LILIS ENERGY, INC. - FORM 10-Q

Attached files

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EX-32.1 - CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT - LILIS ENERGY, INC.	f10q0911ex32i_recovery.htm
EX-31.1 - CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT - LILIS ENERGY, INC.	f10q0911ex31i_recovery.htm
EX-32.2 - CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT - LILIS ENERGY, INC.	f10q0911ex32ii_recovery.htm
EXCEL - IDEA: XBRL DOCUMENT - LILIS ENERGY, INC.	Financial_Report.xls
EX-31.2 - CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT - LILIS ENERGY, INC.	f10q0911ex31ii_recovery.htm

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 September 30, 2011

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)

_______________

(303) 951-7920

(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 November 14, 2011: 15,825,854 shares of Common Stock.

Recovery Energy, Inc.

INDEX

PART I– FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010	1
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010	3
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010	4
	Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4T.	Control and Procedures	34

PART II– OTHER INFORMATION

Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Submission of Matters to a Vote of Security Holders	35
Item 5.	Other Information	35
Item 6.	Exhibits and Reports on Form 8-K	35

SIGNATURES

Part 1. Financial Information

Item 1. Financial Statements

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

				December 31,
	September 30, 2011			2010 (Restated)
Assets
Current Assets
Cash	$	646,070		$	5,528,744
Restricted cash		1,006,540			1,150,541
Accounts receivable		1,748,631			857,554
Prepaid assets		60,177			27,772
Total current assets		3,461,418			7,564,611

Oil and gas properties (full cost method), at cost:
Undeveloped properties		49,329,396			33,605,594
Developed properties		30,053,964			26,307,975
Wells in progress		4,411,110			1,219,397
Total oil and gas properties		83,794,470			61,132,966

Less accumulated depreciation, depletion and amortization		(8,143,835	)		(5,008,606	)
Net oil and gas properties		75,650,635			56,124,360

Other assets
Office equipment, net		70,256			56,236
Prepaid advisory fees		675,482			979,449
Deferred financing costs, net		2,971,604			3,211,566
Restricted cash and deposits		185,867			185,707
Total other assets		3,903,209			4,432,958

TOTAL ASSETS	$	83,015,262		$	68,121,929

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

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

				December 31,
	September 30, 2011			2010 (Restated)
Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable	$	3,406,078		$	968,295
Commodity price derivative liability		-			398,840
Related party payable		17,023			11,638
Accrued expenses		1,629,957			1,540,592
Short term note payable		357,014			208,881
Total current liabilities		5,410,072			3,128,246

Asset retirement obligation		601,195			507,280
Term note payable		19,824,863			20,229,801
Convertible notes payable, net of discount		4,502,251			-
Convertible notes conversion derivative liability		3,534,093			-
Total long term liabilities		28,462,402			20,737,081

Total liabilities		33,872,474			23,865,327

Commitments and contingencies – Note 7

Common Stock Subject to Redemption Rights, $0.0001 par value; 0 and 10,625 shares issued and outstanding as of September 30, 2011 and December 31, 2010, respectively		-			86,258


Shareholders’ Equity
Common stock, $0.0001 par value: 100,000,000 shares authorized;
15,825,854 and 14,453,593 shares issued and outstanding (excluding 0 and 10,625 shares subject to redemption) as of September 30, 2011 and December 31, 2010, respectively		1,583			5,781
Additional paid in capital		110,325,305			93,814,977
Accumulated deficit		(61,184,100	)		(49,650,414	)
Total shareholders' equity		49,142,788			44,170,344

TOTAL LIABILITIES, COMMON STOCK SUBJECT TO REDEMPTION RIGHTS AND SHAREHOLDERS’ EQUITY	$	83,015,262		$	68,121,929

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

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three months ended September 30,						Nine months ended September 30,
	2011			2010 (Restated)			2011			2010 (Restated)
Revenue
Oil sales	$	1,650,702		$	2,652,840		$	5,534,325		$	7,433,192
Gas sales		161,029			-			446,386			-
Operating fees		85,372			1,697			110,282			4,500
Realized gain on commodity price derivatives		733,830			292,805			402,256			565,634
Unrealized gains (loss) on commodity price derivatives		-			(394,552	)		222,788			234,654

Total Revenues		2,630,933			2,552,790			6,716,037			8,237,980

Costs and expenses
Production costs		344,927			290,554			1,114,220			636,531
Production taxes		191,364			299,730			630,718			820,642
General and administrative		1,981,026			6,408,939			8,837,802			11,820,958
Depreciation, depletion and amortization		1,052,946			1,454,197			3,194,301			3,895,610

Total costs and expenses		3,570,263			8,453,420			13,777,041			17,173,741

Loss from operations		(939,330	)		(5,900,630	)		(7,061,004	)		(8,935,761	)

Other income		62,000			1,210			63,115			25,277
Convertible notes conversion derivative gain (loss)		(13,338	)		-			1,587,699			-
Interest expense		(2,136,950	)		(1,591,826	)		(6,123,496	)		(4,598,255	)

Net Loss	$	(3,027,618	)	$	(7,491,246	)	$	(11,533,686	)	$	(13,508,739	)

Net loss per common share
Basic and diluted	$	(0.19	)	$	(0.63	)	$	(0.75	)	$	(1.75	)

Weighted average shares outstanding:
Basic and diluted		15,775,135			11,851,531			15,388,772			7,700,114

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

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine months ended
	September 30,
	2011			2010 (Restated)
Cash flows from operating activities:
Net loss	$	(11,533,686	)	$	(13,508,739	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Amortization of stock issued for services		373,234			166,239
Share based compensation		5,592,638			5,495,346
Warrant modification expense		-			2,953,450
Change in fair value of commodity price derivatives		(398,840	)		(234,654	)
Change in fair value of convertible notes conversion derivative		(1,587,699	)		-
Compensation expense recognized for assignment of overrides		-			1,578,080
Amortization of deferred financing costs and issuance of stock for convertible debt interest		3,701,373			2,752,376
Depreciation, depletion, amortization and accretion		3,194,301			3,895,610

Changes in operating assets and liabilities:
Accounts receivable		(891,076	)		(904,672	)
Other assets		(19,674	)		66,673
Accounts payable		2,428,101			315,142
Restricted cash		144,001			(871,102	)
Related party payable		15,067			(70,808	)
Accrued expenses		297,330			1,148,742
Net cash provided by operating activities		1,315,070			2,781,683

Cash flows used in investing activities:
Additions of producing properties and equipment (net of purchase price adjustments)		-			(21,345,443	)
Acquisition of undeveloped properties		(9,033,007	)		(24,944,600	)
Drilling capital expenditures		(6,876,232	)		(926,882	)
Proceeds from sale of drilling rigs		-			100,000
Additions of office equipment		(40,648	)		(2,914	)
Investment in operating bonds		(160	)		(75,605	)
Net cash used in investing activities		(15,950,047	)		(47,195,444	)

Cash flows from financing activities:
Proceeds from sale of common stock, units and exercise of warrants		2,129,801			28,032,727
Proceeds from debt		8,000,000			28,500,000
Net change in debt		(377,498	)		(6,963,731	)
Net cash provided by financing activities		9,752,303			49,568,996

Change in cash and cash equivalents		(4,882,674	)		5,155,235
Cash and cash equivalents at beginning of period		5,528,744			108,400

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	646,070		$	5,263,635

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

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited interim consolidated financial statements were prepared by Recovery Energy, Inc. (“Recovery” or the “Company”) in accordance with generally accepted accounting principles (“GAAP”) 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, 2010. 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 amended Annual Report on Form 10-K/A filed on August 12, 2011.

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

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. We evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe that our estimates are reasonable. Our most significant financial estimates are associated with our estimated proved oil and gas reserves as well as valuation of common stock used in issuances of common stock, warrants and the valuation of the conversion rights related to the convertible notes payable.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Liquidity

Although cash provided by operating activities during the nine months ended September 30, 2011 was $1,315,000, cash used in investing activities exceeded cash provided by financing activities by approximately $6.2 million. This net cash use contributed to a substantial decrease in our net working capital as of September 30, 2011 and resulted in a working capital deficit of $1.9 million as of September 30, 2011. Principally as a result of continuing well costs related to second and third quarter drilling and completion activities, expenditures subsequent to September 30, 2011 have continued to exceed cash receipts, causing a further reduction of the Company’s working capital position.

Pursuant to our credit agreements with Hexagon, a substantial portion of our monthly net revenues derived from our producing properties is required to be used for debt and interest payments. Effective July 2011, Hexagon agreed to temporarily suspend for two months the requirement to remit monthly net revenues of approximately $900,000 in the aggregate as payment on the notes. In October 2011, Hexagon agreed to suspend this requirement for one additional month. In November 2011, Hexagon extended the maturity to January 1, 2013. The Company expects to repay Hexagon from the proceeds of a future financing transaction, or possibly from a sale of assets or other similar transaction.

Since inception, we have raised approximately $72 million in cash generally through private placements of debt and equity securities. In the immediate term, the Company expects that additional capital will be required to fund its working capital deficit, remaining capital budget for 2011, partially fund some of its ongoing overhead, fund the repayment of the deferred Hexagon note payments, and to provide additional capital to generally improve its working capital position. We anticipate that these capital requirements will be funded by a combination of capital raising activities, including the selling of additional debt and/or equity securities and the selling of certain assets. If we are not successful in obtaining sufficient cash sources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks and highly liquid debt securities that have original maturities of three months or less. Financial instruments that potentially subject the Company to concentration of credit risk consist primarily of cash deposits.

Restricted Cash

Restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities, and are restricted pursuant to our loan agreements.

Accounts Receivable

The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method.

Concentration of Credit Risk

The Company's cash equivalents and short-term investments are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company may at times have balances in excess of the federally insured limits.

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

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

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties or the amount of the impairment is added to costs subject to depletion calculations.

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to sum of i.) the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves, plus ii.) the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized.

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

There were no impairment charges recognized for the nine month periods ended September 30, 2011 and 2010.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Wells in Progress

Wells in progress represent wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to exploration and development costs and become subject to both depletion and the ceiling test calculations in future periods. At September 30, 2011, the Company had two Wells in Progress, both of which have been drilled and completed and are pending evaluation as to their potential to produce commercial quantities of oil and gas reserves.

Deferred Financing Costs

For the nine months ended September 30, 2011, the Company recorded deferred financing costs of approximately $2,000,000 related to the extension of its term notes and the closing of its convertible notes. Deferred financing costs include origination (warrants issued and overriding royalty interests assigned to our lender), and legal and engineering fees incurred in connection with the Company's credit facility, which are being amortized over the term of the credit facility (See Note 6—“Loan Agreements”). The Company recorded amortization expense of approximately $3,390,000 and $2,750,000 for the nine months ended September 30, 2011 and 2010, respectively.

Prepaid Advisory Fees

The Company had prepaid financial advisory fees of approximately $675,000 as of September 30, 2011. The prepaid advisory fees were paid with non-cash consideration (shares of our common stock and warrants exercisable for shares of our common stock issued to our financial advisors) initially totaling approximately $1,234,000. The amount is being amortized over the term of the underlying agreement. The Company amortized approximately $312,000, and $135,000, respectively, in prepaid advisory fees for the nine months ended September 30, 2011 and 2010.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Long-lived Assets

The Company accounts for the impairment and disposition of long-lived assets (other than capitalized exploration and development costs) in accordance with ASC 360, Impairment or Disposal of Long-Lived Assets. ASC 360 requires that the Company’s long-lived assets be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. An impairment charge to current operations is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the differences in the carrying value and estimated fair value of the impaired asset. No impairment was recorded during the nine month periods ended September 30, 2011 and 2010.

Fair Value of Financial Instruments

The Company's financial instruments, other than the derivative instrument discussed separately, including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are carried at cost, which approximates fair value due to the short-term maturity of these instruments. Additionally, the recorded value of the Company's long-term debt approximates its fair value as it bears interest at variable rates over the term of the loan.

Commodity Derivative Instrument

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

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

During the quarter, the Company settled all of its open hedging contracts resulting in a gain of $734,000.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Property and Equipment

Other property and equipment such as office furniture and equipment, vehicles, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is recorded using the straight-line method over the estimated useful lives of three years for computer equipment and five years for office equipment and vehicles. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Revenue Recognition

The Company records revenues from the sales of natural gas and crude oil when they are produced and sold.

Asset Retirement Obligation

The fair value of a liability for an asset retirement obligation is recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as exploration and development costs and included in proved oil and gas properties in the consolidated balance sheets. These assets are included in the base of carrying value for purposes of periodic depletion calculations.

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

Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated to operating expense using a systematic and rational method. As of September 30, 2011, the Company recorded a net asset of $540,707 and a related liability of $601,195.

The information below reconciles the value of the asset retirement obligation for the periods presented:

	For the Nine Months Ended September 30, 2011		For the Year Ended December 31, 2010
Balance, beginning of period	$	507,280	$	-
Liabilities incurred		61,469		478,208
Accretion expense		32,446		28,042
Change in estimate		-		1,030
Balance, end of period	$	601,195	$	507,280

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Share Based Compensation

The Company estimates the fair value of share-based payment awards made to employees and directors, including restricted stock and employee stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. We estimate the fair value of each share-based award using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards and the estimated volatility of our stock price.

Loss per Common Share

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, earnings per share and 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 period ended September 30, 2011, a total of 6,532,517 outstanding warrants and derivative shares related to convertible notes payable 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 2 – OIL AND GAS PROPERTIES

In February 2011, the Company purchased undeveloped oil and gas leases from various private individuals for $1,253,780 in cash and $653,449 in stock in the Grover Field and surrounding area in Weld County, Colorado, and Goshen County, Wyoming.

In March 2011, the Company purchased undeveloped oil and gas interests located in Laramie County, Wyoming. The purchase price was $6,469,552 cash and $5,798,546 in stock. The Company also closed on two acquisitions of undeveloped oil and gas leases from various private individuals for a combined $551,519 in cash in Goshen County, Wyoming.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 3 – WELLS IN PROGRESS

The following table reflects the net changes in capitalized additions to wells in progress for the periods presented, and includes amounts that were capitalized and reclassified to proved properties in the same period.

	For the Nine Months Ended September 30, 2011			For the Year Ended December 31, 2010
Balance, beginning of period	$	1,219,397		$	-
Additions to wells in progress		6,404,474			2,750,499
Reclassifications to proved properties		(3,212,761	)		(1,531,102	)
Balance, end of period	$	4,411,110		$	1,219,397

NOTE 4 - FINANCIAL INSTRUMENTS AND DERIVATIVES

During 2011 and 2010, the Company has entered into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. During the quarter ended September 30, 2011, the Company settled all future commodity swaps resulting in a gain of approximately $734,000.

The amount of gain (loss) recognized in income related to our derivative financial instruments was as follows:

	Three months ended September 30,					Nine months ended September 30,
	2011		2010			2011		2010
Realized gain on commodity price derivatives		733,830		292,805			402,256		565,634
Unrealized gains (loss) on commodity price derivatives		-		(394,552	)		222,788		234,652

Realized gains and losses occur as individual swaps mature and settle. These gains and losses are recorded as income or expenses in the periods during which applicable contracts settle. Swaps which are unsettled as of a balance sheet date are carried at fair market value, either as an asset or liability (See Note 5: “Fair Value of Financial Instruments”). Unrealized gains and losses result from mark to market changes in the fair value of these derivatives between balance sheet dates.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 5 - 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:

●	Level 1	Quoted prices (unadjusted) for identical assets or liabilities in active markets.

●	Level 2	Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable.

●	Level 3	Unobservable inputs that reflect the Company’s own assumptions.

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

Convertible Notes Payable Conversion Feature

In February 2011, the Company issued in a private placement $8,400,000 aggregate principal amount of three year 8% Senior Secured Convertible Debentures with a group of accredited investors who are existing shareholders of the Company. The Debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. The conversion feature has been determined to be a derivative liability and the Company engaged a third party to complete a valuation of this conversion feature as of June 30, 2011, which the Company updated for September 30, 2011(See Note 6 – “Loan Agreements – Convertible Notes Payable”). The valuation was completed using Level 3 inputs.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

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

	Level 1			Level 2			Level 3				Total
Liabilities:
Derivative Liability		$	—		$	—		$	(3,534,093	)		$	(3,534,093	)

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 or nine months ended September 30, 2011.

The Company used Level 3 inputs to estimate the fair value of common stock used in the acquisition of unproved oil and gas properties during the nine months ended September 30, 2011.

NOTE 6 - LOAN AGREEMENTS

Term Notes

The Company entered into three separate loan agreements with Hexagon Investments, LLC (“Hexagon”) during 2010. All three loans bear annual interest of 15% and mature on January 1, 2013.

Effective January 29, 2010, the Company entered into a $4.5 million loan agreement, with an original maturity date of December 1, 2010. Effective March 25, 2010, the Company entered into a $6.0 million loan agreement, with an original maturity date of December 1, 2010. Effective April 14, 2010, the Company entered into a $15.0 million loan agreement, with an original maturity date of December 1, 2010. All three loan agreements have similar terms, including customary representations and warranties and indemnification, and require the Company to repay the notes with the proceeds of the monthly net revenues from the production of the acquired properties. 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 Wilke Field, Albin Field, and State Line Field acquisitions.

The Company entered into a loan modification agreement on May 28, 2010, which extended the maturity date of the loans to December 1, 2011. In consideration for extending the maturity of the loans, Hexagon received 250,000 warrants with an exercise price of $6.00 per share. The loan modification agreement also required the Company to issue 250,000 five year warrants to purchase common stock at $6.00 per share to Hexagon if the Company did not repay the loans in full by January 1, 2011. Since the loans were not paid in full by January 1, 2011, the Company issued 250,000 additional warrants with an exercise price of $6.00 per share to Hexagon which was valued at approximately $1,600,000. This amount was recorded as a deferred financing cost and is being amortized over the remaining term of the loan.

In December 2010, Hexagon extended the maturity to September 1, 2012. In July 2011, Hexagon agreed to temporarily suspend for two months the requirement to remit monthly net revenues of the acquired properties as payment on the notes. In October 2011, Hexagon agreed to suspend this requirement for one additional month. In November 2011, Hexagon extended the maturity to January 1, 2013.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 6 – LOAN AGREEMENTS (Continued)

The Company is subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements. As of September 30, 2011, the Company was in compliance with all covenants under the facilities. 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 and accelerate all principal and interest outstanding.

Convertible Notes Payable

In February 2011, the Company issued in a private placement $8,400,000 aggregate principal amount of three year 8% Senior Secured Convertible Debentures (the "Debentures") with a group of accredited investors, who are existing shareholders of the Company. Of the proceeds from the sale, $3,000,000 is restricted to acquisition of and drilling activities on specified properties, which were pledged as collateral for the Debentures. The balance of the proceeds is to be used by the Company for working capital. The Debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. Interest on the Debentures is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or at the Company's option in shares of common stock, valued at 95% of the volume weighted average price of the common stock for the 10 trading days prior to an interest payment date. The Company can redeem some or all of the Debentures at any time. The redemption price is 115% of principal plus accrued interest. If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price will include a make-whole premium equal to the remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable in common stock. T.R. Winston & Company LLC acted as placement agent for the private placement and received $400,000 of Debentures equal to 5% of the gross proceeds from the sale.

During the second quarter, the Company engaged a third party to complete a valuation of the conversion feature, which the Company updated internally for the third quarter. The Company calculated a valuation of the conversion feature as of September 30, 2011 of approximately $3,534,000. The $13,000 increase in the value of the conversion feature during the quarter was shown as a derivative loss on conversion feature in the Statement of Operations for the three month period ended September 30, 2011.

Interest Expense

For the three and nine months ended September 30, 2011, the Company incurred interest expense of approximately $2,137,000 and $6,124,000, respectively, of which approximately $1,498,000 and $3,701,000, respectively, was non-cash interest expense related to the amortization of the deferred financing costs, accretion of the convertible notes payable discount, and convertible notes payable interest paid in stock.

For the three and nine months ended September 30, 2010, the Company incurred interest expense of approximately $1,592,000 and $4,603,000, respectively, of which approximately $729,000 and $2,752,000, respectively, was non-cash interest expense related to the amortization of the deferred financing costs.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 7 - COMMITMENTS and CONTINGENCIES

Environmental and Governmental Regulation

At September 30, 2011, 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 September 30, 2011, the Company had 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 positions of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.

Potential Stock Grants Under Employment/Appointment Agreements

Until May 2010, the employment agreements for our chief executive officer and former chief financial officer contained provisions which provided these individuals additional stock grants if the Company achieved certain market capitalization milestones. In May 2010, the employment agreements were modified and our chief executive officer and former chief financial officer were no longer entitled to stock grants based on market capitalization milestones.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 8 - SHAREHOLDERS’ EQUITY

Common Stock

Effective October 19, 2011, the Company completed a four-for-one reverse stock split on its common shares. All references to common stock and common stock prices have been adjusted to reflect the effects of the reverse stock split.

As of September 30, 2011, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 15,825,854 shares of common stock were issued and outstanding. No preferred shares were issued or outstanding.

During the nine months ended September 30, 2011, the Company issued 1,361,635 shares of common stock. The stock issuances were comprised of 703,138 shares issued for acquisitions valued at $6,690,795, 10,000 shares issued for services valued at $82,000, 231,250 shares issued as restricted stock grants to employees valued at $2,491,350, 41,915 shares is for interest expense on the convertible notes payable valued at $312,690, and 375,333 shares issued in connection with warrant exercises for $2,903,794 of cash.

In addition to the shares of common stock issued during the period, the Company issued convertible notes payable with a face value of $8.4 million. Based upon the conversion price of $9.40 per share, these notes would convert into 893,617 shares of common stock. The conversion price is subject to adjustments (See Note 6 – “Loan Agreements – Convertible Notes Payable”).

Temporary Equity

As part of the reverse merger in 2009, 21,250 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 preferential to common shares. The 21,250 shares, which were valued at $172,516, covered by the lock-up agreement were treated as temporary equity and reported separately from other shareholders’ equity. The lock-up period for 10,625 shares ended on September 21, 2010, with the other lock-up period ending on March 21, 2011. As a result, on March 21, 2011, the final 10,625 shares covered under the lock-up agreement were moved to permanent on equity.

Warrants

On January 1, 2011, the Company issued 250,000 warrants with an exercise price of $6.00 per share to Hexagon which was valued at approximately $1,600,000 (See Note 6—“Loan Agreements”).

A summary of warrant activity for the nine months ended September 30, 2011 is presented below:

				Weighted-Average
	Warrants			Exercise Price
Outstanding at December 31, 2010		5,764,233			$	7.04
Granted		250,000			$	6.00
Exercised, forfeited, or expired		(375,333	)		$	6.16
Outstanding at September 30, 2011		5,638,900			$	7.04

The aggregate intrinsic value of warrants was approximately $0 and $6,687,000 based on the Company’s closing common stock price of $5.20 and $8.20 as of September 30, 2011 and December 31, 2010, respectively, and the weighted average remaining contract life was 3.68 years and 4.15 years.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 8 - SHAREHOLDERS’ EQUITY (Continued)

Assumptions used in estimating the fair value of the warrants issued for the periods indicated are presented below:

	2011			2010
Weighted-average volatility		97	%		80	%
Expected dividends		0.00	%		0.00	%
Expected term (in years)		5			3 – 5
Risk-free rate		2.02	%		1.49	%

The Company 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.

NOTE 9 - SHARE BASED COMPENSATION

The Company 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. The Company implemented ASC 718 effective March 6, 2009.

During the nine months ended September 30, 2011, the Company granted 231,250 shares of restricted common stock to employees of which 66,667, 69,792, 76,041, and 18,750 shares vest during the years ended December 31, 2011, 2012, 2013, and 2014, respectively. The fair value of these share grants was calculated to be approximately $2,491,000.

The Company recognized stock compensation expense of approximately $917,000 and $2,714,000 for the three months ended September 30, 2011 and 2010, respectively, and $5,593,000 and $5,495,000 for the nine months ended September 30, 2011 and 2010, respectively. $3,551,000 of the stock compensation expense for the nine months ended September 30, 2011, was a one-time charge related to 481,250 shares included in the separation agreement of the former chief financial officer, which was accounted for as a cancellation of an award and issuance of a new award.

A summary of restricted stock grant activity for the nine months ended September 30, 2011 is presented below:

	Shares
Balance outstanding at December 31, 2010		2,235,797
Granted		231,250
Vested		(47,667	)
Balance outstanding at September 30, 2011		2,419,380

Total unrecognized compensation cost related to non-vested stock granted was approximately $1,789,000 as of September 30, 2011. The cost at September 30, 2011 is expected to be recognized over a weighted-average remaining service period of 0.81 years.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2011

(UNAUDITED)

NOTE 10 – SUBSEQUENT EVENTS

In October 2011, the Company negotiated a waiver with Hexagon regarding its Term Loans. The waiver allowed the Company to temporarily retain its net proceeds payment amounts for the period September 1, 2011 through September 30, 2011 (See Note 6—“Loan Agreements”).

In October 2011, the Company completed a four-for-one reverse stock split on its common shares. All references to common stock and common stock prices have been adjusted to reflect the effects of the reverse stock split (See Note 8 – “Shareholders’ Equity”).

In November 2011, Hexagon extended the maturity on all three loan agreements to January 1, 2013 (See Note 6 – “Loan Agreements”).

NOTE 11- REVISION TO FINANCIAL STATEMENTS

The financial statements as of December 31, 2010, and for the three and nine month periods ended September 30, 2010, were revised to incorporate additional general and administrative expense relating to warrant modification expense of $2,953,450 during the quarter ended September 30, 2010, following further analysis of modifications to the Company’s then outstanding warrants.

During September 2010, the Company made a temporary offer to all warrant holders who had received a warrant as part of the unit offering that was closed in May 2010. For all warrant holders who exercised their warrant during September, the Company would grant that warrant holder with a replacement warrant with an $8.80 exercise price. The closing price of the Company’s stock on the offering date was $8.20. A recent analysis of this 2010 transaction determined that the $2,953,450 increase in the value of the exercised warrants should be categorized as a current period warrant modification expense, as opposed to being categorized as an equity cost and netted out of gross proceeds in additional paid in capital. The increase in warrant value was calculated using the Black Scholes method of valuation and included as a period expense in general and administrative expense. The assumptions used in the calculation were as follows: volatility – 50%, dividends expected – 0%, expected term – 5 years, and risk free interest rate – 1.28%.

The effect of the changes in the financial statements is summarized below.

	Three Months Ended September 30, 2010						Nine Months Ended September 30, 2010
	Prior to Restatement			Restated			Prior to Restatement			Restated
Consolidated Statement of Operations:
General and Administrative	$	3,455,489		$	6,408,939			8,867,508			11,820,958
Total Costs and Expenses		5,499,970			8,453,420			14,220,291			17,173,741
Loss from Operations		(2,947,180	)		(5,900,630	)		(5,982,311	)		(8,935,761	)
Net Loss		(4,537,796	)		(7,491,246	)		(10,555,289	)		(13,508,739	)
Earnings per Common Share: Basic and Diluted		(0.10	)		(0.16	)		(0.34	)		(0.44	)

Consolidated Statement of Cash Flows:
Net Loss		(4,537,796	)		(7,491,246	)		(10,555,289	)		(13,508,739	)
Adjustment for Warrant Modification Expense		-			2,953,450			-			2,953,450
Net Cash Provided by Operating Activities		1,063,591			1,063,591			2,781,683			2,781,683

	Year Ended December 31, 2010
	Prior to Restatement			Restated
Consolidated Balance Sheet:
Additional Paid in Capital		90,861,527			93,814,977
Accumulated Deficit		(46,696,964	)		(49,650,414	)

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. 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 expectations 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 amended Annual Report on Form 10-K/A for the year ended December 31, 2010, including the following:

	•		Our ability to maintain adequate liquidity and resolve our existing working capital deficit;

	•		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

Recovery Energy Inc. is a Denver based independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the DJ Basin. 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.

Recent Developments

In February 2011, the Company issued in a private placement $8,400,000 aggregate principal amount of three year 8% Senior Secured Convertible Debentures with a group of accredited investors, who are existing shareholders of the Company. Of the proceeds from the sale, $3,000,000 was restricted to the acquisition of and drilling activities on specified properties, which were pledged as collateral for the Debentures. The balance of the proceeds is to be used by the Company for working capital. The Debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. Interest on the Debentures is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or at the Company's option in shares of common stock, valued at 95% of the volume weighted average price of the common stock for the 10 trading days prior to an interest payment date. The Company can redeem some or all of the Debentures at any time. The redemption price is 115% of principal plus accrued interest. If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price will include a make-whole premium equal to the remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable in common stock. T.R. Winston & Company LLC acted as placement agent for the private placement and received $400,000 of Debentures equal to 5% of the gross proceeds from the sale.

In February 2011, the Company closed on the acquisition of oil and gas leases from various private individuals on approximately 1,700 leasehold acres in the Grover Field and surrounding area in Weld County, Colorado, and approximately 6,600 net acres in Goshen County, Wyoming. The purchase price was $1,253,780 in cash and $653,449 in common stock.

In March 2011, the Company closed on the acquisition of oil and gas interests of approximately 8,060 net acres located in Laramie County, Wyoming. The purchase price was $6,469,552 cash and $5,798,546 in stock.

In March 2011, the Company entered into a modification of its swap agreement whereby Shell extended the company $1,000,000 of unsecured credit. Additionally, the Company entered into an additional commodity swap for 100 barrels per day from November 2011 through October 2012 at a price of $100.20 per barrel.

In March 2011, the Company closed on the acquisition of oil and gas leases from various private individuals for $390,000 in cash on approximately 651 net acres in Goshen County, Wyoming.

In March 2011, the Company closed on the acquisition of oil and gas leases from various private individuals for $161,519 in cash on approximately 640 net acres in Goshen County, Wyoming.

In March 2011, the Company issued 375,334 shares of common stock upon the exercise of outstanding warrants to purchase common stock. The Company received gross proceeds of approximately $2,315,000.

Liquidity and Capital Resources

Pursuant to our credit agreements with Hexagon, a substantial portion of our monthly net revenues derived from our producing properties is required to be used for debt and interest payments. Effective June 2011, Hexagon agreed to temporarily suspend for two months the requirement to remit monthly net revenues of approximately $900,000 in the aggregate as payment on the notes. In October 2011, Hexagon agreed to suspend this requirement for one additional month. In November 2011, Hexagon extended the maturity to January 1, 2013. The Company expects to repay Hexagon from the proceeds of a future financing transaction, or possibly from a sale of assets or other similar transaction.

If we successfully secure a debt or equity financing on or prior to November 30, 2011 that results in proceeds of at least $10 million, an affiliate of Hexagon may, but is not obligated to, put to the Company certain producing oil properties, including undeveloped acreage, overriding royalty interests and certain other rights, for cash consideration of approximately $9.0 million. The actual purchase price will be determined at closing based upon a base price of $10,143,985, less actual net production proceeds received by Hexagon's affiliate during the period of July 31, 2011 through the date of closing. The Company anticipates that if these properties are acquired, daily net oil production will increase by approximately 130 BOPD. In addition, the Company's net revenue interest in approximately half of its undeveloped acreage will increase to an average of over 85%.

2011 Capital Budget

We have spent $15.9 million in capital costs during the nine months ended September 30, 2011, including $9.0 million for acquisitions and $6.9 million for the drilling and completion of 3 gross (3.0 net) conventional wells and 2 gross (0.8 net) Recovery-operated horizontal Niobrara wells. The remainder of our previously announced $20 million capital budget for 2011 is being substantially deferred pending completion of a refinancing or other transaction that will provide for the repayment of the Hexagon debt, capital for future drilling and development costs and general working capital. During the last quarter of 2011, the Company will continue to fund certain costs to confirm economic viability on wells that have been drilled and are currently in completion stages, and may also participate with non-operating working interest in new wells that are proposed by other operators to be drilled on acreage that we already own. We cannot predict how many well proposals we might receive from other operators, nor estimate our pro-rata well expenses. However, if any wells are proposed, we will be required to fund our working interest portion of each well or be subject to a non-consent penalty.

Capital Resources

Currently, the majority of our cash flows from operations are applied to the principal and interest of our loans. Due to large capital expenditures in 2011, our liquidity and working capital have deteriorated. While we believe that we have sufficient liquidity and capital resources to maintain our staff and continue our current production operations, we require additional capital to resolve our current working capital deficit and will also require substantial additional capital in order to fully test, develop and evaluate our 147,000 gross (130,500 net) undeveloped acres. We expect to obtain this capital through a variety of sources, including, but not limited to, future debt and equity financings and potentially from future joint venture partners. In the absence of near term major debt or equity financing or other similar transaction, we may be required to sell certain assets in order to meet obligations as they arise. We can provide no assurance that we will be able to secure a major financing, nor can we predict the terms of any future potential financing transactions.

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

	September 30, 2011			December 31, 2010
Financial Position Summary
Cash and cash equivalents	$	646,070		$	5,528,744
Working capital	$	(1,948,654	)	$	4,436,365
Balance outstanding on term notes and convertible notes payable	$	24,684,128		$	20,438,682
Shareholders’ equity	$	49,142,788		$	44,256,602
Ratios
Debt to total capital ratio		33	%		32	%
Total debt to equity ratio		50	%		46	%

During the nine months ended September 30, 2011, our working capital decreased to $(1,948,654) from $4,436,365 at December 31, 2010. The lower working capital and cash position is primarily the result of $15,950,000 in capital additions, offset by approximately $10,100,000 in capital raised, and offset further by $1,315,000 of cash provided by operations.

	Nine Months Ended September 30,
	2011			2010
Cash provided by (used in):
Operating activities	$	1,315,070		$	2,781,683
Investing activities		(15,950,047	)		(47,195,444	)
Financing activities		9,752,303			49,568,996

Net change in cash		(4,882,674)			5,155,235

During the nine month periods ended September 30, 2011 and 2010, net cash provided by operating activities was $1,315,070 and $2,781,683, respectively. The primary changes in operating cash during the nine months ended September 30, 2011 was $11,533,686 of net loss, adjusted for non-cash charges of $3,194,301 of depreciation, depletion and amortization expenses (“DD&A”) and accretion expense, $5,592,638 of stock-based compensation, and $3,701,373 of amortization of deferred financing costs, offset by a non-cash change in fair value of convertible notes conversion option of $1,587,699.

During the nine month periods ended September 30, 2011 and 2010, net cash used by investing activities was $15,950,047 and $47,195,444. The primary changes in investing cash during the nine months ended September 30, 2011 was $9,033,007 related to our acquisitions of unproved acreage and $6,876,232 in drilling capital expenditures.

During the nine month periods ended September 30, 2011 and 2010, net cash provided by financing activities was $9,752,303 and $49,568,996. The primary changes in financing cash during the nine months ended September 30, 2011 was net proceeds from the exercise of warrants for $2,129,801 and the issuance of convertible notes payable for $8,000,000, offset by a net change in debt of $377,498.

Loan Agreements

Term Notes

The Company entered into three separate loan agreements with Hexagon Investments, LLC (“Hexagon”) during 2010. All three loans bear annual interest of 15% and mature on January 1, 2013.

Convertible Notes Payable

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Oil and Gas Properties & Strategy

We have developed and acquired an oil and natural gas base of proved reserves, as well as a portfolio of development drilling and exploratory drilling opportunities of high-impact conventional and non-conventional prospects with an emphasis on multiple producing horizons and the Niobrara shale resource play. We believe these prospects offer the potential for 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, and Wyoming. Since January 1, 2010 we have acquired or developed 22 producing wells. We currently own interests in approximately 150,000 gross (132,500 net) leasehold acres, of which 147,000 gross (130,500 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska in the DJ Basin. We intend to continue to evaluate and invest in acquisitions and internally generated prospects. It is our long-term goal to maximize our DJ Basin acreage position through development drilling of our conventional horizons as well as development of our Niobrara shale potential.

We have invested, and intend to continue to invest, primarily in 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 the DJ Basin in Colorado, Nebraska, and Wyoming.

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 given appropriate economic conditions. 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.

Retain Operational Control and Significant Working Interest. In our principal development targets, we typically seek to maintain operational control of our development and drilling activities. As operator, we retain more control over the timing, selection and process of drilling prospects and completion design, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of our capital expenditures. We have continued to maintain high working interest in our DJ Basin properties which maximizes our exposure to generated cash flows and increases in value as the properties are developed. With operational control, we can also schedule our drilling program to satisfy most of our lease stipulations and continue to put our acreage into “held by production” status, thus eliminating expirations. The majority of our acreage is contiguous which will permit efficiencies in drilling and production operations.

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 we may 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. Historically, we also outsourced some of our geological, geophysical, reservoir engineering and land functions in order to help reduce capital requirements. We recently brought many of these functions in-house to provide us with greater ability to maximize the value of our growing leasehold position.

From time to time we 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. 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. We currently have no outstanding commodity price hedging instruments.

Marketing and Pricing

We 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 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 oil and natural gas. 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.

Recent Performance

Following are summary comments of our performance in several key areas during the quarter ended September 30, 2011.

●		Average Daily Production
		During the quarter ended September 30, 2011, average daily net production was 282 BOPD net compared to average daily net production of 419 BOPD for the quarter ended September 30, 2010. This decrease is primarily attributable to decline curves related to our Palm and State Line field wells, offset by approximately 45 BOPD attributable to wells drilled subsequent to September 30, 2010.

●		Oil and Gas Sales
		During the quarter ended September 30, 2011, net oil and gas sales were $1,811,731. Our average oil and gas price received was $81.94 per barrel of oil and $5.10 per Mcf of gas.

●		Cash Flow from Operations
		During the quarter ended September 30, 2011, we generated $1,315,070 in cash from operations.

●		Working capital deteriorated significantly due to the following:
	-	Cash used in investing activities during the nine month period ended September 30, 2011 exceeded cash provided by financing activities during the same period by $6.2 million.

	-	As a result of the current due dates of the Hexagon debt facilities, a total of $20.2 million in structured debt is classified as current liabilities as of September 30, 2011.

Results of Operations

For the Three Months Ended September 30, 2011 compared to the Three Months Ended September 30, 2010

The Company reported a net loss for the three months ended September 30, 2011 of approximately $3,028,000 compared to a net loss of approximately $7,491,000 for the same period in 2010.

Oil and Gas Revenues and Production

Oil and gas revenues decreased by approximately $841,000, or 32%, from approximately $2,653,000 in the third quarter of 2010 to approximately $1,812,000 in the third quarter of 2011. Our production volume on a BOE basis decreased 34% from 38,538 BOE during the third quarter of 2010 to 25,408 BOE during the third quarter of 2011. This decrease is primarily attributable to decline curves related to our Palm and State Line field wells, offset by approximately 45 BOPD attributable to wells drilled subsequent to September 30, 2010. The decrease in production volumes was partially offset by increased prices during the third quarter of 2011 versus the third quarter of 2010. Oil price realization increased by 19% to $81.94 per barrel for the third quarter of 2011, compared to $68.84 per barrel for the same period in 2010. In addition to the increase in price realization during the third quarter of 2011, the Company realized a gain on hedges of approximately $734,000 compared to a realized hedge gain of approximately $293,000 for the same period in 2010. The decrease in oil production was also offset by an increase in production of natural gas. Natural gas production increased from zero during to the three months ended September 30, 2010 to 31,579 Mcf during the same period in 2011.

Production and average prices for the third quarter of 2011 are presented in the following table:

	Three Months Ended
	September 30, 2011
	Volume		Average Price
Product:
Oil (Bbls)		20,145	$	81.94
Natural Gas (Mcf)		31,579	$	5.10

Average daily net production was 282 BOPD for the quarter ended September 30, 2011.

Oil and gas production expenses, depreciation, depletion and amortization

	Three Months Ended September 30,
	2011
	(per BOE)
Average price	$	71.31

Production costs		13.58
Production taxes		7.53
Depletion and amortization		41.44

Total operating costs		62.55


Gross margin	$	8.76

Gross margin percentage		12.28	%

Commodity Price Derivative Activities

Changes in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivative instruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted 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. During the quarter we settled all of our open commodity derivative contracts and realized a gain on settlement of $781,488.

We recorded a net realized gain on our commodity derivative contracts that do not qualify for cash flow hedge accounting of $733,830 (including our settlement gain of $781,488) for the quarter ended September 30, 2011, compared to a net realized gain of $292,805 for the quarter ended September 30, 2010. We also recorded an unrealized gain on commodity price derivatives of $222,788 for the quarter ended September 30, 2010.

General and administrative expenses

General and administrative expenses were $1,981,000 for the quarter ended September 30, 2011, compared to $6,409,000 for the quarter ended September 30, 2010. Our general and administrative expenses for the third quarter of 2011 included approximately $362,000 in professional fees and approximately $917,000 in non-cash compensation expense. Our general and administrative expenses for the third quarter of 2010 included approximately $285,000 in professional fees, approximately $2,714,000 in non-cash compensation expense, and approximately $20,000 in expense associated with the assignment of overriding royalty interests. In addition, general and administrative expense in the third quarter of 2010 included non-cash warrant modification expense of $2,953,000. Excluding the specific expenses cited above, the net increase in core general and administrative expenses in the third quarter of 2011 compared to 2010 is attributed primarily to increases in staffing.

Interest Expense

Interest expenses increased approximately $545,000, or 34%, to approximately $2,137,000 in the third quarter of 2011 from $1,592,000 in the comparable period of 2010. Non-cash interest expense in the third quarter of 2011 was approximately $1,498,000, compared to approximately $729,000 in the comparable period of 2010.

For the Nine Months Ended September 30, 2011 compared to the Nine Months Ended September 30, 2010

The Company reported a net loss for the nine months ended September 30, 2011 of approximately $11,534,000 compared to a net loss of approximately $13,509,000 for the same period in 2010. The net loss for the nine months ended September 30, 2011, was impacted by a $1,588,000 non-cash gain related to the mark-to-market valuation of the conversion derivative liability embedded in our convertible notes payable, and a $3,551,000 non-cash charge related to the separation agreement with our former chief financial officer.

Oil and Gas Revenues and Production

Oil and gas revenues decreased $1,452,000, or 20%, from approximately $7,433,000 for the first nine months of 2010 to approximately $5,981,000 for the same period in 2011. Our production volume on a BOE basis decreased 27% from 106,724 BOE during the first nine months of 2010 to 77,819 BOE during the first nine months of 2011. This decrease is primarily attributable to decline curves related to our Palm and State Line field wells, offset by the Palm and State Line fields not being acquired until April 2010, as well as approximately 45 BOPD attributable to wells drilled subsequent to September 30, 2010. The decrease in production volume was partially offset by increased prices during the first nine months of 2011 versus the first nine months of 2010 with oil price realization increasing by 26% to $87.69 per BOE for the first nine months of 2011, compared to $69.65 per BOE for the same period in 2010. This increase in price realization during 2011 was partially offset by a realized gain on hedges of approximately $402,000 compared to a realized gain on hedges of approximately $566,000 for the same period in 2010. The decrease in oil production was also offset by an increase in production of natural gas. Natural gas production increased from zero during to the nine months ended September 30, 2010 to 88,229 Mcf during the same period in 2011.

Production and average prices for the first nine months of 2011 are presented in the following table:

	Nine Months Ended
	September 30, 2011
	Volume		Average Price
Product:
Oil (Bbls)		63,114	$	87.69
Natural Gas (Mcf)		88,229	$	5.06

Average daily net production was 288 BOPD for the nine months ended September 30, 2011.

Oil and gas production expenses, depreciation, depletion and amortization

	Nine Months Ended September 30,
	2011
	(per BOE)
Average price	$	76.85

Production costs		14.32
Production taxes		8.10
Depletion and amortization		41.05

Total operating costs		63.47


Gross margin	$	13.38

Gross margin percentage		17.41	%

Commodity Price Derivative Activities

We recorded a net unrealized gain on our commodity derivative contracts of $222,788 for the nine months ended September 30, 2011, compared to a net unrealized gain of $234,654 for the nine months ended September 30, 2010. These amounts represent an unrealized non-cash gain which represents a change in the fair value of our mark-to-market commodity derivative instruments. We realized a gain on our commodity derivative contracts of $402,256 for the nine months ended September 30, 2011, compared to a realized gain of $565,634 for the nine months ended September 30, 2010. During the quarter ended September 30, 2011, the Company settled all of its open derivative contracts. Included in our realized gain for the nine months ended September 30, 2011, was the settlement gain of $781,488.

General and administrative expenses

General and administrative expenses were $8,838,000 for the nine months ended September 30, 2011, compared to $11,821,000 for the comparable period of 2010. Our general and administrative expenses for the first nine months of 2011 included approximately $1,076,000 in professional fees and approximately $5,593,000 in non-cash compensation expense, which includes a one-time charge of approximately $3,551,000 related to the separation agreement with our former chief financial officer. Our general and administrative expenses for the first nine months of 2010 included approximately $831,000 in professional fees, approximately $5,495,000 in non-cash compensation expense, and approximately $1,598,000 in expense associated with the assignment of overriding royalty interests. . In addition, general and administrative expense in 2010 included non-cash warrant modification expense of $2,953,000. Excluding the specific expenses cited above, the net increase in core general and administrative expenses in the first half of 2011 compared to 2010 is attributed primarily to increases in staffing.

Interest Expense

Interest expenses increased approximately $1,526,000, or 33%, to approximately $6,124,000 for the nine months ended September 30, 2011 from $4,603,000 in the comparable period of 2010, due in part to the addition of the convertible notes payable in February 2011, but also due to an increase in the amortization of non-cash deferred financing costs. Non-cash interest expense for the nine months ended September 30, 2011 was approximately $3,701,000, compared to approximately $2,752,000 in the comparable period of 2010.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not required for smaller reporting companies.

Item 4T. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2011, the end of the period covered by this report. Based upon management’s evaluation, our Chief Executive Officer and our Chief Financial Officer have concluded that, as of September 30, 2011, our disclosure controls and procedures were designed at the reasonable assurance level and were effective at the reasonable assurance level to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities and migrating processes.

In our Quarterly Report on Form 10Q for the quarter ended June 30, 2011, we noted the following material weaknesses in our disclosure controls and systems:

·	Review of contracts for financial implications was not being performed timely.
·	Independent, internal reviews and approvals of critical accounting schedules used to prepare financial statements were not performed timely during the second quarter.

Since the date of that report, we have designed and are in the process of implementing new controls surrounding the review of material contracts, the review of critical accounting schedules and our quarter closing process.

Other than as noted above, there were no other changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations in Control Systems

Our controls and procedures were designed at the reasonable assurance level. However, because of inherent limitations, any system of controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance of achieving the desired objectives of the control system. In addition, the design of a control system must reflect the fact that there are resource constraints, and management must apply its judgment in evaluating the benefits of controls relative to their costs. Further, no evaluation of controls and procedures can provide absolute assurance that all errors, control issues and instances of fraud will be prevented or detected. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls and procedures is also based in part on certain assumptions regarding the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

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 2010 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 September 2011, the Company purchased certain oil and gas interests located in Weld County, Colorado. The purchase price was 28,500 shares of our common stock. Issuance of these shares was not registered under the Securities Act of 1933. The issuance of these shares was exempt from registration, pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D and Rule 506 promulgated thereunder. These securities qualified for exemption since the issuance securities by us did not involve a public offering and the purchasers are all accredited investors as defined in Regulation D. The offering was not a "public offering" as defined in Section 4(2) due to the insubstantial number of persons involved in the sale, size of the offering, manner of the offering and number of securities offered. In addition, these shareholders have the necessary investment intent as required by Section 4(2) since they agreed to and received share certificates bearing a legend stating that such shares are restricted pursuant to Rule 144 of the 1933 Securities Act. This restriction ensures that these shares would not be immediately redistributed into the market and therefore not be part of a "public offering." Based on an analysis of the above factors, we have met the requirements to qualify for exemption under Section 4(2) of the Securities Act and Regulation D for this transaction.

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: November 14, 2011	By:	/s/ Roger A Parker
		Roger A Parker
		Chief Executive Officer

Date: November 14, 2011	By:	/s/ A. Bradley Gabbard
		A. Bradley Gabbard
		Chief Financial Officer and Principal Accounting Officer

LILIS ENERGY, INC. - FORM 10-Q - November 14, 2011

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LILIS ENERGY, INC. Reports