The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States ("GAAP") and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods.

Certain amounts in the December 31, 2010 consolidated financial statements have been reclassified to conform to the December 31, 2011 consolidated financial statement presentation. Such reclassifications had no effect on net income.

The preparation of the financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management evaluates its estimates based on historical experience and on various other factors that the Company believes to be reasonable under the circumstances. Actual results could differ from those estimates.

Our most significant financial estimates are associated with our estimated proved oil and gas reserves as well as valuation of common stock used in various issuances of common stock, options and warrants. Significant financial estimates are also required for the analysis of impairment of oil and gas properties.

The accompanying consolidated financial statements include Recovery Energy, Inc. and its wholly−owned subsidiaries Recovery Oil and Gas, LLC, and Recovery Energy Services, LLC. All intercompany accounts and transactions have been eliminated in consolidation. Both subsidiaries were inactive and were dissolved in the 4th quarter of 2011.

Cash used in operating activities during the year ended December 31, 2011 was $.6 million and cash used in investing activities exceeded cash provided by financing activities by approximately $2.2 million. This net cash use contributed to a substantial decrease in our net working capital as of December 31, 2011. Expenditures subsequent to December 31, 2011 have continued to exceed cash receipts, causing a further reduction of the Company’s working capital position.

In the immediate term, the Company expects that additional capital will be required to fund its capital budget for 2012, partially to fund some of its ongoing overhead, and to provide additional capital to generally improve its working capital position. We anticipate that these capital requirements will be funded by a combination of capital raising activities, including the selling of additional debt and/or equity securities and the selling of certain assets. If we are not successful in obtaining sufficient cash sources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring portions of our 2012 capital budget.

Pursuant to our credit agreements with Hexagon, a substantial portion of our monthly net revenues derived from our producing properties is required to be used for debt and interest payments. In addition, our debt instruments contain provisions that, absent consent of the Lenders, may restrict our ability to raise additional capital.

Since inception, the Company raised approximately $72 million in cash generally through private placements of debt and equity securities. In December 2011, the Company sold certain undeveloped acreage for total proceeds of $4.5 million. During 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues of approximately $2,000,000 in the aggregate as payment on the Hexagon debt. In November 2011, Hexagon extended the maturity date of their notes to January 1, 2013, and also advanced an additional $309,000 to the Company. The Company repaid the $309,000 advance in February 2012. In March 2012, Hexagon extended the maturity date of their notes to June 30, 2013, and in connection therewith, the Company agreed to make minimum note payments of $325,000, effective immediately. The Company will continue to pursue alternatives to shore up its working capital position and to provide funding for its planned 2012 expenditures.

The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables for years ended December 31, 2011or December 31, 2010. Receivables which derive from sales of certain oil and gas production are collateral for our Loan Agreements (see Note 7).

During the year ended December 31, 2010, the Company wrote off a note receivable for $400,000 as a bad debt expense (see Note 13). During the year ended December 31, 2011 and period ended December 31, 2009, no receivable amounts were written off to bad debt expense.

The Company's cash, cash equivalents and short-term investments are invested at major financial institutions primarily within the United States. At December 31, 2011 and December 2010, the Company’s cash and cash equivalents were maintained in accounts that are insured up to the limit determined by the federal governmental agency. The Company may at times have balances in excess of the federally insured limits.

The Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.

During the year ended December 31, 2011 and December 31, 2010, approximately 76% and 64%, respectively, of the Company's revenue sold to one customer, Shell Trading (US). However, the Company does not believe that the loss of a single purchaser, including Shell Trading (US), would materially affect the Company's business because there are numerous other purchasers in the area in which the Company sells its production.

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration, development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves, and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that are not otherwise included in capitalized costs.

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to sum of i.) the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves, plus ii.) the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. As of December 31, 2011, the Company recognized an impairment of $2,821,176. During the year ended December 31, 2010 and period ended December 31, 2009, no impairment charges were recognized.

The present value of estimated future net revenues was computed by applying a twelve month average of the first day of the month price of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.

The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties or the amount of the impairment is added to costs subject to depletion calculations. During the year ended December 31, 2011, the Company impaired $3,861,875 of unproved property value. During the years ending December 31, 2010 and December 31, 2009, no impairment was recorded.

Wells in progress represent wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to exploration and development costs and become subject to both depletion and the ceiling test calculations in future periods. At December 31, 2011, the Company had two wells in progress, both of which have been drilled and completed and are pending evaluation as to their potential to produce commercial quantities of oil and gas reserves.

As of December 31, 2011 and December 31, 2010, the Company recorded unamortized deferred financing costs of approximately $2.3 million and $3.2 million, respectively, related to the closing of its loans and credit agreements (see Note 7). Deferred financing costs include origination (warrants issued and overriding royalty interests assigned to our lender), legal and engineering fees incurred in connection with the Company's credit facility, which are being amortized over the term of the credit facility. The Company recorded amortization expense of approximately $5.0 million and $4.0 million, respectively, in the years ended December 31, 2011 and December 31, 2010.

The Company accounts for prepaid advisory services with the total consideration amortized over the underlying service agreement period. As of December 31, 2011 and 2010 prepaid financial advisory fees were approximately $574,000 and $979,000, respectively. The prepaid fees were paid with non-cash consideration (shares of our common stock and warrants exercisable for shares of our common stock issued to our financial advisors) initially issued in 2010 in the amount of $1,234,000. This amount is being amortized over the term of the underlying agreement. The Company amortized $405,000 and $247,000, respectively of prepaid fees during the years ended December 31, 2011 and December 31, 2010.

Property and equipment (other than the full cost pool) are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from one to 7 years. The Company recorded $34,000 and $5,000 of depreciation for the years ended December 31, 2011 and December 31, 2010, respectively.

The Company accounts for long-lived assets (other than the full cost pool), which include property and equipment, prepaid advisory fees, and identifiable intangible assets with finite useful lives (subject to amortization, depletion, and depreciation), whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.

For the period ended December 31, 2009, the Company recorded impairment expense of $2,750,000 related to the two medium depth drilling rigs. As of December 31, 2011 and 2010, no impairment has been recorded for long lived assets other than the impairment of its capitalized oil and gas property costs during 2011 as discussed above.

As of December 31, 2011 and 2010, the carrying value of cash and cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits approximates fair value due to the short-term nature of such items. The carrying value of other long-term liabilities approximates fair value as the related interest rates approximate rates currently available to Recovery Energy, certain other assets and liabilities are measured at fair value as discussed in Note 6.

The Company utilizes swaps to reduce the effect of price changes on a portion of our future oil production. On a monthly basis, a swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price. The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivative contracts to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions (see Note 5).

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts are currently with one counterparty. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement (see Note 5).

The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable.

The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value.

For purposes of depletion calculations, the Company also includes estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations.

Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated to operating expense using a systematic and rational method. As of December 31, 2011 and 2010, the Company recorded a net asset of $592,150 and $540,707 and a related liability of $612,874 and $507,280 (see Note 6).

	For the years ended December 31,
	2011		2010
Balance, beginning of period	$	507,280		-
Liabilities incurred		61,469		478,208
Accretion expense		44,125		28,042
Change in estimate		-		1,030
Balance, end of period	$	612,874	$	507,280

The Company measures the fair value of share-based compensation expense awards made to employees and directors, including stock options, restricted stock and employee stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. The measurement of share-based compensation expense is based on several criteria, including but not limited to the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining share-based compensation expense and the actual factors, which become known over time, Recovery may change the input factors used in determining future share-based compensation expense.

Recovery accounts for option grants to non-employees whereby the fair value of such options is determined using the Black-Scholes option pricing model at the earlier of the date at which the non-employee’s performance is complete or a performance commitment is reached (Note 12).

The Company accounts for the modification of warrants as an exchange of the old award for a new award. The incremental value is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a period expense or amortized over the performance or vesting date. We estimate the incremental value of each warrant using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree of subjective judgment is the estimated volatility of our stock price (Note 12).

Basic earnings (loss) per share is based on the weighted average number of common shares outstanding during the period presented. In addition to common shares outstanding, diluted loss per share is computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares. Potentially dilutive securities, such as stock grants and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive. For the years ended December 31, 2011 and December 31, 2010, outstanding warrants and derivatives of 5,638,900 and 5,764,233, respectively, have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. Accordingly, basic shares equal diluted shares for all periods presented. On October 16, 2011, the Company affected a 4:1 reverse stock split.

The Company uses the asset liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities, and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization.

We recognize tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards. As of December 31, 2011, the Company has determined that no liability is required to be recognized.

Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. However, we did not accrue interest or penalties at December 31, 2011 and December 31, 2010, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest on underpayments of tax and we believe that we are below the minimum statutory threshold for imposition of penalties. We do not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months. The earliest years remaining subject to examination are April 30, 2010 and 2009.