Lilis Energy 10Q 2010 Q2 Quarterly report

Lilis Energy (LLEX) 10-Q2010 Q2 Quarterly report

Content analysis

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, 2010

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

For the transition period from ______to______.

RECOVERY ENERGY, INC.

(Exact name of registrant as specified in Charter)

NEVADA		333-152571		74-3231613
(State or other jurisdiction of incorporation or organization)		(Commission File No.)		(IRS Employee Identification No.)

1515 Wynkoop Street, Suite 200

Denver, CO 80202

(Address of Principal Executive Offices)

_______________

1 (888) 887-4449

(Issuer Telephone number)

_______________

Check whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the issuer 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 ¨ No ¨

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

Large Accelerated Filer o Accelerated Filer o Non-Accelerated Filer o Smaller 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

State the number of shares outstanding of each of the issuer’s classes of common equity, as of August 13, 2010: 38,830,933 shares of Common Stock.

Recovery Energy, Inc.

FORM 10-Q

June 30, 2010

INDEX

PART I– FINANCIAL INFORMATION

Item 1.	Financial Statements	1
	Consolidated Balance Sheets as of June 30, 2010 (Unaudited) and December 31, 2009 (Unaudited)	1
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010, the three months ended June 30, 2009 and the period from March 6, 2009 through June 30, 2009 (Unaudited)	3
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and the period from March 6, 2009 (inception) through June 30, 2009 (Unaudited)	4
	Notes to Consolidated Financial Statements (Unaudited)	5
Item 2.	Management’s Discussion and Analysis of Financial Condition	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4T.	Control and Procedures	28

PART II– OTHER INFORMATION

Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 3.	Defaults Upon Senior Securities	30
Item 4.	Submission of Matters to a Vote of Security Holders	30
Item 5.	Other Information	30
Item 6.	Exhibits and Reports on Form 8-K	30

SIGNATURES

Part 1. Financial Information

Item 1. Financial Statements

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30,			December 31,
	2010			2009
Assets
Current Assets
Cash	$	2,155,162		$	108,400
Restricted Cash		184,494			20,876
Accounts Receivable		1,567,821			100,000
Assets from price risk management		629,206			-
Prepaid assets		106,595			55,249
Total current assets		4,643,278			284,525

Oil and gas properties (full cost method), at cost:
Undeveloped properties		23,323,115			-
Developed properties		24,452,355			-
Wells in progress		274,064			-
Lease & well equipment		97,389			-
Total Property and equipment		48,146,923			-

Less accumulated depreciation, depletion and amortization		(2,431,792	)		-
Net properties and equipment		45,715,131			-

Other assets
Office equipment		2,156			470
Prepaid assets		1,182,094			-
Deferred financing costs		4,114,776			-
Restricted cash and deposits		185,431			110,031
Notes receivable		400,000			-
Assets held for sale		-			500,000
Total other assets		5,884,457			610,501

TOTAL ASSETS	$	56,242,866		$	895,026

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

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30,			December 31,
	2010			2009
Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable	$	491,909		$	106,355
Related Party Payable		119,864			70,876
Common Stock Issuable		-			100,000
Accrued expenses		710,455			51,523
Short term note		892,500			-
Total current liabilities		2,214,728			328,754

Asset retirement obligation		422,666			-
Term note		22,359,995			-
Total long term liabilities		22,782,661			-

Total liabilities		24,997,389			328,754
Commitments and Contingencies – Note 9

Common Stock subject to redemption rights, $0.0001 par value;		172,516			172,516
85,000 shares issued and outstanding

Other Shareholders’ Equity
Common Stock, $0.0001 par value: 100,000,000 shares authorized;
38,748,015 and 10,774,000 shares issued and outstanding (excluding 85,000 shares subject to redemption) as of June 30, 2010 and December 31, 2009, respectively		4,075			1,077
Additional Paid in Capital		66,997,759			30,304,060
Accumulated deficit		(35,928,873	)		(29,911,381	)
Total other shareholders' equity		31,072,961			393,756

TOTAL LIABILITIES, COMMON STOCK SUBJECT TO REDEMPTION RIGHTS AND OTHER SHAREHOLDERS’ EQUITY	$	56,242,866		$	895,026

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

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Three months ended June 30,						Six months ended			March 6, 2009 (inception) through
	2010			2009			June 30, 2010			June 30, 2009

Revenue
Oil sales	$	4,157,757		$	-		$	4,780,352		$	-
Operating fees		1,688			-			2,813			-
Realized gain on hedges		272,829			-			272,829			-
Price risk management activities		762,575			-			629,206			-

Total Revenues		5,194,849			-			5,685,200			-

Costs and expenses
Production costs		224,111			-			345,988			-
Production taxes		485,424			-			520,911			-
General and administrative (includes non-cash expense of $2.5 million and $4.5 million for the three and six month periods ending June 30, 2010)		3,068,698			200			5,412,019			200
Depreciation, depletion and amortization		2,209,496			-			2,441,413			-

Total costs and expenses		5,987,729			200			8,720,331			200

Loss from operations		(792,880	)		(200	)		(3,035,131	)		(200	)

Unrealized gain on Lock-up		8,858			-			24,067			-
Interest expense (includes non-cash deferred financing cost amortization expense of $1.5 million and $2.0 million for the three and six month periods ending June 30, 2010)		(2,412,757	)		-			(3,006,428	)		-

NET LOSS	$	(3,196,779	)	$	(200	)	$	(6,017,492	)	$	(200	)

Net loss per common share
Basic and diluted	$	(0.13	)				$	(0.32	)

Weighted average shares outstanding:
Basic and diluted		25,451,688						18,619,320

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

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six months ended			March 6, 2009 (inception)
	June 30, 2010			through June 30, 2009

Cash flows from operating activities
Net loss	$	(6,017,492	)	$	(200	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Stock issued for services		66,363			-
Stock based compensation		2,781,467			-
Changes in the fair value of derivatives		(629,206	)		-
Compensation expense recognized for assignment of overrides		1,578,080			-
Amortization of deferred financing costs		2,022,974			-
Depreciation, depletion, and accretion		2,441,413			-
Changes in operating assets and liabilities:
Accounts receivable		(1,467,821	)		-
Other current assets		12,457			-
Accounts payable		395,628			-
Restricted cash		(163,618	)		-
Related party production payments		38,914			-
Accrued expenses		658,933			-
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		1,718,092			(200)

Cash flows from investing activities
Additions of producing properties and equipment (net of purchase price adjustments)		(21,102,540	)		-
Acquisition of properties		(24,352,980	)		-
Drilling capital expenditures		(402,944	)		-
Proceeds from sale of drilling rigs		100,000			-
Additions of office equipment		(1,688	)		-
Investment in operating bonds		(75,400	)		-
NET CASH USED IN INVESTING ACTIVITIES		(45,835,552	)		-

Cash flows from financing activities
Net proceeds from sale of common stock		22,911,727			200
Proceeds from debt issuance		28,500,000			-
Repayment of debt		(5,247,505	)		-
NET CASH PROVIDED BY FINANCING ACTIVITIES		46,164,222			200

Net increase in cash and cash equivalents		2,046,762			-
Cash and cash equivalents, beginning of period		108,400			-

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	2,155,162		$	-

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

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

NOTE 1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ORGANIZATION

Basis of Presentation

The unaudited financial statements included herein were prepared from the records of Recovery Energy, Inc. (“Recovery” or the “Company”) in accordance with generally accepted accounting principles in the United States applicable to interim financial statements 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. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year. Such financial statements conform to the presentation reflected in the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission (the "SEC") for the year ended December 31, 2 009. The current interim period reported herein should be read in conjunction with the financial statements and summary of significant accounting policies and notes included in the Company's Annual Report on Form 10-K for the year ended December 31, 2009.

Prior to March 2009, the Company was in the development stage as it did not have significant revenues. In the second quarter of 2010, the Company exited the development stage as the result of several acquisitions of oil and gas properties.

Principles of Consolidation

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.

Use of Estimates

The preparation of the financial statements in conformity 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. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and various other assumptions it believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable. Our most significant financial estimates are associated with our estimated proved oil and gas reserves and our share based compe nsation calculations.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

Oil and Gas Producing Activities

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, 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 the proved reserves related to a single full cost pool.

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 have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. 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 propert ies. The properties are reviewed quarterly for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

Estimated reserve quantities and future net cash flows have the most significant impact on the Company because these reserve estimates are used in providing a measure of the Company's overall value. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company's proved properties.

Estimating accumulations of oil and gas is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. 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 optimal method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Most of the Company's wells have been producing for a period of less than six years and for some, less than a year. Because of this short production history, other generally less accurate methods such as volumetric analysis and analogy to the production history of wells of ours and other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Company's estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Company's wells are produced over time and more data is available, the estimated proved reserves will be re-determined at least on a quarterly basis in accordance with applicable rules established by the SEC and may be adjusted based on that data.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations. Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves. For this purpose, we convert our petroleum products and reserves to a common unit of measure. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cub ic feet of natural gas to one barrel of crude oil. 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 the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus 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 subject to amortization. Should capitalized costs exceed this ceiling, an impairment is recognized.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

The present value of estimated future net revenues is computed by applying current prices 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.

There were no impairment charges recognized for proved or unproved properties for the six month period ending June 30, 2010.

Wells in Progress

Wells in progress at June 30, 2010 represent the costs associated with wells that have not reached total depth or been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test. The costs for these wells are then transferred to proved property when the wells are completed and the costs become subject to depletion and the ceiling test calculation in future period. The table below details the net changes in capitalized additions to wells in progress during the six month period ended June 30, 2010.

December 31, 2009	$	-
Additions to wells in progress pending the determination of proved reserves		274,064

June 30, 2010	$	274,064

Deferred Financing Costs

Deferred financing costs include fees incurred in connection with the Company's Loan Agreements, which are being amortized over the terms of the Agreements (see Note 6 – Loan Agreements and Note 7 - Acquisitions). The Company recorded amortization expense of $1,556,800 and $2,022,974 in the three and six month periods ended June 30, 2010, respectively.

Long Lived Assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.

In accordance with FASB new codification of “Accounting for Impairment or Disposal of Long-Lived Assets”, the Company carries long-lived assets at the lower of the carrying amount or fair value. Impairment is evaluated by estimating future undiscounted cash flows expected to result from the use of the asset and its eventual disposition. If the sum of the expected undiscounted future cash flow is less than the carrying amount of the assets, an impairment loss is recognized. Fair value, for purposes of calculating impairment, is measured based on estimated future cash flows, discounted at a market rate of interest.

There was no impairment losses recorded during the three or six month period ended June 30, 2010.

Revenue Recognition

The Company records the sale of oil and gas as they are produced and sold. The Company recognized $4,157,757 and $4,780,352 in proceeds from oil and gas sales in the three and six month periods ended June 30, 2010. The Company also recognized $1,688 and $2,813 in proceeds from net well management fees for the three and six month periods ended June 30, 2010.

Accounting Standards Updates

In January 2010, the FASB issued ASU 2010-03, “Extractive Activities – Oil and Gas,” to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC’s revised rules. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month average of the first day of the month prices and additional disclosure requirements. In contrast to the applicable SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. In April 2010, the FASB issued ASU 2010-14 which amends the guidance on oil and gas reporting in the ASC 932.10.S99-1 by adding the Codification SEC Regul ation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU 2010-14 are effective for annual reporting.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

In January 2010, the FASB issued ASU 2010-06, "Improving Disclosures About Fair Value Measurements," which provides amendments to fair value disclosures. ASU 2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. The revised guidance for transfers into and out of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010, with the amendments to Level 3 disclosures effective for beginning after January 1, 2011. ASU 2010-06 concerns disclosure only. Both the current and future adoption does not have a material impact on the Company's financial position or results of operations. Refer to “Note 3 – Financial and Derivative Instruments” for the Company’s disclosures on fair value.

NOTE 2

LOSS PER SHARE

Basic earnings (loss) per share is computed based on the weighted average number of common shares outstanding during the period presented. In addition to common shares outstanding, and in accordance with ASC 260 – “Earnings Per Share,” 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 had been issued. 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 three and six month periods ending June 30, 2010, 8,536,000 restricted common stock grants, 4,500,000 contingent common stock issuances and 23,056,933 warrants to purchase common stock 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.

NOTE 3

FINANCIAL AND DERIVATIVE INSTRUMENTS

The Company’s primary market exposure is to adverse fluctuations in the prices of oil. The Company uses derivative instruments, primarily swaps, to manage the price risk associated with equity oil production, and the resulting impact on cash flow, net income, and earnings per share. The Company does not use derivative instruments for speculative purposes.

The Company recognizes its derivative instruments as either assets or liabilities at fair value on its consolidated balance sheet and accounts for the derivative instruments as mark to market derivative instruments. On the cash flow statement, the cash flows from these instruments are classified as operating activities.

Derivative instruments expose the Company to counterparty credit risk. The Company enters into these contracts with third parties that it considers to be credit worthy. In addition, the Company’s master netting agreements reduce credit risk by permitting the Company to net settle for transactions with the same counterparty.

As with most derivative instruments, the Company’s derivative contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. The Company was in an overall asset position with its counterparty at June 30, 2010 and no party has required any form of security guarantee.

Mark to market hedging instruments

Unrealized gains and losses resulting from derivatives not designated as cash flow hedges are recorded at fair value on the balance sheet and changes in fair value are recognized in the price risk management activities line on the consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives not designated as cash flow hedges are recorded in the realized gain on hedges line on the consolidated statement of operations.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

During March 2010 and April 2010, the Company entered into three commodity derivative financial instruments intended to hedge our exposure to market fluctuations of oil prices.

The Company had the following commodity volumes under derivative swap contracts as of June 30, 2010:

	Barrels per		Average		Weighted
	quarter		Barrels per		Average Price
			Day		per Barrel

2010
Third quarter		31,000		344	$	85.65
Fourth quarter		23,700		263	$	85.37
2011
First quarter		18,900		210	$	85.25
Second quarter		3,300		110	$	88.00

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of June 30, 2010, presented gross of any master netting arrangements:

The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statement of operations for the six months ended June 30, 2010 was as follows:

Derivatives not		Amount of Gain Recognized in
Designated as	Location of Gain	Income on Derivative
Hedging Instruments	Recognized in Income	Six months ended June 30,
under ASC 815	on Derivative	2010
Commodity contracts	Realized gain on hedges	$	272,829
Commodity contracts	Price risk management activities	$	629,206

Refer to Note 4 – Fair Value of Financial Instruments for additional information regarding the valuation of the Company’s derivative instruments.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

NOTE 4

FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company records certain of its assets and liabilities on the balance sheet at fair value. Fair value is defined as 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). A three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

The following describes the valuation methodologies the Company uses for its fair value measurements.

Cash and cash equivalents

Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value because of the short maturity of these instruments. At June 30, 2010 the Company had $2,155,162 in cash equivalents.

Derivative instruments

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, and the credit rating of its’ counterparty. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.

In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

At June 30, 2010, the types of derivative instruments utilized by the Company included commodity swaps. The oil derivative markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Asset Retirement Obligations

The Company estimates asset retirement obligations in accordance with ASC 410 – “Asset Retirement and Environmental Obligations.” The income approach is utilized by the Company to recognize the estimated liability for future costs associated with the abandonment of its oil and gas properties at the point of inception. The Company’s asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs include (1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; (2) the economic lives of its properties, which is based on estimates from reserve engineers; (3) the inflation rate; and (4) the credit adjusted risk-free rate.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

A reconciliation of the Company’s asset retirement obligation liability is below:

December 31, 2009	$	-
Liabilities incurred		412,015
Retirements		-
Accretion expense (1)		9,621
Change in estimate		1,030

June 30, 2010	$	422,666

(1)	The accretion expense recorded during the period is recorded in the Depreciation, depletion and amortization line item on the consolidated statement of operations and totaled $7,974 and $9,621 in the three and six months ended June 30, 2010.

The following table provides a summary of the fair values of assets and liabilities measured at fair value:

	Level 1		Level 2		Level 3		Total

Assets
Commodity forward contracts	$	—	$	629,206	$	—	$	629,206

Total assets at fair value	$	—	$	629,206	$	—	$	629,206

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three months ended June 30, 2010.

Concentration of credit risk

Financial instruments which potentially subject the Company to credit risk consist of the Company’s accounts receivable and its derivative financial instruments. Substantially all of the Company’s receivables are within the oil and gas industry, including those from a third-party marketing company. Collectability is dependent upon the financial wherewithal of each individual company as well as the general economic conditions of the industry. The receivables are not collateralized.

At June 30, 2010 the Company’s derivative financial instruments were held with a single counterparty. The Company continually reviews the credit-worthiness of its counterparties. The Company’s derivative instruments are part of master netting agreements, which reduces credit risk by permitting the Company to net settle for transactions with the same counterparty.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

NOTE 5

EMPLOYEE AND DIRECTOR SHARE BASED COMPENSATION

Recovery has not adopted a Stock Incentive Plan for its management team. Each member of the board of directors and the management team was awarded restricted stock grants in their respective appointment or employment agreements.

Recovery accounts for stock based compensation arrangements in accordance with the provisions of ASC 718 Compensation – Stock Compensation. ASC 718 requires measurement and recording to the financial statements of the costs of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, recognized over the period during which an employee is required to provide services in exchange for such award.

On May 1, 2010 our Chief Executive Officer became our Chief Financial Officer resulting in a termination of the Chief Executive Officer’s employment agreement. In conjunction with accepting the Chief Financial Officer position, the officer’s previous stock grant of 464,200 shares was modified and combined with a new stock grant of 1,635,800 shares. Of the combined stock grant of 2,100,000 shares, 1,050,000 shares vest on January 1, 2011 with the remaining 1,050,000 shares vesting evenly over six quarters (175,000 on April 1, 2011, July 1, 2011, October 1, 2011, January 1, 2012, April 1, 2012, and July 1, 2012). The fair value of the 1,635,800 new shares and the modification of the original 464,200 share grant was $1,400,889 based on the price of $0.75, which equals the price we obtained for private placements prior to or concurrent with the restricted stock grant.

On May 1, 2010 our Chairman became our Chief Executive Officer and was award 4,500,000 shares of restricted common stock. These shares vest on January 1, 2011. The fair value of the 2010 share grant was $3,375,000 based on the price of $0.75 which equals the price we obtained for the restricted stock private placements prior to or concurrent with the stock grant.

On February 5, 2010 we granted 100,000 shares of restricted common stock to a board member. 62,500 shares of the stock vest on January 1, 2011, with the remaining 37,500 shares vesting evenly over three quarters (12,500 on April 1, July 1, and September 1, 2011). The fair value of these shares was $225,000 was based on the price of $2.25, which equals the price we obtained for private placements prior to or concurrent with the restricted stock grants. On May 1, 2010 we granted an additional 80,000 shares to the director that vest evenly over 3 years (26,667 shares vesting on January 1, 2011, January 1, 2012, and January 1, 2013). The fair value of these shares was $60,000 based on the price of $0.75, which equals the price we obtained for private placements prior to or concurrent with the restricte d stock grant.

On May 1, 2010 we granted 36,000 shares of restricted stock to an employee. The 36,000 shares vest in two even amounts of January 1, 2011 and January 1, 2012. The fair value of these shares was $27,000 based on the price of $0.75, which equals the price we obtained for private placements prior to the restricted stock grant.

On June 1, 2010 we granted 500,000 shares of restricted stock to a new board member. 250,000 shares vest on January 1, 2011 and 250,000 shares vest on January 1, 2012. The fair value of these shares was $565,000 based on the price of $1.13, which equals the price we obtained for private placements prior to the restricted stock grant.

On June 1, 2010 we granted 150,000 shares of restricted stock to a new board member. 50,000 shares vest on January 1, 2011, 50,000 shares vest on January 1, 2012, and 50,000 shares vest on January 1, 2013. The fair value of these shares was $169,500 based on the price of $1.13, which equals the price we obtained for private placements prior to the restricted stock grant.

On June 23, 2010 we granted 50,000 shares of restricted to a new employee. The shares vest over three years, with 10,000 shares vesting on January 1, 2011, 20,000 shares vesting on January 1, 2012, and 20,000 shares on January 1, 2012. The fair value of these shares was $56,500 based on the price of $1.13, which equals the price we obtained for private placements prior to the restricted stock grant.

We recognized stock compensation expense of $1,675,030 and $2,781,467 for the three and six month periods ended June 30, 2010.

A summary of stock grant activity for the period ended June 30, 2010 is presented below:

	Shares
Unregistered restricted stock grants outstanding at January 1, 2010		1,584,200
Granted		6,951,800
Vested		-
Outstanding at June 30, 2010		8,536,000

Total unrecognized compensation cost related to non-vested stock granted was $6,062,741 as of June 30, 2010. The unrecognized compensation cost at June 30, 2010 is expected to be recognized over a weighted-average remaining service period of 8 months.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

NOTE 6

LOAN AGREEMENTS

The Company entered into three separate loan agreements with Hexagon Investments, Inc. (“Hexagon”) during the six months ending June 30, 2010. All three loans bear annual interest of 15%, and mature on December 1, 2011. The loans contain cross collateralization and cross default provisions and are collateralized by mortgages against a portion of the Company’s developed and undeveloped leasehold acreage as well as all related equipment purchased in the first three acquisitions (Wilke Field, Albin Field, and State Line Field) detailed in Note 7 - Acquisitions. The loans require the payment of all proceeds after production costs and taxes from the acquired assets. The loan agreements contain customary terms such as representations and warranties and indemnification. In consider ation for the loans, Hexagon also received 5 million shares of common stock and a royalty interest in the Albin Field and State Line Field properties. In consideration for extending the maturity of the loans in connection with our June capital raise (see Note 8 – Stockholders’ Equity), Hexagon received 1 million warrants with an exercise price of $1.50 per share. The Company recorded $369,153 in deferred financing costs related to the warrants issued in conjunction with the extension of the loans. If the loan is not paid in full by January 1, 2011 we are required to issue 1 million additional warrants with an exercise price of $1.50 per share to Hexagon.

On May 26, 2010 the Company agreed to a $3 million seller note in conjunction with the acquisition of the 60,000 undeveloped acres and certain overriding interest described below. However, the Company paid the agreed note in full on May 27, 2010 and did not incur any interest expense with the transaction.

NOTE 7

ACQUISITIONS

In January, 2010 the Company acquired the Wilke Field from Edward Mike Davis, L.L.C. (“Davis”) for $4,500,000. In February, 2010 the Company entered into a credit agreement with Hexagon Investments, LLC to finance 100% of the purchase of the Wilke Field properties. Hexagon received 1,000,000 shares of the Company's common stock in connection with the financing. The Company recorded $2.25 million in deferred financing costs related to the shares issued in conjunction with the loan. The shares were valued at $2.25 per share which reflects the value of private placements completed near the time the loan agreement was executed. The Company will amortize the deferred financing costs through December 1, 2011, the loan’s maturity date.

In March, 2010 the Company acquired the Albin Field properties from Davis for $6,000,000 and 550,000 shares of our common stock valued at $412,500 or $0.75 per share. We simultaneously entered into a loan agreement with Hexagon to finance 100% of the cash portion of the purchase price. Hexagon received 750,000 shares of the Company’s common stock in connection with the financing. The Company recorded $562,500 in deferred financing costs related to the shares issued in conjunction with the loan and $175,322 in deferred financing costs associated with the ½ percent overriding royalty interest assigned in conjunction with the loan. The shares were valued at $0.75 per share which reflects the value of private placements completed near the time the loan agreement was executed. ; Hexagon also received a one-half percent overriding royalty in the leases and wells.

In April, 2010 the Company acquired the State Line Field properties from Davis for $15,000,000 and 2,500,000 shares of our common stock valued at $1,875,000 or $0.75 per share. We simultaneously entered into a loan agreement with Hexagon to finance 100% of the cash portion of the purchase price. Hexagon received 3,250,000 shares of the Company’s common stock and 2,000,000 warrants to acquire the Company’s common stock at $2.50 per share in connection with the financing. The Company recorded $2,596,185 in deferred financing costs related to the shares and warrants issued in conjunction with the loan and $184,589 in deferred financing costs associated with the one percent overriding royalty interest assigned in conjunction with the loan.

In May 2010, the Company acquired 60,000 acres of undeveloped leasehold acreage, in addition to certain overriding interests on existing Company owned acreage and wells in the DJ Basin from Davis for 2,000,000 shares of the Company’s stock valued at $1,500,000 or $0.75 per share and a cash payment of $20 million.

Davis and Hexagon currently own 6,500,000 shares and 6,500,000 shares, respectively, of our common stock, representing approximately 16.7% and 16.7%, respectively, of our outstanding shares at June 30, 2010.

In June 2010, the Company acquired interests in 3 wells located in the DJ Basin for $82,606 in cash and assumption of $17,394 in liabilities. The effective date of the acquisition was May 1, 2010.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

The following table shows the pro forma results of operations for the six months ended June 30, 2010 and 2009 as if the acquisitions had occurred on January 1, 2009. These unaudited pro forma results of operations are based on the historical financial statements and related notes of the Company, and the related historical audited financial statements of the Wilke, Albin and State Line acquisitions included in the related 8-K filings. These pro forma results of operations contain adjustments to depreciation, depletion and amortization for the effects of purchase price allocation, and to interest expense and amortization of deferred financing costs related to financing the acquisitions.

	Six Months Ended			Six Months Ended
	June 30, 2010			June 30, 2009
	Pro Forma			Pro Forma

Revenues	$	8,868,615		$	2,995,443

Operating income	$	(2,674,148	)	$	(22,267,133	)

Net income	$	(7,508,678	)	$	(24,179,633	)

Basic and diluted net loss per share	$	(0.40	)	$	(3.41	)

The pro forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that actually would have been achieved had the acquisition been consummated as of that time, nor is it intended to be a projection of future results.

The Company incurred $98,017 and $195,075, for the three and six month periods ended June 30, 2010, in acquisition related expenses which is included in General and Administrative expenses on the Statement of Operations.

NOTE 8

STOCKHOLDERS' EQUITY

During 2010, Recovery issued 27,974,015 shares. As of June 30, 2010 Recovery has 100,000,000 shares of common stock authorized of which 38,748,015 of shares were issued and outstanding (not including the 85,000 shares issued and outstanding under a lock-up agreement in conjunction with the reverse merger completed in September, 2009). The Company also has 10,000,000 shares of preferred stock authorized, none of which were issued or outstanding. Such shares, however, may be issued in such series and preferences as determined by the Board of Directors. 85,000 shares of common stock were issued and outstanding under a lock-up agreement that has terms which may result in the Company reacquiring the shares due to circumstances outside of the Company’s control and therefore the shares are pre ferential to common shares. The 85,000 shares covered by the lock-up agreement are treated as temporary equity and reported separately from other shareholders’ equity.

In May, 2010 we completed a private placement of 1,058,486 shares of our common stock to 32 accredited investors (as defined in Regulation D) for $0.75 per share resulting in gross proceeds to us of $793,732.

In June 2010, we completed a private placement of 15,901,200 units with a group of accredited investors for $1.50 per unit for gross proceeds of $23,851,800. Each unit consisted of one share of our common stock and a five year warrant to purchase a share of our common stock for $1.50. The stock portion of the unit was valued at $1.13 per share and the warrant portion of each unit was valued at $0.37 per share. The value of the warrant portion of each unit was determined utilizing a modified Black-Scholes model in accordance with ASC 718 – Stock Compensation.

In June 2010, we issued 800,000 shares of our common stock, a five year warrant to purchase 750,000 shares of our common stock at $1.50, and two three year warrants to purchase a combined 300,000 shares of our common stock at $1.50 to three separate vendors in exchange for future services. The value of the equity compensation has been capitalized as a prepaid asset and will be amortized over the life of the service agreements.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

A summary of warrant activity for the period ended June 30, 2010 is presented below:

			Weighted-Average
	Shares		Exercise Price
Outstanding at January 1, 2010		750,000	$	3.50
Granted		22,306,933	$	1.59
Exercised, forfeited, or expired		-		-
Outstanding at June 30, 2010		23,056,933	$	1.65
Exercisable at June 30, 2010		23,056,933	$	1.65

2,000,000 five year warrants with an exercise price of $2.50 per share were issued to Hexagon Investments, Inc. on April 14th in conjunction with the acquisition of the State Line field (See Note 7 - Acquisitions).

15,901,200 five year warrants with an exercise price of $1.50 per share were issued to as part of the unit issued as part of our capital raise which closed in June (See Note 8 - Shareholders’ Equity) (See Note 7 - Acquisitions).

2,355,731 five year warrants with an exercise price of $1.50 per share issued to our investment banker as part of our capital raise which closed in June (See Note 8 - Shareholders’ Equity). The five year warrants have a strike price of $1.50 per share (See Note 7 - Acquisitions).

1,000,000 five year warrants with an exercise price of $1.50 per share were issued to Hexagon Investments, Inc. on May 24th in exchange for the extension of the maturity date of our acquisition loans from December 1, 2010 to December 1, 2011 (See Note 7 - Acquisitions).

1,000,000 warrants with an exercise price of $1.50 per share were issued to a consultant on June 1, 2010. 250,000 of these warrants expire in three years and 750,000 of these warrants expire in five years.

50,000 three year warrants were issued with an exercise price of $1.50 to a consultant on June 14, 2010. The three year warrants have a strike price of $1.50 per share.

In connection with the above warrant issuances, the Company used the following assumptions: term 3 to 5 years, volatility 50% to 125%, price $ .75 to $2.50, interest rate 0.15% to 2.30%.

The aggregate intrinsic value of the in-the-money warrants as of June 30, 2010 was $20,306,933 based on the Company’s June 30, 2010 closing common stock price of $2.50; and the weighted average remaining contract life was 4.7 years.

NOTE 9

COMMITMENTS and CONTINGENCIES

Environmental and Governmental Regulation – At June 30, 2010 there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates, and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of June 30, 2010, the Company has not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.

Legal Proceedings – The Company may from time to time be involved in various other legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.

Potential Stock Grants and Royalty Interest under Employment/Appointment Agreements - The employment agreement for our Chief Financial Officer and the appointment agreement for our Chairman of the Board contain provisions which provide these individuals additional stock grants if the Company achieves certain market capitalization miles stones. As of May 1, 2010 our Chairman of the Board also became our Chief Executive Officer and our Chief Executive Officer became our Chief Financial Officer. Upon termination of the employment agreement for our former Chief Executive Officer, a provision which provides for a twelve month tail for additional stock grants to this individual if the Company achieves certain market capitalization mile stones.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

Our Chairman of the Board and Chief Executive Officer and our Chief Financial Officer are entitled to:

(1)	Upon the Company’s attainment of market capitalization of $100,000,000 or more, 100,000 shares of fully-vested Common Stock;

(2)	Upon the Company’s attainment of market capitalization of at least $200,000,000 or more, the shares specified under subsection (1) to the extent not yet issued, plus 200,000 shares of fully-vested Common Stock;

(3)	Upon the Company’s attainment of market capitalization of $300,000,000 or more, the shares specified under subsections (1) and (2) to the extent not yet issued, plus 300,000 shares of fully-vested Common Stock;

(4)	Upon the Company’s attainment of market capitalization of $400,000,000 or more, the shares specified under subsections (1), (2) and (3) to the extent not yet issued, plus 400,000 shares of fully-vested Common Stock; and

(5)	Upon the Company’s attainment of market capitalization of $500,000,000 or more, the shares specified under subsections (1), (2), (3) and (4) to the extent not yet issued, plus 500,000 shares of fully-vested Common Stock.

The Company has accounted for these agreements in accordance with ASC 718 Compensation—Stock Compensation. The Company recorded $9,801 and $19,603 of expense during the three and six month period ending June 30, 2010. This is based on independent valuation specialist’s reports and an estimated service period of four years. The expense is included in the General and administrative expense line item in the Statement of Operations.

In addition, under the employment agreement of our Chairman of the Board and Chief Executive Officer, and the employment agreement of our Chief Financial Officer, each individual is entitled to a 1% royalty for all acquisitions acquired during their employment/appointment with the Company. In connection with the acquisitions during the three and six month period ending June 30, 2010, $751,570 and $1,578,080 was expensed under these agreements.

NOTE 10

RELATED PARTY TRANSACTIONS

Previously, the Company sold to IEXCO, LLC a company controlled by our Chairman of the Board and Chief Executive Officer, its remaining 50% interest in the Church Field that were purchased under the purchase and sale agreement effective October 1, 2009 for $750,000 cash. Additionally, in an unrelated transaction, IEXCO, LLC purchased a 12.5% interest in the Wilke Field. The Company is the operator of both assets, and IEXCO, LLC is responsible for its portion of the operating costs for each field. Additionally, the Company charges IEXCO, LLC a prorated portion of a $500 per month per well operating fee.

Four of the five acquisitions (See Note 7 Acquisitions) the Company completed since the beginning of the year have been with the same seller, Davis. Davis owns approximately 16.7% of the issued and outstanding shares as of June 30, 2010. The cash portion of the purchase price for the first three acquisitions was financed with loans from Hexagon which owns approximately 16.7% of the stock issued and outstanding at June 30, 2010. During the quarter ending June 30, 2010, related to these loan agreements, the Company made principal payments of $2,068,755, interest payments of $823,603, and has accrued interest totaling $36,485 to Hexagon.

As of June 30, 2010 the Company had a net payable to related parties of approximately $45,864 related to joint interest billings receivable from, production payments payable to, and purchase price adjustments payable to related parties.

In May, 2010 the Company closed the previously announced sale of its two medium depth drilling rigs to Resource Energy, Inc., an entity controlled by Mathew Jennings, for $100,000 in cash and a $600,000 note. The note bears interest at an annual rate of prime plus 1%. Interest is payable quarterly, commencing June 30, 2010. Principal payments are due quarterly in eight equal payments commencing on June 30, 2011 and ending on June 30, 2013. The gain in this sale will be recognized as a capital contribution when the proceeds are fully received. We have recognized and accrued $3,896 in interest income on the loan for the three and six month periods ended June 30, 2010. As of the date of this filing, Resource Energy has not made the required interest payment and we have issued a demand letter to Resource. Management is evaluating the fair value of the collateral and recoverability of the loan principal at this time, but does not believe the loan is impaired and has not recognized any impairment of the loan. As of June 30, 2010, Mr. Jennings and entities controlled by Mr. Jennings owned approximately 2,958,334 or 7.6% of the issued and outstanding stock of the Company.

In June, 2010 we started drilling and completion work on a well located on a 640 acre oil and gas lease in Arapahoe County, Colorado known as Comanche Creek. We acquired 50% interests in this prospect and the Omega prospect in January 2010 from Davis as part of the Wilke acquisition. We acquired an additional 12.5% working interest in the Comanche Creek prospect in June 2010 from Davis in exchange for a 1% overriding royalty interest on our existing 50% working interest, resulting in us owning 62.5% working interest. The remaining 37.5% working interest is split between Davis and Timothy N. Poster, a member of our board of directors, with Davis holding 12.5% and Mr. Poster holding 25% of the working interest. Both of these interests are on a “head’s up” basis with Dav is and Mr. Poster paying their proportionate share of the estimated costs to us. We received deposits from both Davis and Mr. Poster for their portion of the dry hole costs associated with the well. The operations of the well is covered by a joint operating agreement and requires both Davis and Mr. Poster to pay their proportionate share of operating costs as well as an overhead/operating fee to us.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2010

(UNAUDITED)

NOTE 11

SUBSEQUENT EVENTS

In July, 2010 the Company filed a registration statement for resale of 45,696,666 shares which included the shares and warrants issued to our lender under the three loan agreements and the loan modification agreement as more fully described above, shares issued under the purchase agreements for the various assets we acquired as more fully described above, the shares and warrants issued in our June capital raise as more fully described above, and shares and warrants issued to certain consultants. The registration statement has not become effective as of the date of this filing.

In August, 2010 the Company entered into a commodity derivative financial instrument intended to hedge our exposure to market fluctuations of oil prices. The following table details the derivative instrument.

			Average		Weighted
	Barrels per		Barrels per		Average Price
	quarter		Day		per Barrel

2011
Second quarter		6,600		110	$	84.95
Third quarter		9,900		110	$	84.95
Fourth quarter		9,900		110	$	84.95

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expecta tions and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2009, including the following:

	•		Our ability to maintain adequate liquidity in connection with low oil and gas prices;

	•		The changing political environment in which we operate;

	•		Our ability to obtain, or a decline in, oil or gas production;

	•		A decline in oil or gas prices;

	•		Our ability to increase our natural gas and oil reserves;

	•		Incorrect estimates of required capital expenditures;

	•		The amount and timing of capital deployment in new investment opportunities;

	•		The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment;

	•		Our future capital requirements and availability of capital resources to fund capital expenditures;

	•		Our ability to successfully integrate and profitably operate any future acquisitions;

	•		Increases in the cost of drilling, completion and gas collection or other costs of production and operations;

	•		The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;

	•		Numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs;

	•		Our ability to remedy any deficiencies that may be identified in the review of our internal controls;

	•		The credit worthiness of third-parties which we enter into business agreements with;

	•		General economic conditions, tax rates or policies, interest rates and inflation rates;

	•		Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;

	•		Weather, climate change and other natural phenomena;

	•		Industry and market changes, including the impact of consolidations and changes in competition;

	•		The effect of accounting policies issued periodically by accounting standard-setting bodies;

	•		The actions of third party co-owners of interests in properties in which we also own an interest;

	•		The cost and effects on our business, including insurance, resulting from terrorist actions or natural disasters and responses to such actions or events;

	•		The volatility of our stock price; and

	•		The outcome of any current or future litigation or similar disputes and the impact on any such outcome or related settlements.

We also may make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and the possibility of their occurring is not taken into consideration in the forward-looking statements.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward -looking statements, whether as a result of new information, future events, or otherwise.

Overview of Our Business

Industry terms used in this report are defined in the Glossary of Oil and Natural Gas Term located at the end of Item 1 of Part I of our 2009 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.

Overview

Recovery Energy Inc. is an independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the United States. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team along with that of our operating partners.

We target low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Colorado, Nebraska, Wyoming, Kansas, Oklahoma, and Texas. At June 30, 2010, we owned interests in approximately 82,000 gross (81,000 net) leasehold acres, of which approximately 79,000 gross (78,000 net) acres are classified as undeveloped acreage.

For the three and six month period ending June 30, 2010, our total production was 59,289 and 68,187 net barrels of oil, respectively.

Our executive offices are located at 1515 Wynkoop Street, Suite 200, Denver, Colorado 80202, and our telephone number is (888) 887-4449. Our web site is www.recoveryenergyco.com. Additional information which may be obtained through our web site does not constitute part of this quarterly report on Form 10-Q. A copy of this quarterly report on Form 10-Q is located at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information on the operation of the SEC’s Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings at www.sec.go v.

Recent Developments and Related Transactions

In April, 2010 we acquired six wells in Laramie County, Wyoming and interests in 1240 acres from Edward Mike Davis, L.L.C. The purchase price was $15,000,000 and 2,500,000 shares of our common stock. In connection with the acquisition we entered into a credit agreement with Hexagon Investments, LLC to finance the $15,000,000 cash portion of the purchase price. The loan bears annual interest of 15%, will mature on December 1, 2011 and is secured by a mortgage on the acquired property. Hexagon Investments received 3,250,000 shares of our common stock and a warrant to purchase 2,000,000 shares of our common stock exercisable at $2.50 per share in connection with the financing. The credit agreement contained customary terms such as representations and warranties and indemnificati on.

In April, 2010 we issued 333,333 shares of our common stock to one accredited investor (as defined in Regulation D) for $0.75 per share resulting in proceeds of $250,000 to us.

In May, 2010 we sold our two medium depth drilling rigs to Resource Energy, Inc., an entity controlled by Mathew Jennings, for $100,000 in cash and a $600,000 note. The note bears interest at an annual rate of prime plus 1%. Interest is payable quarterly, commencing June 30, 2010. Principal payments are due quarterly in eight equal payments commencing on June 30, 2011 and ending on June 30, 2013. The gain in this sale will be recognized as a capital contribution when the proceeds are fully received. The first payment due on June 30, 2010 has not been made. As of August 13, 2010, Mr. Jennings and entities controlled by Mr. Jennings owned approximately 2,958,334 or 7.6% of our outstanding common stock.

In May, 2010 we purchased from Edward Mike Davis, L.L.C. and an affiliate oil and gas interests in approximately 60,000 acres located in Banner and Kimball Counties, Nebraska and Laramie and Goshen Counties, Wyoming. The purchase price was $20,000,000 and 2,000,000 shares of our common stock. The cash portion of the purchase price was paid from the proceeds of a private placement of 15,901,200 shares of our common stock and 15,901,200 five year warrants to purchase our common stock for $1.50 with a group of accredited investors for $1.50 per unit for gross proceeds of $23,851,800 which closed in June 2010. In connection with the acquisition and financing we issued Hexagon a five year warrant to purchase 1,000,000 shares of our common stock at $1.50 per share as compensation for amendments to our credit agreements and ag reed that if the loans are not repaid in full on or before January 1, 2011 we will issue Hexagon a second five year warrant to purchase 1,000,000 shares of our common stock at $1.50 per share.

In May, 2010 we granted (i) 4,500,000 shares of our common stock to Roger A. Parker pursuant to his employment agreement as our chief executive officer, (ii) 1,635,800 shares of our common stock to Jeffrey A. Beunier pursuant to his employment agreement as our chief financial officer and (iii) 80,000 shares of our common stock to James Miller pursuant to his amended and restated director appointment agreement.

In June, 2010 we started drilling and completion work on a well located on a 640 acre oil and gas lease in Arapahoe County, Colorado known as Comanche Creek. We acquired 50% interests in this prospect and the Omega prospect in January 2010 from Edward Mike Davis, L.L.C. as part of the Wilke acquisition. We acquired an additional 12.5% working interest in the Comanche Creek prospect in June 2010 from Davis in exchange for a 1% overriding royalty interest on our existing 50% working interest, resulting in us owning 62.5% working interest. The remaining 37.5% working interest is split between Davis and Timothy N. Poster, a member of our board of directors, with Davis holding 12.5% and Mr. Poster holding 25% of the working interest. Both of these interests are on a “head’s up&# 8221; basis with Davis and Mr. Poster paying their proportionate share of the estimated costs to us. We received deposits from both Davis and Mr. Poster for their portion of the dry hole costs associated with the well. The operations of the well is covered by a joint operating agreement and requires both Davis and Mr. Poster to pay their proportionate share of operating costs as well as an overhead/operating fee to us.

In June, 2010 we granted 500,000 shares of our common stock to Timothy N. Poster and 150,000 shares of our common stock to Conway J. Schatz pursuant to their respective director appointment agreements.

In June, 2010 we granted 50,000 shares of restricted common stock to an employee.

In June, 2010 we issued 750,000 shares of our common stock, a five-year warrant to purchase 750,000 shares of our common stock for $1.50 per share and a three-year warrant to purchase 250,000 shares of our common stock for $1.50 per share to Market Development Consulting Group, Inc. in exchange for management consulting services.

In June, 2010 we issued a three-year warrant to purchase 50,000 shares of our common stock for $1.50 per share to Globe Media for public relations services.

In June, 2010 we purchased interests in three wells from an unrelated third party. The wells are located in Adams, Weld, and Elbert Counties, Colorado.

Four of the five acquisitions we have completed since the beginning of the year have been with the same seller, Edward Mike Davis, L.L.C. Davis owns approximately 16.7% of our outstanding common stock as of August 13, 2010. The cash portion of the purchase price for the first three acquisitions was financed with loans from Hexagon, together with its affiliates, which owns approximately 22.7% of our outstanding common stock at August 13, 2010. As of June 30, 2010 we have made principal payments of $2,248,382, interest payments of $950,387, and have accrued interest totaling $36,485 to Hexagon. As required by our employment agreements with Mr. Parker and Mr. Beunier, we have assigned a 1% overriding royalty interest in the acquisitions to each of them. We have accrued a total of approximately $110,000 for overriding royalties payable to Mr. Parker and Mr. Beunier at June 30, 2010.

Our Oil and Gas Operations

We intend to invest primarily in domestic oil and natural gas interests, including producing properties, prospects, leases, wells, mineral rights, working interests, royalty interests, overriding royalty interests, net profits interests, production payments, farm-ins, drill to earn arrangements, partnerships, easements, rights of way, licenses and permits, in Colorado, Nebraska, Wyoming, Kansas, Oklahoma, and Texas. During the period ending June 30, 2010 we sold our two drilling rigs (See Note 10 – Related Party Transactions).

Principal Oil and Gas Interests

As of June 30, 2010 we own nineteen producing wells in the Wyoming, Nebraska and Colorado portion of the DJ Basin, as well as interests in 78,000 net acres of undeveloped leasehold (See Note 7 – Acquisitions and “Recent Developments” above).

Our Strategy

It is our belief that the exploration and production industry’s most significant value creation occurs through the drilling of successful development wells and the enhancement of oil recovery in mature fields. Our goal is to create significant value while maintaining a low cost structure. To this end, our business strategy includes the following elements:

Participation in development prospects in known producing basins. We pursue prospects in known producing onshore basins where we can capitalize on our development and production expertise. We intend to operate the majority of our properties and evaluate each prospect based on its geological and geophysical merits.

Negotiated acquisitions of properties. We acquire producing properties based on our view of the pricing cycles of oil and natural gas and available exploration and development opportunities of proved, probable and possible reserves.

Leasing of prospective acreage. In the course of our business, we identify drilling opportunities on properties that have not yet been leased. At times, we take the initiative to lease prospective acreage and sell all or any portion of the leased acreage to other companies that want to participate in the drilling and development of the prospect acreage.

Controlling Costs. We maximize our returns on capital by minimizing our expenditures on general and administrative expenses. We also minimize initial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that have already invested capital in such. We also outsource some of our geological, geophysical, reservoir engineering and land functions in order to help reduce capital requirements.

We intend to use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. From time to time, we will enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts; however, it is our preference to utilize hedging strategies that provide downside commodity price protection without unduly limiting our revenue potential in an environment of rising commodity prices. We intend to use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In the future we may also be required by our lenders to hedge a portion of production as part of any financing.

It is our long-term goal to achieve a well-diversified and balanced portfolio of oil and natural gas producing properties located in North America.

Marketing and Pricing

We will derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We will sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.

Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of natural gas and crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:

●		changes in global supply and demand for oil and natural gas;
●		the actions of the Organization of Petroleum Exporting Countries, or OPEC;
●		the price and quantity of imports of foreign oil and natural gas;
●		acts of war or terrorism;
●		political conditions and events, including embargoes, affecting oil-producing activity;
●		the level of global oil and natural gas exploration and production activity;
●		the level of global oil and natural gas inventories;
●		weather conditions;
●		technological advances affecting energy consumption; and
●		the price and availability of alternative fuels.

From time to time, we will enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:

●		our production and/or sales of natural gas are less than expected;
●		payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
●		the counter party to the hedging contract defaults on its contract obligations.

In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.

Government Regulations

General. Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and local laws and regulations. The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impact our operations and can affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different than our competitors. Matters regulated include permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements for the operation of wells, and taxa tion of production. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gas and other substances and materials produced or used in connection with oil and natural gas operations. While we believe we will be able to substantially comply with all applicable laws and regulations, the requirements of such laws and regulations are frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect on our actual operations.

Federal Income Tax. Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, our domestic “intangible drilling and development costs” and to claim depletion on a portion of our domestic oil and natural gas properties based on 15% of our oil and natural gas gross income from such properties (up to an aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas).

Environmental Matters. The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoining property, giving rise to additional liabilities.

A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing and may, in addition to other laws, impose liability in the event of discharges, whether or not accidental, failure to notify the proper authorities of a discharge, and other noncompliance with those laws. Compliance with such laws and regulations may increase the cost of oil and gas exploration, development and production, although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operat ions.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that dispose or arrange for disposal of the hazardous substances found at the time. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and severable liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA because our jointly owned drilling and production activities generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA.

The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because o ur operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by OPA. In addition, to the extent we acquire offshore leases and those operations affect state waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws. OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. We cannot predict whether the financial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or impose substantial additional annual costs to us or otherwise materially adversely affect us. The impact, however, should not be any more adverse to us than it will be to other similarly situated owners or operators.

The Federal Water Pollution Control Act Amendments of 1972 and 1977 (“Clean Water Act”) imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm wa ter discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of crude oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from crude oil and natural gas production. The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. Failure to abide by our permits could subject us to civil and/or criminal enforcement. We believ e that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

The Clean Air Act of 1963 and subsequent extensions and amendments, known collectively as the “Clean Air Act”, and state air pollution laws adopted to fulfill its mandate provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.

There are numerous state laws and regulations in the states in which we operate which relate to the environmental aspects of our business. These state laws and regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality.

We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you that environmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks generally are not fully insurable.

In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

Federal Leases. For those operations on federal oil and gas leases, such operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies. In addition, on federal lands in the United States, the Minerals Management Service ("MMS") prescribes or severely limits the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, MMS prohibits deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the MMS has been engaged in a proces s of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculating royalties owed to the government. The natural gas and crude oil industry as a whole has resisted the proposed rules under an assumption that royalty burdens will substantially increase. We cannot predict what, if any, effect any new rule will have on our operations.

Other Laws and Regulations. Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which we have production, could be to limit the number of wells that could be drilled on our properties and to limit the allowable production from the successful wells completed on our properties, thereby limiting our revenues.

Competition

We compete with numerous other companies in virtually all facets of our business. Our competitors in the exploration, development, acquisition and production business include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater financial resources and in-house technical expertise than we do.

Employees

At June 30, 2010, we had four employees. Effective May 1, 2010, Roger A Parker became our chief executive officer and Jeffrey Beunier, formerly our chief executive officer, became our president and chief financial officer. Additionally on June 23, 2010, Christopher Barber joined Recovery Energy as controller. For the foreseeable future, we intend to only add additional personnel as our operational requirements grow, in the interim, we plan to continue to use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We believe that by limiting our management and employee costs, we are able to better control total costs and retain flexibility in terms of project management.

Recent Performance

Following are summary comments of our performance in several key areas during the quarter ended June 30, 2010

	●		Average Daily Production
			DJ Basin. During the quarter ended June 30, 2010, average daily net production was 659 BOPD net. As discussed in the Recent Developments and Related Transactions section above, the Company successfully acquired a number of producing properties during the quarters ending March 31, 2010 and June 30, 2010. The Palm and State Line acquisitions were effective as of April 1, 2010 and therefore our production increased due to the addition of these properties.

	●		Oil and Gas Sales
			During the quarter ended June 30, 2010, net oil sales were $4,157,757. Our average oil price received was $70.13 per barrel.

	●		Cash Flow from Operations
			During the quarter ended June 30, 2010, we generated $1,913,423 in cash from operations.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

As of June 30, 2010 we had $2,155,162 in cash.

We believe that we have sufficient liquidity and capital resources to continue our current operations. We also may consider additional offerings of securities to develop our 78,000 gross undeveloped acres. Although we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or what the terms of any additional financing would be.

Information about our financial position is presented in the following table:

	June 30, 2010 (unaudited)		December 31, 2009 (unaudited)
Financial Position Summary
Cash and cash equivalents	$	2,155,162	$	108,340
Working capital	$	2,428,550	$	(44,229)
Balance outstanding on term notes	$	23,252,495	$	-
Common Stock subject to redemption rights and Other Shareholders’ Equity	$	31,245,477	$	566,272
Ratios
Debt to total capital ratio		43%		0%
Total debt to equity ratio		74%		0%

During the quarter ended June 30, 2010, our working capital increased to $2,428,550 compared to negative working capital of ($44,229) at December 31, 2009. The higher working capital and cash position is primarily the result of capital raised during the six months ending June 30, 2010 (See Note 8 – Stockholders’ Equity), the reclassification of the majority of our debt as a long term liability due to the maturity date extension (See Note 6 – Loan Agreements), as well as the addition of several producing oil and gas properties during the six months ending June 30, 2010 (See Note 7 – Acquistions). Our accounts payable and accrued liabilities balance increased $1,054,561 and our accounts receivable balance increased by $1,467,821 from December 31, 2009, primarily due to the acquisition of properties and related production activities.

	Quarter ended June 30,
	2010
	(unaudited)
Cash provided by (used in):
Operating activities		$	1,913,423
Investing activities			(35,473,281	)
Financing activities			35,542,973

Net change in cash		$	1,983,115

During the three and six month ended June 30, 2010, net cash provided by operating activities was $1,913,423 and $1,718,092, respectively. The primary changes in operating cash during the six months ended June 30, 2010 were $(6,017,492) of net loss, adjusted for non-cash charges of $2,441,413 of depreciation, depletion and amortization expenses (“DD&A”) and accretion expense, $2,781,467 stock-based compensation, $2,022,974 of amortization of deferred financing costs and $1,578,080 of non-cash compensation expense, offset by the non-cash gain on derivative contracts of $(629,206). In addition, we had an increase in accounts receivable of $1,467,821 and a decrease in accrued expenses of $658,933.

During the three and six month ended June 30, 2010, net cash used by investing activities was $(35,473,281) and $(45,835,552). The primary changes in investing cash during the six months ended June 30, 2010 was $45,455,520 related to our acquisitions which consisted primarily of the Wilke, Albin and State Line fields, and unproved acreage. In addition, we used $402,944 for drilling capital expenditures. See Note 7 – Acquisitions for further details on the acquisitions.

During the three and six month ended June 30, 2010, net cash provided by financing activities was $35,542,973 and $46,164,222. The primary changes in financing cash during the six months ended June 30, 2010 were net proceeds from the sale of common stock for $22,911,727 and the issuance of debt in connection with the acquisitions for $28,500,000, offset by debt repayments of ($5,247,505).

Off-Balance Sheet Arrangements

We do not participate in transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities are often referred to as structured finance or special purpose entities (“SPEs”) or variable interest entities (“VIEs”). SPEs and VIEs can be established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any of the periods presented in this Form 10-Q.

From time to time, we enter into contracts that might be construed as off-balance sheet obligations but are normal in the day-to-day course of business in the oil and gas industry. Those contracts are the derivative instruments discussed in “Contracted Volumes” above. We do not believe we will be affected by these contracts materially differently than other similar companies in the energy industry.

Loan Agreements

In conjunction with the acquisitions, as described in Note 7 – Acquisitions and Note 6 - Loan Agreements, the Company entered into one additional secured note and loan agreement during the quarter ending June 30, 2010. Effective January 29, 2010, we entered into a $4.5 million loan agreement, with an original maturity date of December 1, 2010. Effective March 25, 2010, we entered into a $6.0 million loan agreement, with an original maturity date of December 1, 2010. Effective April 14, 2010, we entered into a $15.0 million loan agreement, with an original maturity date of December 1, 2010. All three loan agreements have similar terms and require us to repay the notes out of cash flows from production. We entered into a loan modification agreement on May 28, 2010 which extended the maturity date of our loans to December 1, 2011. The loan modification agreements require us to issue 1 million five year warrants to purchase common stock at $1.50 per share to Hexagon if we do not repay the loan in full by January 1, 2011. Our loans bear annual interest rates of 15% and are secured by a mortgage on the property acquired with the loan proceeds. The loan agreements contained customary terms such as representations and warranties and indemnification.

As of June 30, 2010, the outstanding balance on our loan agreements was $23.25 million, of which approximately $892,500 is classified as a current liability and approximately $22.4 million is classified as a long term liability. For the three and six month period ended June 30, 2010, we incurred cash interest expense of $860,088 and $987,750, on the loan agreements of which $36,485 was accrued as of June 30, 2010. We made $5,068,755 and $5,247,505 in principal payments for the three and six month periods ending June 20, 2010.

Deferred financing costs related to stock, warrants and overriding royalty interests placed in conjunction with our loan agreements total $6,137,750. During the three and six month periods ending June 30, 2010, we have amortized $1,556,780 and $2,022,974. Amortization expense for deferred financing costs is included in the Interest expense line item on the Statement of Operations. The remaining $4,114,776 in Deferred Financing Costs is classified as long term asset on our Balance Sheet. The deferred financing costs will amortize on a straight line basis over the remaining life of our loan agreements as detailed below.

Quarterly Amortization of Deferred Financing Costs

9/30/2010	$	729,402
12/31/2010	$	729,402
3/31/2011	$	713,545
6/30/2011	$	721,473
9/30/2011	$	729,401
12/1/2011	$	491,553

We did not capitalize any interest costs for the three or six month periods ended June 30, 2010.

We are subject to certain financial and non-financial covenants with respect to the above loan agreement. As of June 30, 2010, we were in compliance with all covenants under the facility. If any of the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

Capital Requirements

Our estimated capital budget for 2010 is approximately $700,000 for drilling two wells within the Omega and Comanche project areas. We spudded the first of these two wells in June 2010 as more fully describe in the “Recent Developments and Related Transactions” section above. The 2010 budget does not include the impact of any potential future exploration projects, or ongoing exploration or development activities, or potential acquisitions. We expect to fund our 2010 capital expenditures with cash provided by operating activities and we intend to raise additional funds through private placements or registered offerings of equity or debt.

RESULTS OF OPERATIONS

Quarter ended June 30, 2010

Revenues

For the three and six month period ending June 30, 2010, we had $4,157,757 and $4,780,352 in oil sale revenues.

	Quarter Ended June 30,
	2010
	Volume		Average Price
Product:
Oil (Bbls)		59,289		$	70.13

During the quarter, as discussed in Note 7 - Acquisitions, the Company acquired additional producing assets. The Wilke acquisition was effective January 1, 2010, the Albin and State Line acquisitions were effective April 1, 2010, and therefore contribute to a material increase in production and revenue during the quarter ending June 30, 2010. Average daily net production was 659 BOPD.

Miscellaneous Income and Operating fees

The Company earned net operating fees of $1,688 and $2,813 during the three and six month periods ending June 30, 2010. The Company realized a mark-to-market gain of $8,858 and $24,067 during the three and six month periods ended June 30, 2010 on a put agreement associated with 85,000 shares of stock placed in conjunction with our reverse merger in September 2009.

Price Risk Management activities

We recorded a net gain on our derivative contracts that do not qualify for cash flow hedge accounting of $762,575 for the quarter ended June 30, 2010. This amount represents an unrealized non-cash gain which represents a change in the fair value of our mark-to-market derivative instruments at June 30, 2010 as detailed in Note 3 Financial and Derivative Instruments and Note 4 – Fair Value of Financial Instruments. We realized a gain on our derivative contracts that do not qualify for cash flow hedge accounting of $272,829 for the quarter ended June 30, 2010. This amount represents a realized cash gain from the settlement of our forward sale contracts for the quarter ending June 30, 2010 as detailed in Note 3 Financial and Derivative Instruments and Note 4 – Fair Value of Financial Instru ments.

Oil and gas production expenses, depreciation, depletion and amortization

	Quarter Ended June 30,
	2010
	(unaudited, in dollars per bbl)
Average price	$	70.13

Production costs		3.78
Production taxes		8.19
Depletion and amortization		37.27

Total operating costs		49.24


Gross margin	$	20.89

Gross margin percentage		29.79	%

General and administrative expenses

General and administrative expenses were $3,068,698 for the quarter ended June 30, 2010. Our general and administrative expenses for the quarter ended include $260,207 in professional fees, and $2,426,600 in non-cash compensation expense. The non-cash compensation expense was comprised of $1,675,030 in stock compensation expense and $751,570 in expense associated with the assignment of overriding royalty interest.

CONTRACTED VOLUMES

Changes in the market price of oil can significantly affect our profitability and cash flow. We have entered into various derivative instruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consist of swaps. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.

Our outstanding derivative instruments as of June 30, 2010 are summarized below:

	Barrels per		Average		Price per
	quarter		Barrels per		barrel
			Day

2010
Third quarter		31,000		344	$	85.65
Fourth quarter		23,700		263	$	85.37
2011
First quarter		18,900		210	$	85.25
Second quarter		3,300		110	$	88.00

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not required for smaller reporting companies.

Item 4T. Controls and Procedures

(a) Management of Recovery Energy is responsible for establishing and maintaining adequate internal control over financial reporting under the supervision of the Chief Executive Officer and the President and Chief Financial Officer. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

As required by Rule 13a-15 under the Securities Exchange Act of 1934 (the "1934 Act"), as of June 30, 2010, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. This evaluation was carried out by our Chief Financial Officer and our Chief Executive Officer, who concluded, that because of the material weakness in our internal control over financial reporting (see Item 9A (T) CONTROLS AND PROCEDURES in the Company’s Form 10-K filed for the year ended December 31, 2009), our disclosure controls and procedures were not effective as of June 30, 2010. Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchang e 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 include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

(b) For the quarter ended June 30, 2010, there were changes in our internal control over financial reporting during our most recent fiscal quarter that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting due to the addition of a Controller to oversee accounting.

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

This quarterly report does not include an attestation of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this quarterly report.

INHERENT LIMITATIONS OF INTERNAL CONTROLS

Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the U.S. GAAP. Our internal control over financial reporting includes those policies and procedures that:

–	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

–	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the U.S. GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

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

Management does not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of internal controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. Also, any evaluation of the effectiveness of controls in future periods are subject to the risk that those internal controls may become inadequate because of changes in business conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Currently we are not aware of any litigation pending or threatened by or against the Company.

Item 1A. Risk Factors.

There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2009 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.

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

During early May, 2010 we placed 725,153 shares with 32 qualified investors at $0.75 per share.

All other unregistered issuances of equity securities during the period covered by this report have been previously included in Current Reports on form 8-K.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

None

Item 6. Exhibits and Reports of Form 8-K.

Exhibits

31.1 Certifications pursuant to Section 302 of Sarbanes Oxley Act of 2002

31.2 Certifications pursuant to Section 302 of Sarbanes Oxley Act of 2002

32.1 Certifications pursuant to Section 906 of Sarbanes Oxley Act of 2002

32.2 Certifications pursuant to Section 906 of Sarbanes Oxley Act of 2002

SIGNATURES

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

	Recovery Energy, Inc.

Date: August 16, 2010	By:	/s/ Roger A Parker
		Roger A Parker
		Chief Executive Officer

Date: August 16, 2010	By:	/s/ Jeffrey A Beunier
		Jeffrey A Beunier
		Chief Financial Officer

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Derivatives not designated as hedging

instruments under ASC 815

Balance Sheet Location

Fair Value

Commodity derivatives

Assets from price risk management — current