes changes in stockholders’ equity during the periods that do not result from transactions with stockholders. Our total comprehensive income (loss) for the periods is as follows:

	Three Months Ended August 31,
	2011			2010
Net income (loss)	$	(3,177,877	)	$	569,169
Unrealized loss on investment in Cross Border investment		(1,552,123	)		-
Total comprehensive income (loss)	$	(4,730,000	)	$	569,169

Concentrations

Upon acquisition of its oil and gas field interests, the Company also became party to joint operating agreements ("JOA's") that define the rights and responsibilities between the third party operators and passive interest holders. Under the JOA's, the third party operator is responsible for acquiring customers to sell the oil and gas produced and to either performing or contracting out to other third parties to perform services necessary to continue and maintain well production, commence and complete drilling operations and also to maintain undeveloped acreage. The Company is thus dependent upon the third party operator to remit payment for its share of the proceeds from the sale of hydrocarbons produced, and to adequately maintain and develop the individual fields. As of August 31, 2011, one operator, ConocoPhillips, Inc., controlled approximately 86% of the Company's revenues and approximately 77% of direct operating expenses.

Concentrations of Market Risk

The future results of the Company's oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The Company operates in the exploration, development and production sector of the oil and gas industry. The Company's receivables include amounts due from purchasers of its oil and natural gas production and amounts due from joint venture partners for their respective portions of operating expenses and exploration and development costs. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company's results of operations over the long-term. Trade receivables are generally not collateralized.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date ("exit price"). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities ("Level 1"), a middle priority to inputs based on other than quoted prices in active markets ("Level 2") and the lowest priority to unobservable inputs ("Level 3"). In instances in which multiple levels of inputs are used to measure fair value, hierarchy classification is based on the lowest level input that is significant to the fair value measurement in its entirety. The three levels of the fair value hierarchy are as follows:

Level 1 — Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 — Other inputs that are observable, directly or indirectly, such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 — Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

The following table presents recurring financial assets and liabilities which are carried at fair value as of August 31, 2011:

	Fair Value		Level 1		Level 2		Level 3
Investment in Cross Border Resources, Inc. common shares and warrants		4,763,915		3,061,109		-		1,702,806
Warrant liability		519,942		-		-		519,942

The reconciliation of the fair value for our Level 3 assets and liabilities including net purchases and sales and changes in unrealized gains, is set out below:

	Cross Border Warrants		Warrant Liability
Balance, May 31, 2011	$	1,217,613	$	-
Award of Warrants		-		(615,401	)
Unrealized gain recorded in other comprehensive income		485,193		-
Unrealized gain recorded in earnings		-		95,458
Balance, August 31, 2011	$	1,702,806	$	(519,943	)

During the quarter, management revised the industry comparable companies used to determine the historical volatility. The new companies represent small publicly traded domestic exploration and production companies. Management believes these companies provide a better estimation of Cross Border’s volatility.

Financial Instruments

The Company's financial instruments consist of cash and cash equivalents, receivables, payables, and notes payable and lines of credit. The carrying amounts of cash and cash equivalents, receivables, payables and short-term debt approximate fair value due to the highly liquid or short-term nature of these instruments.

Recent Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board ("FASB") issued an update to the Oil and Gas Topic, which aligns the oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC's final rule, Modernization of the Oil and Gas Reporting Requirements (the "Final Rule"). The Final Rule was issued on December 31, 2008. The Final Rule is intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves, which should help investors evaluate the relative value of oil and natural gas companies.

In January 2010, the FASB issued ASU 2010-06, "Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements" ("ASU 2010-06"). ASU 2010-06 includes new disclosure requirements related to fair value measurements, including transfers in and out of Levels 1 and 2 and information about purchases, sales, issuances and settlements for Level 3 fair value measurements. This update also clarifies existing disclosure requirements relating to levels of disaggregation and disclosures of inputs and valuation techniques. ASU 2010-06 was effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The Company adopted ASU 2010-06 upon issuance and such adoption did not have a material impact on the Company's financial statements.

In May 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 will be effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. The Company believes that the adoption of this standard will not materially expand the consolidated financial statement footnote disclosures.

In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income” (“ASU 2011-05”), which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, we must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. ASU 2011-05 will be effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. The adoption of ASU 2011-05 will not have a material impact on the consolidated financial statements.

In December 2010, the FASB issued an accounting standard update 2010-29 that addresses the disclosure of supplementary pro forma information for business combinations. This update clarifies that when public entities are required to disclose pro forma information for business combinations that occurred in the current reporting period, the pro forma information should be presented as if the business combination occurred as of the beginning of the previous fiscal year when comparative financial statements are presented. This update is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Early adoption is permitted. The Company’s adoption of this standard did not have a material effect on its results of operation or its financial position.