S-1

As filed with the Securities and Exchange Commission on January 18, 2013

Registration No. 333-

United States

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

______________________

RECOVERY ENERGY, INC.

(Exact name of registrant as specified in its charter)

Nevada	1311	74-3231613
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

A. Bradley Gabbard

President and Chief Financial Officer

Recovery Energy, Inc.

1900 Grant Street, Suite #720

Denver, CO   80203

1-888-887-4449

(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices and agent for service)

Copies to:

Ronald R. Levine, II, Esq.

Davis Graham & Stubbs LLP

1550 Seventeenth Street, Suite 500

Denver, CO 80202

Approximate date of commencement of proposed sale to public: as soon as practicable after the registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. x

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earliest effective registration statement for the same offering.  o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” 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

CALCULATION OF REGISTRATION FEE

Title of each class of securities to be registered	Amount to be registered		Proposed maximum offering price per share (2)		Proposed maximum aggregate offering price (2)		Amount of registration fee (2)
Common Stock (1)		1,630,096	$	2.045	$	3,333,546	$	454.70

(1) Represents (a) 1,176,483 shares of common stock that may be offered by us to the holders of an aggregate principal amount of $5,000,000 of our 8% Senior Secured Debentures due February 8, 2014 (the “Debentures”) in the event of conversion of the Debentures (at a conversion price of $4.25 per share), (b) 423,517 shares of common stock that may be offered by us to holders of the Debentures as interest payments in connection with the Debentures (at a conversion price equal to the fair market value of such shares on the date of the interest payment), (c) 30,096 shares of common stock issued previously on a restricted basis to holders of the Debentures as interest payments and being registered for resale on behalf of such holders and (d) pursuant to Rule 416 under the Securities Act, an indeterminate number of shares of common stock that are issuable upon stock splits, stock dividends, recapitalizations or other similar transactions affecting such shares.

(2) Estimated solely for the purpose of determining the registration fee pursuant to Rule 457 promulgated under the Securities Act of 1933, as amended (the “Securities Act”), based upon the high and low prices of the common stock of Recovery Energy, Inc. (the “Registrant”) as quoted on the Nasdaq Global Market on January 14, 2013.

The information in this prospectus is not complete and may be changed without notice.  The shares of common stock offered hereby may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and Recovery Energy, Inc. is not soliciting offers to buy these securities, in any state where the offer or sale of these securities is not permitted.

Recovery Energy, Inc. hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We and the selling stockholder may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and we and the selling stockholder are not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to completion, dated January 18, 2013

1,630,096 shares of Common Stock

RECOVERY ENERGY, INC.

This prospectus relates to (a) 1,176,483 shares of common stock of Recovery Energy, Inc. that may be offered by us to the holders of an aggregate principal amount of $5,000,000 of our 8% Senior Secured Debentures due February 8, 2014 (the “Debentures”) in the event of conversion of the Debentures (at a conversion price of $4.25 per share), (b) 423,517 shares of common stock Recovery Energy, Inc. that may be offered by us to holders of the Debentures as interest payments in connection with the Debentures (at a conversion price equal to the fair market value of such shares on the date of the interest payment), and (c) 30,096 shares of common stock Recovery Energy, Inc. issued previously on a restricted basis to holders of the Debentures as interest payments and being registered for resale on behalf of such holders, which may be offered by the selling stockholders identified on page 14 of this prospectus for their own account.  We are paying the expenses incurred in registering the shares, but all selling and other expenses incurred by the selling stockholders will be borne by the selling stockholders.

The shares of common stock being offered by the selling stockholders pursuant to this prospectus are “restricted securities” under the Securities Act of 1933, as amended (the “Securities Act”), before their sale under this prospectus. This prospectus has been prepared for the purpose of registering these shares of common stock under the Securities Act to allow for a sale by the selling stockholders to the public without restriction. Each of the selling stockholders and the participating brokers or dealers may be deemed to be an “underwriter” within the meaning of the Securities Act, in which event any profit on the sale of shares by such selling stockholder, and any commissions or discounts received by the brokers or dealers, may be deemed to be underwriting compensation under the Securities Act.

Our common stock is quoted on the Nasdaq Global Market under the symbol “RECV”.   On January 17, 2013, the last reported sale price of our common stock was $2.25 per share.

Investing in our common stock involves a high degree of risk. Please carefully consider the “Risk Factors” beginning on page 3 of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved the securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is _________, 2013.

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	2
PROSPECTUS SUMMARY	3
RISK FACTORS	3
USE OF PROCEEDS	14
SELLING STOCKHOLDERS	14
PLAN OF DISTRIBUTION	14
DESCRIPTION OF COMMON STOCK	15
BUSINESS AND PROPERTIES	15
LEGAL PROCEEDINGS	29
MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS	30
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	31
DIRECTORS AND EXECUTIVE OFFICERS	46
EXECUTIVE COMPENSATION	48
TRANSACTIONS WITH RELATED PERSONS	53
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	55
DISCLOSURE OF COMMISSION POSITION ON INDEMNIFICATION FOR SECURITIES ACT LIABILITY	56
LEGAL MATTERS	56
WHERE YOU CAN FIND MORE INFORMATION	56
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS	57

We have not authorized any dealer, salesperson or other person to give any information or represent anything not contained in this prospectus.  You should not rely on any unauthorized information.  This prospectus does not offer to sell or buy any shares in any jurisdiction in which it is unlawful.  The information in this prospectus is current as of the date on the cover.  You should rely only on the information contained or incorporated by reference in this prospectus.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This prospectus includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to, any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations; any statements concerning future production, reserves or other resource development opportunities, any projected well performance or economics, or potential joint ventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements of belief; and any statements of assumptions underlying any of the foregoing.

Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “expect” or “anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this presentation. Except as required by law, we do not intend, and undertake no obligation, to update any forward-looking statement.

Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-looking statements, are subject to change and inherent risks and uncertainties. The factors impacting these risks and uncertainties include, but are not limited to:

● estimated quantities and quality of oil and natural gas reserves;

● exploration, exploitation and development results;

● fluctuations in the price of oil and natural gas, including reductions in prices that would adversely affect our revenue, cash flow, liquidity, reserves and access to capital;

● availability of capital on an economic basis, or at all, to fund our capital needs;

● availability of, or delays related to, drilling, completion and production, personnel, supplies and equipment;

● the timing and amount of future production of oil and gas;

● the completion, timing and success of our drilling activity;

● the inability of management to effectively implement our strategies and business plans;

● potential default under our secured obligations or material debt agreements;

● lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements;

● declines in the values of our natural gas and oil properties resulting in write-downs;

● inability to hire or retain sufficient qualified operating field personnel;

● increases in interest rates or our cost of borrowing;

● deterioration in general or regional (especially Rocky Mountain) economic conditions;

● the strength and financial resources of our competitors;

● the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;

● inability to acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts;

● delays, denials or other problems relating to our receipt of operational consents and approvals from governmental entities and other parties

● unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids;

● environmental liabilities;

● loss of senior management or technical personnel;

● adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations;

● changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate; and

● other factors, many of which are beyond our control.

Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.

For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, we urge you to carefully review and consider the disclosures made in the “Risk Factors” section of this prospectus and of our SEC filings, available free of charge at the SEC’s website (www.sec.gov).

2

PROSPECTUS SUMMARY

Industry terms used in this prospectus are defined in the Glossary of Oil and Natural Gas Terms, beginning on page 26.

Overview of Our Business

Recovery Energy, Inc. (NASDAQ: RECV), sometimes referred to in this prospectus as “we,” “us,” “our,” “Recovery Energy,” “Recovery,” or the “Company,” is a Denver based independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. Our current activities are focused on the Denver-Julesburg (“DJ”) Basin in Colorado, Wyoming and Nebraska. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team and via the future exploration and development of the approximate 125,000 net acres of developed and undeveloped leases that are currently held by the Company, primarily in the northern DJ Basin.

We have developed and acquired an oil and natural gas base of proved reserves, as well as a portfolio of exploration and development prospects with high-impact conventional and non-conventional reservoir opportunities with an emphasis on multiple producing horizons and the Niobrara, Codell and Greenhorn shale resource plays. Since early 2010, we have acquired and/or developed 29 producing wells. As of December 31, 2011 we owned interests in approximately 140,000 gross (125,000 net) leasehold acres, of which 118,000 gross (103,000 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 in the DJ Basin and elsewhere.  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 were incorporated in August of 2007 in the State of Nevada as Universal Holdings, Inc.  In October 2009, we changed our name to Recovery Energy, Inc.  Our executive offices are located at 1900 Grant Street, Suite #720, Denver, CO 80203.  Our telephone number is 1-303-951-7920.  Our website is www.recoveryenergyco.com.  The information on our website is not intended to be a part of this prospectus, and you should not rely on any of the information provided there in making your decision to invest in our common stock.

The Offering

The shares offered hereby consist of (a) 1,176,483 shares of common stock that may be offered by us to the holders of an aggregate principal amount of $5,000,000 of our 8% Senior Secured Debentures due February 8, 2014 (the “Debentures”) in the event of conversion of the Debentures (at a conversion price of $4.25 per share), (b) 423,517 shares of common stock that may be offered by us to holders of the Debentures as interest payments in connection with the Debentures (at a conversion price equal to the fair market value of such shares on the date of the interest payment), and (c) 30,096 shares of common stock issued previously on a restricted basis to holders of the Debentures as interest payments and being registered for resale on behalf of such holders.

RISK FACTORS

Investing in our shares involves significant risks, including the potential loss of all or part of your investment.  These risks could materially affect our business, financial condition and results of operations and cause a decline in the market price of our shares.  You should carefully consider all of the risks described in this prospectus, in addition to the other information contained in this prospectus, before you make an investment in our shares. In addition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors, include the following:

Risks Related to Our Company

We have historically incurred losses and cannot assure investors as to future profitability. We have historically incurred losses from operations during our history in the oil and natural gas business. We had a cumulative deficit of approximately $68.0 million as of December 31, 2011 and $81 million for September 30, 2012. Many of our properties are in the exploration stage, and to date we have established a limited volume of proved reserves on our properties. Our ability to be profitable in the future will depend on successfully implementing our acquisition, exploration, development and production activities, all of which are subject to many risks beyond our control. Even if we become profitable on an annual basis, we cannot assure you that our profitability will be sustainable or increase on a periodic basis. In addition, should we be unable to continue as a going concern, realization of assets and settlement of liabilities in other than the normal course of business may be at amounts significantly different from those in the financial statements included in this prospectus.

3

Our credit agreements mature on December 31, 2013, and our lender can foreclose on several of our properties if we do not pay off or refinance our approximately $19.5 million of loans.Some of our oil and gas properties, including many of our producing properties,  are pledged as collateral for our credit agreements. Failure to repay these loans at maturity or refinance them could cause a default under the credit agreements and allow the lender to foreclose on these properties.

Our 8% Senior Secured Debentures mature on February 8, 2014 and require monthly interest payments, and the debenture holders can foreclose on several of our properties if we default.Some of our oil and gas properties, including producing properties, are pledged as collateral for our 8% Senior Secured Debentures. An event of default under the debentures would allow the lender to foreclose on these properties.

Currently, the majority of our revenue after field level operating expenses is required to be paid to our lender as debt service.The terms of our credit agreements require us to pay a significant portion of our operating cash flow as debt service. In 2011, we paid $842,000 in principal and $3,156,000 in interest pursuant to such requirements, representing approximately 700% of our cash flow from operations, and in 2012, we paid $0.68 million in principal and $3.22 million in interest. In 2011, our lender deferred the payment of approximately $2 million of revenue toward debt service, and there can be no assurance that our lender will continue to permit deferrals. As of September 30, 2012, we had working capital of ($0.90) million.  In February 2012, we completed the sale of certain rights in our Grover field property for $4.5 million, and in December 2012 we granted a four-year lease for the deep rights on approximately 6,300 net acres of our undeveloped leasehold acreage in the Denver-Julesburg Basin for approximately $1.5 million. Additionally, we will seek to obtain additional capital through the sale of our equity or debt securities, the successful deployment of our cash on hand, bank lines of credit, joint ventures, and project financing. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price could be materially adversely affected.

We will require additional capital in order to achieve commercial success and, if necessary, to finance future losses from operations as we endeavor to build revenue, but we do not have any commitments to obtain such capital and we cannot assure you that we will be able to obtain adequate capital as and when required. The business of oil and gas acquisition, drilling and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. We believe that our ability to achieve commercial success and our continued growth will be dependent on our continued access to capital either through the additional sale of our equity or debt securities, bank lines of credit, project financing, joint ventures, sale or lease of undeveloped properties, or cash generated from oil and gas operations.

We do not have a significant operating history and, as a result, there is a limited amount of information about us on which to make an investment decision. In January 2010, we acquired our first oil and gas prospects and received our first revenues from oil and gas production in February 2010. In November 2012, our chairman and chief executive officer retired, and we appointed W. Phillip Marcum to the position of chairman and chief executive officer, and appointed A. Bradley Gabbard to the position of president (in addition to his current position as chief financial officer). Accordingly, there is little operating history upon which to judge our business strategy, our management team or our current operations.

We have limited management and staff and will be dependent upon partnering arrangements. We have seven employees. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:

● the possibility that such third parties may not be available to us as and when needed; and

● the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.

If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price could be materially adversely affected.

4

The loss of our chief executive officer or our president and chief financial officer could adversely affect us. We are dependent on the experience of our executive officers to implement our operational objectives and growth strategy. The loss of the services of either of these individuals could have a negative impact on our operations and our ability to implement our strategy.

We experienced a material weakness in our disclosure controls and systems. In our Annual Report on Form 10K/A for the year ended December 31, 2011, we noted that the following material weaknesses in our internal control over financial reporting existed as of December 31, 2011:

● Insufficient independent internal review and approval of critical accounting schedules used in the preparation of financial statements.

● The financial statement close process did not permit timely preparation of necessary financial information and there is inadequate documentation of internal controls for some assertions in certain significant accounts.

● Lack of effective controls over general ledger processing, spreadsheets and data back-up.

These material weaknesses continued to exist during the three months ending March 31, 2012, June 30, 2012, and September 30, 2012.

We have implemented the following new internal controls during the three months ending September 30, 2012:

Remediation Activities:

● Additional controls were implemented during 2012 within the areas of internal controls over financial reporting including (but not limited to) the implementation of a new accounting system, timely management contract review and tracking, journal entry review and posting procedures, the timely and consistent reconciliation of balance sheet accounts to mitigate the risk of financial reporting inaccuracies, revenue recognition procedures, and month-over-month financial analyses to allow for trend analysis and the timely capture of coding errors. Additional controls were implemented over daily financial network and application data backups to an off-site server to ensure the safety and redundancy of shareholder data and the ability to retrieve shareholder data as needed.

● Management believes the implementation and timely testing of these controls will assist with the accuracy of the financial schedules and statements. All financial statement assertion gaps have been addressed by the implementation of these new controls.

Management conducted an evaluation of the effectiveness of our internal control over financial reporting as of September 30, 2012, based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was not effective as of September 30, 2012 and that the material weaknesses documented in the Annual Report on Form 10K/A for the year ending December 31, 2011 continue to exist but that significant effort has been made to remediate these issues and that management expects the material weaknesses will be fully remediated by December 31, 2012.

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, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

In addition to acquiring producing properties, we may also grow our business through the acquisition and development of exploratory oil and gas prospects, which is the riskiest method of establishing oil and gas reserves. In addition to acquiring producing properties, we may acquire, drill and develop exploratory oil and gas prospects that are profitable to produce. Developing exploratory oil and gas properties requires significant capital expenditures and involves a high degree of financial risk. The budgeted costs of drilling, completing, and operating exploratory wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an exploratory oil or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. We cannot assure you that our exploration, exploitation and development activities will result in profitable operations. If we are unable to successfully acquire and develop exploratory oil and gas prospects, our results of operations, financial condition and stock price may be materially adversely affected.

5

If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, wells in progress are deemed unsuccessful, or major tracts of undeveloped leases expire, or other similar adverse events occur, we may be required to write-down the carrying value of our evaluated properties.

We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling wells, completing productive wells, or plugging and abandoning non-productive wells, costs related to expired leases, or leases underlying  producing and non-producing wells, and overhead charges directly related to acquisition and exploration activities.  Under the full cost method of accounting, capitalized oil and natural gas property that comprise the full cost pool, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves.  This ceiling test is performed at least quarterly.  Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize impairment expense.  Effective with our report on Form 10-Q for the quarter ended March 31, 2012, we recognized impairment expenses in the amount of approximately $3.3 million related to impairment of the carrying value of the evaluated properties that comprised the full cost pool.  Future write-downs could occur for numerous reasons, including, but not limited to reductions in oil and gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserve estimates, or from the addition of non-productive capitalized costs to the full cost pool that do not result in corresponding increase in oil and gas reserves.  Impairments of undeveloped leases and plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full cost pool, without any corresponding increase in reserve values; as such, these situations could result in future additional impairment expenses.

Hedging transactions may limit our potential gains or result in losses. In order to manage our exposure to price risks in the marketing of our oil and natural gas, from time to time, we may enter into derivative contracts that economically hedge our oil and gas price on a portion of our production. These contracts may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: 

● there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;

● our production and/or sales of oil or 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 other party to the hedging contract defaults on its contract obligations.

Hedging transactions we may enter into may not adequately protect us from declines in the prices of oil and natural gas. Further, where we choose not to engage in hedging transactions, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

Our large inventory of undeveloped acreage and large percentage of undeveloped proved reserves may create additional economic risk.  Our success is largely dependent upon our ability to develop our large inventory of future drilling locations, undeveloped acreage and undeveloped reserves. As of December 31, 2011, approximately 47% of our total proved reserves were undeveloped.  To the extent our drilling results are not as successful as we anticipate, natural gas and oil prices decline, or sufficient funds are not available to drill these locations and reserves, we may not capture the expected or projected value of these properties. In addition, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations. Significant growth in the size and scope of our operations would place a strain on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

6

The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, the present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. This prospectus contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves contained in our filings with the SEC. The December 31, 2011, reserve estimate was prepared by our current reserve engineer consultant and audited by RE Davis. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development and operating expenses, and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control. You should also not assume that our initial rates of production of our wells will lead to greater overall production over the life of the wells, or that early results suggesting lack of reservoir continuity will prove to be accurate.

You should not assume that the present value of future net revenues referred to in this prospectus is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the un-weighted average of the closing prices during the first day of each of the twelve months preceding the end of the fiscal year. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any change in consumption by oil or natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of our oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor nor does it reflect discount factors used in the market place for the purchase and sale of oil and natural gas.

Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.   One of our growth strategies is to pursue selective acquisitions of undeveloped leasehold oil and natural gas reserves. If we choose to pursue an acquisition, we will perform a review of the target properties; however, these reviews are inherently incomplete. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties.

All of our producing properties and operations are located in the DJ Basin region, making us vulnerable to risks associated with operating in one major geographic area.  All of our estimated proved reserves at December 31, 2011, and our 2010, 2011 and 2012 sales were generated in the DJ Basin in southeastern Wyoming, northeastern Colorado and southwestern Nebraska. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the DJ Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

Unless we find new oil and gas reserves, our reserves and production will decline, which would materially and adversely affect our business, financial condition and results of operations. Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Thus, our future oil and gas reserves and production and, therefore, our cash flow and revenue are highly dependent on our success in efficiently obtaining reserves and acquiring additional recoverable reserves. We may not be able to develop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would be materially and adversely affected.

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Part of our strategy involves drilling in existing or emerging unconventional shale plays using available horizontal drilling and completion techniques. The results of our planned exploratory and development drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.  Unconventionaloperations involve utilizing drilling and completion techniques as developed by ourselves and our service providers. Risks that we face while drilling include, but are not limited to, landing our wellbore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the wellbore and being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the wellbore during completion operations and successfully cleaning out the wellbore after completion of the final fracture stimulation stage.

Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Niobrara is limited. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and the value of our undeveloped acreage could decline in the future.

The unavailability or high cost of drilling rigs, equipment supplies or personnel could adversely affect our ability to execute our exploration and development plans. The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. The higher prices of oil and gas during the last several years have resulted in shortages of drilling rigs, equipment and personnel, which have resulted in increased costs and shortages of equipment in the areas where we operate. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our financial condition and results of operations could be materially and adversely affected.

Covenants in our credit agreements impose significant restrictions and requirements on us. Our three credit agreements contain a number of covenants imposing significant restrictions on us, including restrictions on our repurchase of, and payment of dividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets and create liens on our assets. These restrictions may affect our ability to operate our business, to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial conditions and results of operations.

We could be required to pay liquidated damages to some of our investors if we fail to maintain the effectiveness of a prior registration statement. We could default and accrue liquidated damages under registration rights agreements covering approximately 3.2 million shares of our common stock if we fail to maintain the effectiveness of a prior registration statement as required in the agreements. In such case, we would be required to pay monthly liquidated damages of up to $228,050. The maximum aggregate liquidated damages are capped at $1,368,300. If we do not make a monthly payment within seven days after the date payable, we are required to pay interest at an annual rate of 18% on the unpaid amount. If we default under the registration rights agreement and accrue liquidated damages, we could be required to either raise additional outside funds through financing or curtail or cease operations.

We are exposed to operating hazards and uninsured risks. Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

● fire, explosions and blowouts;

● pipe failure;

● abnormally pressured formations; and

● environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).

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These events may result in substantial losses to us from: 

● injury or loss of life;

● severe damage to or destruction of property, natural resources and equipment;

● pollution or other environmental damage;

● clean-up responsibilities;

● regulatory investigation;

● penalties and suspension of operations; or

● attorney's fees and other expenses incurred in the prosecution or defense of litigation.

We maintain insurance against some, but not all, of these risks. We cannot assure you that our insurance will be adequate to cover these losses or liabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations.

The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions and weather conditions. These curtailments can last from a few days to many months.

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult. We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

● recoverable reserves;

● future oil and natural gas prices and their appropriate differentials;

● development and operating costs; and

● potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.

Significant acquisitions and other strategic transactions may involve other risks, including:

● diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

● challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

● difficulty associated with coordinating geographically separate organizations;

● challenge of attracting and retaining personnel associated with acquired operations; and

● failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

Prospects that we decide in which to participate may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return. A prospect is a property in which we own an interest and have what we believe, based on available seismic and geological information, to be indications of oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion cost or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analysis we perform using data from other wells, more fully explored prospects or producing fields will be useful in predicting the characteristics and potential reserves associated with our drilling prospects.

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Our reserve estimates will depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of reserves shown in these reports.

In order to prepare reserve estimates in its reports, our independent petroleum consultant projected production rates and timing of development expenditures. Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary and may not be in our control. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Risks relating to the oil and gas industry

Oil and natural gas prices are highly volatile, and our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following: 

● 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;

● the price and availability of alternative fuels; and

● market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives.

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

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Our industry is highly competitive which may adversely affect our performance, including our ability to participate in ready to drill prospects in our core areas. We operate in a highly competitive environment. In addition to capital, the principal resources necessary for the exploration and production of oil and natural gas are: 

● leasehold prospects under which oil and natural gas reserves may be discovered;

● drilling rigs and related equipment to explore for such reserves; and

● knowledgeable personnel to conduct all phases of oil and natural gas operations.

We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these competitors have financial and other resources substantially greater than ours. We cannot assure you that such materials and resources will be available when needed. If we are unable to access material and resources when needed, we risk suffering a number of adverse consequences, including:

● the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests;

● loss of reputation in the oil and gas community;

● a general slowdown in our operations and decline in revenue; and

● decline in market price of our common shares.

Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.  In December 2009, the Environment Protection Agency (“EPA”) determined that emissions of carbon dioxide, methane and other ‘‘greenhouse gases’’ present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act, or CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011.  The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs, and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Under the proposed legislation, this information would be available to the public via the internet, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.  At the state level, some states have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

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In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business. Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, and operating safety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may result in substantial penalties and harm to our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as: 

● land use restrictions;

● lease permit restrictions;

● drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds;

● spacing of wells;

● unitization and pooling of properties;

● safety precautions;

● operational reporting; and

● taxation.

Under these laws and regulations, we could be liable for:

● personal injuries;

● property and natural resource damages;

● well reclamation cost; and

● governmental sanctions, such as fines and penalties.

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is also possible that a portion of our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See “Business and Properties—Government Regulations” for a more detailed description of our regulatory risks.

Our operations may incur substantial expenses and resulting liabilities from compliance with environmental laws and regulations. Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations: 

● require the acquisition of a permit before drilling commences;

● restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, including new environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells;

● limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

● impose substantial liabilities for pollution resulting from our operations.

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Failure to comply with these laws and regulations may result in:

● the assessment of administrative, civil and criminal penalties;

● incurrence of investigatory or remedial obligations; and

● the imposition of injunctive relief.

Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Our permits require that we report any incidents that cause or could cause environmental damages. See “Business and Properties—Government Regulations” for a more detailed description of our environmental risks.

Risks Relating to Our Common Stock

There is a limited public market for our shares and we cannot assure you that an active trading market or a specific share price will be established or maintained.

Our common stock trades on the Nasdaq Global Market, generally in small volumes each day.  The value of our common stock could be affected by:

● actual or anticipated variations in our operating results;

● changes in the market valuations of other oil and gas companies;

● announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;

● adoption of new accounting standards affecting our industry;

● additions or departures of key personnel;

● sales of our common stock or other securities in the open market;

● actions taken by our lenders or the holders of our convertible debentures;

● changes in financial estimates by securities analysts;

● conditions or trends in the market in which we operate;

● changes in earnings estimates and recommendations by financial analysts;

● our failure to meet financial analysts’ performance expectations; and

● other events or factors, many of which are beyond our control.

In a volatile market, you may experience wide fluctuations in the market price of our securities. These fluctuations may have an extremely negative effect on the market price of our common stock and may prevent you from obtaining a market price equal to your purchase price when you attempt to sell our common stock in the open market. In these situations, you may be required either to sell at a market price which is lower than your purchase price, or to hold our common stock for a longer period of time than you planned. An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or oil and gas properties by using common stock as consideration.

Securities analysts may not initiate coverage of our shares or may issue negative reports, which may adversely affect the trading price of the shares.

We cannot assure you that securities analysts will cover our company. If securities analysts do not cover our company, this lack of coverage may adversely affect the trading price of our shares. The trading market for our shares will rely in part on the research and reports that securities analysts publish about us and our business. If one or more of the analysts who cover our company downgrades our shares, the trading price of our shares may decline. If one or more of these analysts ceases to cover our company, we could lose visibility in the market, which, in turn, could also cause the trading price of our shares to decline. Further, because of our small market capitalization, it may be difficult for us to attract securities analysts to cover our company, which could significantly and adversely affect the trading price of our shares.

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USE OF PROCEEDS

We will not receive any proceeds from the sale or issuance of the shares of common stock offered by this prospectus.  

SELLING STOCKHOLDERS

The persons listed in the following table plan to offer the shares shown opposite their respective names by means of this prospectus. The selling stockholders acquired their shares in the transactions described below.

Name of Selling Stockholder	Shares Owned	Shares to be Sold in This Offering	Share Ownership After Offering
EZ Colony Partners, LLC	230,348	6,222	224,126
Wallington Investment Holdings Ltd	1,733,432	12,665	1,720,767
Jonathan & Nancy Glaser Family Trust UTD 12/16/1998 Jonathan M. & Nancy E. Glaser TTEES	141,327	1,685	139,642
G. Tyler Runnels & Jasmine Niklas Runnels Ttee The Runnels Family Trust Dtd 1/11/00	680,660	2,985	677,675
Elevado Investment Company, LLC	46,860	2,193	44,667
EMSE, LLC	2,668	2,193	475
Ezralow Family Trust u/t/d 12/9/1980	1,445	970	475
Ezralow Marital Trust u/t/d 1/12/2002	1,394	1,183	211

PLAN OF DISTRIBUTION

1,176,483 shares of common stock that may be offered by us to the holders of an aggregate principal amount of $5,000,000 of our 8% Senior Secured Debentures due February 8, 2014 (the “Debentures”) in the event of conversion of the Debentures (at a conversion price of $4.25 per share). These shares are not being offered to the public.

423,517 shares of common stock that may be offered by us to holders of the Debentures as interest payments in connection with the Debentures (at a conversion price equal to the fair market value of such shares on the date of the interest payment). These shares are not being offered to the public.

30,096 of the shares offered pursuant to this prospectus may be offered for resale by selling stockholders. Each selling stockholder of the shares and any of their pledgees, assignees and successors-in-interest may, from time to time, sell any or all of their shares covered hereby on the NASDAQ Global Market or any other stock exchange, market or trading facility on which our common stock is traded or in private transactions. These sales may be at fixed or negotiated prices. A selling stockholder may use any one or more of the following methods when selling shares:

● ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

● block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

● purchases by a broker-dealer as principal and resale by the broker-dealer for its account;

● an exchange distribution in accordance with the rules of the applicable exchange;

● privately negotiated transactions;

● settlement of short sales entered into after the effective date of the registration statement of which this prospectus is a part;

● in transactions through broker-dealers that agree with the selling stockholders to sell a specified number of such shares at a stipulated price per share;

● through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise;

● a combination of any such methods of sale; or

● any other method permitted pursuant to applicable law.

The selling stockholders may also sell shares under Rule 144 under the Securities Act of 1933, if available, rather than under this prospectus.

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Broker-dealers engaged by the selling stockholders may arrange for other brokers-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the selling stockholders (or, if any broker-dealer acts as agent for the purchaser of shares, from the purchaser) in amounts to be negotiated, but, except as set forth in a supplement to this prospectus, in the case of an agency transaction not in excess of a customary brokerage commission in compliance with FINRA Rule 2440; and in the case of a principal transaction a markup or markdown in compliance with FINRA IM-2440.

In connection with the sale of the shares or interests therein, the selling stockholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of the shares in the course of hedging the positions they assume. The selling stockholders may also sell shares short and deliver these shares to close out their short positions, or loan or pledge the shares to broker-dealers that in turn may sell these shares. The selling stockholders may also enter into option or other transactions with broker-dealers or other financial institutions or create one or more derivative securities which require the delivery to such broker-dealer or other financial institution of shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).

DESCRIPTION OF COMMON STOCK

The following description of our common stock is derived from our articles of incorporation and bylaws as well as relevant provisions of applicable law.  Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.0001 per share, and 10,000,000 shares of preferred stock, par value $0.0001 per share.

Except as otherwise required by law or provided in any designation of rights of preferred stock, the holders of our common stock are entitled to one vote per share on all matters submitted to a vote of the stockholders, including the election of directors.  Generally, all matters to be voted on by stockholders must be approved by a majority (or, in the case of election of directors, by a plurality) of the votes entitled to be cast by all shares of common stock that are present in person or represented by proxy, subject to any voting rights granted to holders of preferred stock.  Except as otherwise provided by law, and subject to any voting rights granted holders of preferred stock, amendments to our articles of incorporation generally must be approved by a majority of the votes entitled to be cast by all outstanding shares of common stock.  Our articles of incorporation and bylaws do not provide for cumulative voting in the election of directors.

BUSINESS AND PROPERTIES

Industry terms used in this prospectus are defined in the Glossary of Oil and Natural Gas Terms located at the end of this section.

General

Recovery Energy, Inc. (NASDAQ: RECV), sometimes referred to in this prospectus as “we,” “us,” “our,” “Recovery Energy,” “Recovery,” or the “Company” is a Denver based independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. Our current activities are focused on the Denver-Julesburg (“DJ”) Basin in Colorado, Wyoming and Nebraska. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team and via the future exploration and development of the approximate 125,000 net acres of developed and undeveloped leases that are currently held by the Company, primarily in the northern DJ Basin.

Our executive offices are located at 1900 Grant Street, Suite #720, Denver, CO 80203, and our telephone number is (303) 951-7920.  Our web site is www.recoveryenergyco.com.  Additional information which may be obtained through our web site does not constitute part of this prospectus.  Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are accessible free of charge at our website.  The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings at www.sec.gov.

Company Overview & Strategy

We have developed and acquired an oil and natural gas base of proved reserves, as well as a portfolio of exploration and development prospects with  conventional and non-conventional reservoir opportunities with an emphasis on multiple producing horizons and the Niobrara, Codell and Greenhorn shale resource plays. We believe these prospects offer the possibility of 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 early 2010 we have acquired and/or developed 29 producing wells. As of December 31, 2012 we owned interests in approximately 140,000 gross (125,000 net) leasehold acres, of which 118,000 gross (103,000 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, Codell and Greenhorn shale potential.

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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.

As of December 31, 2009, we had not successfully acquired any properties; therefore our total production was 0 Mboe net. Subsequent to December 31, 2009, we successfully completed a number of acquisitions which resulted in 136 Mboe of production for the year ended December 31, 2010.  In 2011, we drilled and completed 6 gross (5 net) wells and recorded net production of 101 Mboe during the year. During the year ended December 31, 2012, we drilled 6 gross (4 net) wells and recorded net production of 95 Mboe during the year.

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 basin. We pursue prospects in one known producing onshore basin, the DJ Basin, 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 seek to 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.  

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 own interest in 140,000 gross, 125,000 net developed and undeveloped acres in DJ basin leases, and will require access to substantial capital in order to fully assess and develop our inventory of undeveloped acreage.

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Principal Oil and Gas Interests

As of December 31, 2011 we owned 21  producing wells, 7 shut-in wells, 2 injection wells, and 2 wells in progress in the Wyoming, Nebraska and Colorado portions of the DJ Basin, as well as approximately 144,000 gross (130,000 net) acres, of which 134,000 gross (121,000 net) acres are classified as undeveloped acreage. As of December 31, 2012, we owned interests in approximately 140,000 gross (125,000 net) leasehold acres, of which 118,000 gross (103,000 net) acres are classified as undeveloped acreage.   Our primary targets within the DJ Basin are the conventional Dakota and Muddy ‘J’ formations, in addition to the developing unconventional Niobrara shale play.  Additional horizons include the Coddell, Greenhorn and Pierre Shale.    

During 2011, we made capital expenditures of approximately $16.4 million, including $9.4 million for the purchase of undeveloped leases and $7.4 million related  to drilling and completion operations where we drilled 4 gross (3.25 net) wells and completed 3 gross (2.25 net) wells; also, as of December 31, 2011 we had 2 gross (1.75 net) wells in progress.  As of December 31, 2012, we have 1 gross (1 net) well in progress.

During 2012, we made capital expenditures of approximately $3.27 million, including $0.50 million for the purchase of undeveloped leases, $4.28 million related to drilling and completion operations where we drilled and completed 6 gross (4 net) wells. We sold undeveloped property for $1.4 million and leased undeveloped property for $1.5 million.

As of December 31, 2011 we had net proved reserves of 633 Mboe, and for the year ending December 31, 2011 we produced 101 Mboe. During the year ended December 31, 2012, we produced 95 Mboe. 

2013 Capital Budget

Our 2013 Capital Budget is currently projected to be approximately $15 million, but is subject to securing sufficient capital to support planned drilling and development expenses.  We anticipate that approximately 50% of this budget will be allocated toward the development of two of our unconventional prospects located in the Wattenburg field of the DJ Basin that will target horizontal drilling and development of the Niobrara shale and Codell formations.  The remainder of our 2013 budget is anticipated to be directed principally toward the conventional development of certain lower risk offset wells to existing production.  We also anticipate the allocation of approximately 10% of our 2013 capital budget toward higher risk exploration activities, including the procurement of seismic data and the drilling of one conventional exploratory well.

Our 2013 capital expenditure budget is subject to various factors, including availability of capital, market conditions, oilfield services and equipment availability, commodity prices and drilling results.  Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget as the cash flow from the wells could provide additional capital which we may use to increase our capital budget. We do not anticipate any significant expansion of our current DJ Basin acreage position.

Other factors that could cause us to further increase our level of activity and adjust our capital expenditure budget include a reduction in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, a further improvement in commodity prices or well performance that exceeds our forecasts, any of which could positively impact our operating cash flow. Factors that could cause us to reduce level of activity and adjust our capital budget include, but are not limited to, increases in service and materials costs, reductions in commodity prices or under-performance of wells relative to our forecasts, any of which could negatively impact our operating cash flow.

Capital Resources

Our 2013 capital program is subject to securing sufficient capital, principally via the issuance of additional equity and debt.   We may also secure additional capital by pursuing sales of certain assets that are considered non-strategic.  We may also seek to finance certain projects via joint venture agreements or other arrangements with strategic or industry partners.

We cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings, equity offerings or other financings, or sales of non-strategic assets will be sufficient to fund our anticipated 2013 capital expenditures.

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Reserves

The table below presents summary information with respect to the estimates of our proved oil and gas reserves for the year ended December 31, 2011.  Prior to January 2010, we did not own any reserves nor did we have any production.  We engaged Ralph E Davis Associates, Inc. (“RE Davis”) to audit internal engineering estimates for 100 percent of the PV-10 value of our proved reserves in 2011.  The prices used in the calculation of proved reserve estimates as of December 31, 2011 were $88.16 per Bbl and $3.96 per Mcf and as of December 31, 2010, were $78.93 per Bbl and $4.39 per Mcf for oil and natural gas, respectively.  The prices were adjusted for basis differentials, pipeline adjustments, and BTU content.

We emphasize that reserve estimates are inherently imprecise and that estimates of all new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties.  Accordingly, these estimates are expected to change as new information becomes available.  The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by us.  Neither prices nor costs have been escalated.  The following table should be read along with the section entitled “Risk Factors — Risks Related to Our Company — The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated.”  No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the Securities and Exchange Commission ("SEC"), since the beginning of the last fiscal year. We did not have third party engineers review probable, possible and resource based reserves as of December 31, 2011.  These reserve categories are currently being determined across our substantial acreage position and are expected to identify significant potential in all unproven classifications and from multiple horizons.

	As of December 31,
	2011			2010 (1)			2009 (1)
Reserve data:
Proved developed
Oil (MBbl)		216			278			-
Gas (MMcf)		148			308			-
MBOE		240			329			-
Proved undeveloped
Oil (MBbl)		392			415			-
Gas (MMcf)					-			-
MBOE		392			415			-
Total Proved
Oil (MBbl)		608			693			-
Gas (MMcf)		148			308			-
MBOE		633			744			-
Proved developed reserves %		38	%		44	%		-
Proved undeveloped reserves %		62	%		56	%		-
Reserve value data :
Proved developed PV-10	$	10,204,160		$	11,377,009		$	-
Proved undeveloped PV-10		9,809,885			12,217,798			-
Total proved PV-10	$	20,014,045		$	23,594,807		$	-
Standardized measure of discounted future cash flows	$	20,014,045		$	23,594,807		$	-
Reserve life (years)		22.58			21.92			-

(1) Prior to January 2010, the Company did not own any oil and gas properties

As we currently do not expect to pay income taxes in the future, there is no difference between the PV-10 value and the standard measure of future net cash flows.  Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the Glossary.

Internal Controls Over Reserves Estimate

Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserve quantities and values in compliance with the regulations of the SEC. Responsibility for compliance in reserve bookings is delegated to our President with assistance from our Principal Accounting Officer and certain retained  consultants.

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Technical reviews are performed throughout the year by engineering consultants and geologic staff who evaluate all available geological and engineering data.  This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserve quantities.  The 2011 reserve process was overseen by Kent Lina, then our Senior Reserve Engineer. Mr. Lina joined us in October 2010, and prior to that was employed by Delta Petroleum Company from March 2002 to September 2010 in various operations and reservoir engineering capacities culminating as the Senior V.P. of Corporate Engineering. Mr. Lina received a Bachelor of Science degree in Civil Engineering from University of Missouri at Rolla in 1981. Mr. Lina left the Company in December 2012, and continues to serve the Company in a consulting capacity.

Third-party Reserves Study

An independent third party reserve study as of December 31, 2011 was performed by RE Davis using their own engineering assumptions and other economic data provided by us.  One-hundred percent of our total calculated proved reserve PV-10 value was audited by RE Davis.  RE Davis is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services for over 20 years.  The technical person at RE Davis primarily responsible for overseeing our reserve audit is Allen C. Barron, the President and CEO, who received a Bachelor of Science degree in Chemical and Petroleum Engineering from the University of Houston and is a registered Professional Engineer in the States of Texas.  He is also a member of the Society of Petroleum Engineers.  The RE Davis report dated March 5, 2012 was filed as Exhibit 99.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

Oil and gas reserves and the estimates of the present value of future net revenues therefrom were determined based on prices and costs as prescribed by SEC and FASB guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods.  Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. For the year ended December 31, 2011, commodity prices over the prior 12-month period and year end costs were used in estimating net cash flows.

In addition to a third party reserve study, our reserves are reviewed by senior management and the audit committee of our board of directors.  Our chief executive officer is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate.  The audit committee reviews the final reserves estimate in conjunction with RE Davis’s audit letter. 

Production

The following table summarizes the average volumes and realized prices, including and excluding the effects of our economic hedges, of oil and gas produced from properties in which we held an interest during the periods indicated.  Also presented is a production cost per BOE summary: 

	For the Year Ended December 31,
Net production	2012		2011		2010
Oil (MMBbl)		81,999		81,433		133.709
Gas (MMcf)		76,265		115,583		14.914
MBOE		94,710		100,707		136.195
Average net daily production
Oil (Bbl)		225		223		366
Gas (Mcf)		209		317		41
BOE		260		275		373
Average realized sales price, excluding the effects of our economic hedges
Oil (per Bbl)	$	85.38	$	87.77	$	71.08
Gas (per Mcf)	$	5.27	$	4.73	$	4.56
Per BOE	$	69.79	$	76.41	$	70.29
Average realized sales price, including the effects of our economic hedges
Oil (per Bbl)	$	94.833	$	95.44	$	75.27
Gas (per Mcf)	$	5.27	$	4.73	$	4.56
Per BOE	$	77.24	$	82.62	$	74.47
Production costs per BOE
Lease operating expense	$	14.58	$	15.19	$	6.33
DD&A	$	40.88	$	42.25	$	36.98
Production taxes	$	7.92	$	8.18	$	7.76

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Productive Wells

As of December 31, 2012, we had working interests in 29 gross (26 net) productive oil wells, and 1 gross (1 net) productive gas well. Productive wells are either wells producing in commercial quantities or wells capable of commercial production although currently shut-in.  Multiple completions in the same wellbore are counted as one well.  A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.

Acreage

As of December 31, 2012 we owned 29  producing wells in the Wyoming, Nebraska and Colorado portion of the DJ Basin, as well as approximately 140,000 gross (125,000 net) acres, of which 118,000 gross (103,000 net) acres were classified as undeveloped acreage.

As of December 31, 2012 our primary assets included acreage located in Laramie County and Goshen counties in Wyoming, Banner, Kimball, and Scotts Bluff Counties in Nebraska, and Weld, Arapahoe and Elbert Counties in Colorado.  

The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 2012.

	Undeveloped				Developed
	Gross		Net		Gross		Net
DJ Basin		118,200		103,200		21,800		21,800
Total		118,200		103,200		21,800		21,800

Drilling Activity

The following table describes the development and exploratory wells we drilled during the years ended December 31, 2012, 2011, and 2010.

	For the Year Ended December 31,
	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Development:						-		-		-		-
Productive wells		5		3		3.0		2.25		2.0		1.4
Dry wells		1		1		1.0		1.0		1.0		0.7
		6		4		4.0		3.25		3.0		2.1
Exploratory:
Productive wells		-		-		-		-		-		-
Dry wells		-		-		-		-		-		-
		-		-		-		-		-		-
Total		6		4		4.0		3.25		3.0		2.1

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A productive well is an exploratory, development or extension well that is not a dry well.  A dry well (hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

As defined in the rules and regulations of the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.  A development well is part of a development project, which is defined as the means by which petroleum resources are brought to the status of economically producible.  The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated.  Completion refers to the installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to the reporting to the appropriate authority that the well has been abandoned.

As of December 31, 2012 we had 1 gross (1 net) well in progress.

Major Customers

During 2012, 2011 and 2010, the Company had one customer, Shell Trading (US), individually accounting for approximately 72 percent, 76 percent and 64 percent, respectively, of our revenues. 

Employees

As of December 31, 2012 we had 7 full-time employees and no part-time employees. For the foreseeable future, we intend to only add additional personnel as our operational requirements grow. In the interim, we plan to continue to use the services of independent consultants and contractors to perform various professional services, including land, legal, environmental and tax services. We believe that by limiting our management and employee costs, we are able to better control total costs and retain flexibility in terms of project management.

Title to Properties

Substantially all of our interests are held pursuant to leases from third parties.  The majority of our producing properties are subject to mortgages securing indebtedness under our credit facility that we believe do not materially interfere with the use of or affect the value of such properties.  We typically perform only minimal title investigation before acquiring undeveloped leasehold acreage.

Seasonality

Generally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer.  However, increased summertime demand for electricity has placed increased demand on storage volumes.  Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season — although oil prices are much more driven by global supply and demand.  Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.  The impact of seasonality on crude oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of production capacity in excess of existing worldwide demand for crude oil.

Competition

The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties.  We believe our leasehold position provides a sound foundation for a solid drilling program and our future growth.  Our competitive position also depends on our geological, geophysical, and engineering expertise, and our financial resources.  We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete effectively in our core operating areas.  However, we face intense competition from a substantial number of major and independent oil and gas companies, which, in some cases, have larger technical staffs and greater financial and operational resources than we do.  Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, and generate electricity.

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We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells.  Consequently, we may face shortages or delays in securing these services from time to time.  The oil and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas.  Competitive conditions may also be affected by future new energy, climate-related, financial, and other policies, legislation, and regulations.

In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals and consultants.  Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the number of talented people available is constrained.  We are not insulated from this resource constraint, and we must compete effectively in this market in order to be successful.

Recent Developments

In February 2011, we issued in a private placement $8.4 million aggregate principal amount of 8% Senior Secured Convertible Debentures due February 8, 2014 (the “Debentures”) to a group of accredited investors.  In March 2012, some investors in the original convertible debenture offering agreed to purchase up to $5.0 million of additional convertible debentures (the “Supplemental Debentures”).  The additional capital   provided by the Supplemental Debentures has been used to partially fund the 2012 Capital Budget, and specifically for the drilling and development of certain proven undeveloped and other properties held by the Company, and for general corporate purposes.  The initial funding under the March 2012 agreement occurred in March and continued through July 2012 in the amount of $3.04 million.  These proceeds were used to fund the drilling and development of six new wells, resulting in a total investment of $3.69 million.  Five of these wells resulted in commercial production, and one well was plugged and abandoned.

In December 2011, we sold 2,840 net undeveloped acres in Weld County, Colorado to a third party.  The sale included one marginally producing oil well in which the Company owned a 25% net working interest. The purchase price was approximately $4.5 million (approximately $1,600 per net acre).

In February 2012, we completed the sale of our Grover Prospect acreage, under which we agreed to sell all of our oil and gas leases in the Grover Field in Weld County, Colorado to Bill Barrett Corporation for approximately $4,540,800.

In March 2012, Hexagon agreed to extend the maturity of its term loans to June 30, 2013, and in connection therewith, we agreed to make minimum monthly loan payments of $0.33 million, effective immediately. In July 2012, Hexagon agreed to extend the maturity of its term loans to September 30, 2013. In November 2012, Hexagon extended the maturity date to December 31, 2013.

In April, 2012, we made the decision to temporarily abandon one of our unconventional Niobrara wells that was categorized as a well in progress as of December 31, 2011.  In conjunction with that decision, all capitalized drilling, completion and allocable lease costs related to this well in the amount of $4.8 million were transferred to developed properties.  This transfer of costs contributed to a $3.27 impairment charge of developed properties derived from the ceiling test completed as of March 31, 2012.

In August 2012, the Company restructured the terms of the Supplemental Debenture offering and concluded the offering by issuing an additional $1.96 million of convertible debentures.  On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures.

On November 5, 2012, the Company liquidated all of its price derivatives (commodity hedges) for proceeds of $0.60 million.

On November 15, 2012, Roger A. Parker retired as our chief executive officer and resigned from our board of directors. On the same day our board of directors appointed W. Phillip Marcum as chief executive officer and chairman and A. Bradley Gabbard as president in addition to his role as chief financial officer.

In December 2012, the Company leased certain deep rights to 6,300 undeveloped acres to a private company for proceeds of approximately $1.50 million.

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Marketing and Pricing

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

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

● changes in global supply and demand for oil and natural gas;

● the actions of the Organization of Petroleum Exporting Countries, or OPEC;

● the price and quantity of imports of foreign oil and natural gas;

● acts of war or terrorism;

● political conditions and events, including embargoes, affecting oil-producing activity;

● the level of global oil and natural gas exploration and production activity;

● the level of global oil and natural gas inventories;

● weather conditions;

● technological advances affecting energy consumption; and

● the price and availability of alternative fuels.

From time to time, we enter into derivative contracts. These contracts economically hedge 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 counterparty to the hedging contract defaults on its contract obligations.

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

Government Regulations

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

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

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Environmental, Health, and Safety Regulations. Our operations are subject to stringent federal, state, and local laws and regulations relating to the protection of the environment and human health and safety.  Environmental laws and regulations may require that permits be obtained before drilling commences, restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities, govern the handling and disposal of waste material, and limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, including areas containing endangered animal species.  As a result, these laws and regulations may substantially increase the costs of exploring for, developing, or producing oil and gas and may prevent or delay the commencement or continuation of certain projects.  In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligations in the event of any discharges or emissions in violation of these laws and regulations.  Further, legislative and regulatory initiatives related to global warming or climate change could have an adverse effect on our operations and the demand for oil and natural gas.  See “Risk Factors — Risks Related to Oil and Gas Industry — Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.”

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations.  For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors— Risks Related to Our Company.”   Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and gas wells.

Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, or produced in our operations.  Some of this information must be provided to our employees, state and local governmental authorities, and local citizens.  We are also subject to the requirements and reporting framework set forth in the federal workplace standards.

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

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

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

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

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

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

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

The Clean Air Act of 1963 and subsequent extensions and amendments, known collectively as the Clean Air Act, and state air pollution laws adopted to fulfill its mandate provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.  Over the next several years, we may be required to incur capital expenditures for air pollution control equipment or other air emissions-related issues. For example, on July 28, 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production, including, among other things, the application of reduced emission completion techniques, referred to as “green completions,” for completion of newly drilled and fractured wells in addition to establishing specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. Final action on the proposed rules is expected no later than April 3, 2012. If this action is finalized, we do not believe that such requirements will have a material adverse effect on our operations.

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

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

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

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

Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management, or BLM.  These leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change.  In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met.  Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated.

In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process.  These changes may increase the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM.

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

To date we have not experienced any materially adverse effect on our operations from obligations under environmental, health, and safety laws and regulations.  We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and that continued compliance with existing requirements would not have a materially adverse impact on us.

Glossary of Oil and Natural Gas Terms

The following is a description of the meanings of some of the oil and natural gas industry terms used in this prospectus.

bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in reference to crude oil or other liquid hydrocarbons.

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Bcf. Billion cubic feet of natural gas.

boe. Barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

boe/d. boe per day.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Drilling locations. Total gross locations specifically quantified by management to be included in our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. An identifiable layer of rocks named after its geographical location and dominant rock type.

Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.

Leasehold. Mineral rights leased in a certain area to form a project area.

Mbbls. Thousand barrels of crude oil or other liquid hydrocarbons.

Mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

Mcf. Thousand cubic feet of natural gas.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

MMbbls. Million barrels of crude oil or other liquid hydrocarbons.

MMboe. Million barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

MMbtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

Net acres, net wells, or net reserves. The sum of the fractional working interest owned in gross acres, gross wells, or gross reserves, as the case may be.

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Net barrel of production. The sum of the fractional revenue interest in gross production owned by the company.

ngl. Natural gas liquids, or liquid hydrocarbons found in association with natural gas.

Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lesser or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues (PV-10). The present value of estimated future revenues to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using the simple 12 month first of month average price and current costs (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of Recovery Energy on a comparative basis to other companies and from period to period.

Production. Natural resources, such as oil or gas, taken out of the ground.

Proved reserves. The quantities of oil, natural gas and natural gas liquids, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs under existing economic conditions and operating conditions.

Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. 

Probable Reserves. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P estimate.

Possible Reserves. Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10-percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

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Productive well. A well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Project. A targeted development area where it is probable that commercial gas can be produced from new wells.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Recompletion. The process of re-entering an existing well bore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reserves. Oil, natural gas and gas liquids thought to be accumulated in known reservoirs.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible nature gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.

Shut-in. A well that has been capped (having the valves locked shut) for an undetermined amount of time. This could be for additional testing, could be to wait for pipeline or processing facility, or a number of other reasons.

Standardized measure. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Successful. A well is determined to be successful if it is producing oil or natural gas, or awaiting hookup, but not abandoned or plugged.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Water flood. A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

LEGAL PROCEEDINGS

Parker v. Tracinda Corporation, Denver District Court, Case No. 2011-CV-561.  In November 2012, the Company filed a motion to intervene in garnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman.  The Defendant has served various writs of garnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested, restricted stock.  The Company has asserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company.  At this stage of the proceedings, we cannot express an opinion as to the probable outcome.

There are no other material pending legal proceedings to which we or our properties are subject.

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MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Recent Market Prices

On November 2, 2011 our common stock began trading on the Nasdaq Global Market under the symbol "RECV."  Between September 25, 2009 and November 1, 2011 our stock traded on the OTC Bulletin Board under the symbol "RECV.OB."

The following table shows the high and low reported sales prices of our common stock for the periods indicated.  Effective October 19, 2011 we completed a 1:4 reverse stock split, and stock prices prior to such date have been adjusted to reflect the effect of the stock split.

	High		Low
2012
Fourth Quarter	$	4.95		$	1.40
Third Quarter	$	4.75		$	1.64
Second Quarter	$	3.99		$	2.25
First Quarter	$	4.90		$	2.31
2011
Fourth Quarter	$	7.00		$	2.99
Third Quarter	$	11.00		$	4.88
Second Quarter	$	13.00		$	8.80
First Quarter	$	15.56		$	7.80
2010
Fourth Quarter	$	10.00		$	7.24
Third Quarter	$	10.00		$	6.00
Second Quarter	$	16.00		$	1.00
First Quarter	$	22.00		$	8.20

On January 18, 2013, there were approximately 30 owners of record of our common stock.

Dividend Policy

We have never paid any cash dividends on our common stock and do not anticipate paying any dividends in the foreseeable future. Our current business plan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at the discretion of our board of directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as our board may deem relevant at that time.

Equity Compensation Plan Information

The following table sets forth certain information regarding shares of our common stock issuable upon the exercise of options granted under our 2012 Equity Incentive Plan (the “Plan”) as of December 31, 2012.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance  under equity compensation plans
Equity compensation plans approved by security holders		0	$	—		479,167	(1)
Equity compensation plans not approved by security holders		—		—		—
Total		0	$	—		479,167

(1) Awards under our 2012 Equity Incentive Plan may be made in the form of stock options, stock appreciation rights, restricted stock, restricted stock units or other securities that are valued in whole or in part by reference to, or are otherwise based upon, the Company’s common stock, including without limitation dividend equivalents, phantom stock, phantom stock units and performance units. This balance accounts for 420,833 shares of restricted stock issued and outstanding under the Plan, but does not account for the stock options anticipated to be issued in connection with the employment agreements to be entered into with Messrs. Marcum and Gabbard as discussed below, under “Executive Compensation”.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with our financial statements included elsewhere in this prospectus. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors including those set forth in our “Risk Factors” described herein.

General

We are an 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 shareholder value by developing our undeveloped properties and leveraging the knowledge, expertise and experience of our management team.

We principally target low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Colorado, Nebraska, and Wyoming.  

Results of Operations

Nine Months Ended September 30, 2012 compared to the Nine Months Ended September 30, 2011.

The Company reported a net loss for the nine months ended September 30, 2012 of approximately $12.78 million compared to a net loss of approximately $11.53 million for the nine months ended September 30, 2011.

	Nine months ended September 30,
	2012			2011
Revenues and other income:
Oil sales	$	4,685,713		$	5,534,325
Gas sales		397,298			446,386
Realized gain on commodity hedges		49,729			402,256
Unrealized gain on commodity price derivatives		445,609			222,788
Other		132,367			110,282
Total revenues and other income		5,710,711			6,716,037
Expenses:
Production costs		1,033,635			1,114,220
Production taxes		561,278			630,718
General and administrative		5,099,932			8,837,802
Depreciation, depletion and amortization		2,897,156			3,194,301
Impairment of evaluated properties		3,274,718			-
Total expenses		12,866,719			13,777,041
Loss from continuing operations		(7,156,009	)		(7,061,004	)
Interest expense		(6,320,919	)		(6,123,496	)
Other		(372	)		63,115
Conversion note derivative gain		700,000			1,587,699
Net loss	$	(12,777,299	)	$	(11,533,686	)

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Oil and Gas Revenues and Production

Oil and gas revenues were $5.08 million for the nine months ended September 30, 2012, as compared to $5.98 million for the nine months ended September 30, 2011, a decrease of $0.90 million, or 15%. Our production volume on a BOE basis was 80,005 for the nine months ended September 30, 2012, as compared to 101,251 for the nine months ended September 30, 2011 a decrease of 21,246 BOE, or 21%. This decrease is primarily attributable to normal decline curves related to mature properties, but partially offset by production attributable to wells drilled during the nine months ended September 30, 2012.  Production declines were also partially offset by slightly higher average prices for both oil and natural gas.

Production and average prices for the nine months ended September 30, 2012 are presented in the following table:

	Nine Months Ended
	September 30,
	2012		2011
Product:
Oil (Bbls)-volume		52,658		63,114
Oil (Bbls)-average price (1)	$	88.98	$	87.69
Natural gas (Mcf)-volume		63,746		88,229
NGL’s-(BOE)		16,723		23,433
Natural gas (Mcf)-average price (2)	$	6.23	$	5.06
Barrels of oil equivalent (BOE)		80,005		101,251
Average daily net production (BOE)		291		370

(1)	Does not include the realized price effects of hedges
(2)	Includes proceeds from the sale of NGL’s.

Oil and gas production expenses, depreciation, depletion and amortization

	Nine Months Ended September 30,				Nine Months Ended September 30,
	2012				2011
		(per BOE)			(per BOE)
Average price (1)		$	63.53		$	59.07
Production costs			12.92			11.00
Production taxes			7.02			6.23
Depletion and amortization			36.21			31.55
Total operating costs			56.15			48.78
Gross margin		$	7.38		$	10.29
Gross margin percentage			12	%		17	%

(1) Does not include the realized price effects of hedges

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 exclusively 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.

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Commodity price derivative net realized gain was $0.05 million during the nine months ended September 30, 2012, as compared to a realized gain of $0.40 million for the nine months ended September 30, 2011, for a decrease in realized gain of $0.35 million, or 88%.  We also recorded an unrealized gain on commodity price derivatives of $0.45 million for the nine months ended September 30, 2012 compared to a gain of $0.22 million during the nine months ended September 30, 2011, for an increase of $0.23 million, or 105%.

Production costs

Production costs were $1.03 million during the nine months ended September 30, 2012, as compared to $1.11 million for the nine months ended September 30, 2012, a decrease of $0.08 million, or 7%.  Production costs decreased due to lower work over expenses during the nine months ended September 30, 2012.

Production taxes

Production taxes were $0.56 million during the nine months ended September 30, 2012, as compared to $0.63 million during the nine months ended September 30, 2011, a decrease of $0.07 million, or 11%. Production taxes decreased due to the decrease in revenues during the nine months ended September 30, 2012.

General and administrative expenses

General and administrative expenses were $5.10 million for the nine months ended September 30, 2012 compared to $8.84 million for the nine months ended September 30, 2011, a decrease of $3.74 million, or 42%.  General and administrative expenses for the nine months ended September 30, 2012 included approximately $1.07 million in non-cash compensation expense and $0.71 million for non-cash payment for consulting fees.  General and administrative expenses for the nine months ended September 30, 2011 included approximately $5.50 million in non-cash compensation expense.  Excluding non-cash components, cash general and administrative expenses were $3.32 million for the nine months ended September 30, 2012 compared to $3.34 million for the nine months ended September 30, 2011.  Cash general and administrative expenses during the nine months ended September 30, 2012 decreased primarily as a result of a decrease in payroll, legal and accounting fees and third party fees related to transactions, as well as being offset by general increases in other general and administrative expense areas.

Depreciation, depletion and amortization

Depreciation, depletion, and amortization were $2.90 million during the nine months ended September 30, 2012, as compared to $3.19 million during the nine months ended September 30, 2011, a decrease of $.29 million, or 9%.  Depreciation, depletion, and amortization decreased due lower unit volumes of oil and gas sales and a declining cost center.

Expressed in dollars per BOE, depreciation, depletion, and amortization was $36.21 per BOE during the nine months ended September 30, 2012, as compared to $31.55 during the nine months ended September 30, 2011.

Impairment of evaluated properties

Impairment of evaluated properties was $3.27 million during the nine months ended September 30, 2012, as compared to no impairment during the nine months ended September 30, 2011. Impairment of evaluated properties increased due to capitalized costs exceeding the ceiling value as of the quarter ended March 31, 2012.

Interest Expense

Interest expense was $6.32 million during the nine months ended September 30, 2012, compared to $6.12 million during the nine months ended September 30, 2011, an increase of $0.20 million, or 3%.  During the nine months ended September 30, 2012, interest included non-cash charges of $3.8 million, compared to $3.70 million for the nine months ended September 30, 2011.  Cash interest accruing on debt in 2012 decreased primarily as a result of lower average term loan balances.

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Year ended December 31, 2011 compared to year ended December 31, 2010

The following table compares operating data for the fiscal year ended December 31, 2011 to December 31, 2010:

	December 31,
	2011			2010
Revenues and other income:
Oil sales		7,148,110			9,504,737
Gas sales		547,190			68,075
Realized gains on commodity hedges		625,043			570,233
Other		41,751			(385,353	)
Total revenues		8,362,094			9,757,692
Expenses:
Production Costs		1,514,784			862,042
Production Taxes		838,714			1,056,244
General and administrative		10,544,347			15,530,248
Impairment of oil and natural gas properties		2,821,176			-
Depreciation depletion and amortization		4,347,117			5,036,648
Bad debt expense		-			400,000
Total expenses		20,066,138			22,885,182
Income (loss) from continuing operations		(11,704,044	)		(13,127,490	)
Interest expense		(8,218,225	)		(6,640,209	)
Other		71,253			28,666
Debt Inducement Expense		(2,800,000	)		-
Conversion Note Derivative Gain		3,821,792			-
Net income		(18,829,224	)		(19,739,033	)

Total revenues in 2011 declined from $9.8 million in 2010 to $8.4 million in 2011 due primarily to a decrease in net oil production due to natural production declines.  This reduction in oil sales was partially offset by an increase in net gas production, but also affected by changes in the average unit prices received by the Company for the sale of its oil and gas products.  The following table shows the comparison of production volume and average prices:

	Year Ended December 31,
	2011			2010
Oil Sales (net bbls)		81,443			133,709
Gas Sales (net mcf)		115,583			14,914
Average Oil Price	$	87.77		$	71.08
Average Gas Price	$	4.73		$	4.56
Average Price per BOE		76.41			74.47
Production Costs		15.19			6.33
Production Taxes		8.18			7.76
Depreciation and Amortization		42.25			36.98
Total Operating Costs		65.62			51.07
Gross Margin		10.79			23.40
Gross Margin %		14.12	%		31.42	%

Oil volumes declined 39%, gas volume increased by 675%, and prices for both oil and gas increased.  The gas volume increase can be attributed to the production of one gas well that produced during the entirety of 2011, but only for part of 2010.  The decline in oil volume is due almost entirely to natural production declines.

Other revenues in 2010 included an unrealized loss on commodity hedges of $399,000.  Unrealized losses on commodity hedges in 2011 were nominal.

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Production taxes in 2011 decreased by 22% in 2011 as a result in the overall decrease in oil and gas sales.  Production costs increased by 77%.  This increase is due primarily to an increase in the number of workovers, property improvements and other onsite work that was performed on our producing properties during the year.

Depletion expense declined in 2011 by 16% as a result of lower unit volumes of oil and gas sales, and a declining cost center, even though the cost per BOE increased by 14%.

An impairment expense of $2.8 million was recorded in 2011 as a result of capitalized costs exceeding the standardized measure of reserve values.

General and administrative expenses declined 32% in 2011 as compared to 2010.  2011 general and administrative expenses included non-cash stock compensation expense of $6.7 million compared to $13.1 million in 2010.  Excluding these non-cash components, cash general and administrative expenses were $3.9 million in 2011 compared to $2.23 million in 2010.  Cash general and administrative expenses in 2011 increased primarily as a result of an increase in payroll, and legal and third party fees related to transactions, as well as general increases in other general and administrative expense areas.

Interest expense increased by $1.6 million in 2011 as compared to 2010.  2011 interest includes non-cash loan costs amortization of $5.0 million, and cash interest expense of $3.2 million, compared to cash interest expense in 2010 of $2.7 million.  Cash interest increased in 2011 primarily as a result of an increase in the average level of debt.

In 2011, we recorded inducement expense of $2.8 million related to an amendment of our convertible debentures that reduced the conversion price from $9.40 to $4.25 per share.  The inducement related to a request to the holders of the convertible debentures to release certain collateral so that it could be sold. We also recorded derivative gains of $3.8 million related to the reduction of liability attributed to the conversion feature recorded as of the original transaction date in the first quarter of 2011, versus the liability related to this conversion feature as of the end of the year.

Year ended December 31, 2010 compared to year ended December 31, 2009

In general our revenues and expenses were significantly higher in 2010 when compared to inception through December 31, 2009 as during 2009 we were a development stage company with minimal activities.  In January 2010, we acquired our first producing oil and gas assets and incurred interest expense with the associated debt utilized to acquire the property.     Therefore, results are generally not comparable for the year ended December 31, 2010 to the period of inception through December 31, 2009.  We have presented the results for each period below.

Revenue and other income:

For the twelve month period ended December 31, 2010, we had $9,504,737 in oil sales and $68,075 in natural gas sales, respectively.

Average daily net production for the twelve month period ended December 31, 2010 was 373 BOEPD. 

Miscellaneous Income and Operating Fees

We earned net operating fees of $13,487 during the twelve months ended December 31, 2010. We realized a mark-to-market gain of $28,666 during the twelve months ended December 31, 2010 on a put agreement associated with 85,000 shares of stock placed in conjunction with our reverse merger in September 2009.

Price Risk Management Activities

We recorded a net loss on our derivative contracts that do not qualify for cash flow hedge accounting of $(398,840) for the year ended December 31, 2010.  This amount represents an unrealized non-cash loss which represents a change in the fair value of our mark-to-market derivative instruments at December 31, 2010 as detailed in “Note 5 – Financial Instruments and Derivatives” and “Note 6 – Fair Value of Financial Instruments”.  We realized a gain on our derivative contracts that do not qualify for cash flow hedge accounting $570,233 for the year ended December 31, 2010.  This amount represents a realized cash gain from the settlement of our forward sale contracts for the quarter ended December 31, 2010 as detailed in “Note 5 – Financial Instruments and Derivatives” and “Note 6 – Fair Value of Financial Instruments”.   

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Oil and Gas Production Expenses, Depreciation, Depletion and Amortization

	Years ended December 31,
	2010			2009 (1)
Net production
Oil (Bbl)		133,709			-
Gas (Mcf)		14,914			-
MBOE		136,195			-
Average net daily production
Oil (Bbl)		366			-
Gas (Mcf)		41			-
BOE		373			-
Average realized sales price, excluding the effects of hedging
Oil (per Bbl)	$	71.08		$	-
Gas (per Mcf)	$	4.56		$	-
Per BOE	$	70.29		$	-
Average realized sales price, including the effects of hedging
Oil (per Bbl)	$	75.27		$	-
Gas (per Mcf)	$	4.56		$	-
Per BOE	$	74.47		$	-
Production costs per BOE
Lease operating expense (2)	$	6.33		$	-
DD&A	$	36.98		$	-
Production taxes	$	7.76		$	-
Total operating costs	$	51.07		$	-
Gross margin percentage		31	%	$	-	%

(1)	Prior to January 2010, the Company did not own any oil and gas properties.
(2)	Approximately $2.35/BOE of lease operating expense relates to surface, subsurface, road repairs and work-over activities.

General and Administrative Expenses

General and administrative expenses were $15,530,248 for the year ended December 31, 2010.  Our general and administrative expenses twelve months ended December 31, 2010 included $1,464,990 in professional fees (financial advisors, attorneys, accountants, and reserve engineers) of which $372,393 were noncash, and $9,958,300 in non-cash compensation expense.  We also incurred a non-cash expense of $54,500 in rental expense for our office lease for the year ending December 31, 2010 and a non-cash warrant modification expense of $2,953,450 for the year ended December 31, 2010. Total non-cash general and administrative expenditures for the year ended December 31, 2010 was approximately $13,300,000.  This compares to approximately $1,057,306 in general and administrative expenditures from inception through December 31, 2009 which included non-cash expenditures of $690,000.

Depreciation Expense

Depreciation and amortization expense were $5,036,648 for the twelve months ended December 31, 2010.

Interest Expense

Total interest expense was $6,640,209 for the year ended December 31, 2010.  The interest expense was comprised of $3,989,649 in non-cash amortization of expenses for the year ended December 31, 2010 related to warrants issued and overriding royalty interests assigned to our lender in conjunction with the closing of the three credit agreements and the extension of the credit agreements.  We incurred $2,655,131 in cash interest expense for the year ended December 31, 2010.  Neither we nor our predecessor business incurred interest expense from inception through December 31, 2009.

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We incurred a net loss to common shareholders of $19,739,033 for the year ended December 31, 2010.

Financial Condition and Liquidity

Cash used in operating activities during the nine months ending ended September 30, 2012 was $2.75 million; this use of cash, coupled with the cash used in investing activities, exceeded cash provided by financing activities by $2.0 million, and resulted in a corresponding decrease in cash.  This net use of cash also substantially contributed to a $2.20 million decrease in working capital as of September 30, 2012 as compared to working capital as of December 31, 2011.

During the nine months ended September 30, 2012, our working capital decreased to $(0.91 million) from $1.29 million at December 31, 2011. The lower working capital and cash position is primarily the result of a combination of cash used in operating and investing activities, but partially offset by cash provided by financing activities.

A summary of cash flow results during the nine months ended September 30, 2012 follows:

	Nine Months Ended September 30,
	2012
Cash provided by (used in):
Operating activities	$	(2,747,079	)
Investing activities		(3,274,068	)
Financing activities		4,011,701
Net change in cash	$	(2,009,446	)

During the nine months ended September 30, 2012, net cash used in operating activities was $2.75 million.  The primary changes in operating cash during the nine months ended September 30, 2012 were $12.78 million of net loss, adjusted for non-cash charges of $4.51 million of depreciation, depletion, amortization and accretion expenses,  $1.77 million of stock-based compensation, $3.27 million of impairment of evaluated properties, $2.23 million of amortization of deferred financing costs and issuance of stock for convertible debentures interest, and non-cash change in fair value of convertible debentures conversion option of $0.70 million, and offset by a non-cash charge for the change in commodity price derivatives of $0.45 million.

During the nine months ended September 30, 2012, net cash used in investing activities was $3.27 million. The primary changes in investing cash during the nine months ended September 30, 2012 were $0.44 million related to our acquisitions of unproved acreage and drilling capital expenditures of $4.28 million, offset by the proceeds from the sale of undeveloped properties of $1.44 million.

During the nine months ended September 30, 2012, net cash provided by financing activities was $4.01 million. The changes in financing cash during the nine months ended September 30, 2012 were from net proceeds from the issuance of new convertible debentures of $5.00 million, offset by the net repayments of debt of $0.98 million.

On March 19, 2012, we entered into agreements with our existing convertible debenture holders to issue up to an additional $5.0 million in convertible debentures. All terms of the new convertible debentures are substantively identical to the existing convertible debentures.  This financing was completed by September 30, 2012.

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

	September 30, 2012			December 31, 2011
Financial Position Summary
Cash and cash equivalents	$	698,276		$	2,707,722
Working capital	$	(907,863	)	$	1,294,706
Balance outstanding on term loans and convertible debentures payable	$	33,692,339		$	29,680,636
Shareholders’ equity	$	39,311,760		$	49,668,225

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

During the year ended December 31, 2011, our working capital decreased to $1.3 million compared to $4.4 million at December 31, 2010. This lower level of working capital is primarily of the result of cash used in operations, and cash investing activities that exceeded cash provided by financing activities.

During the year ended December 31, 2011, net cash used in operating activities was $570,000. The primary changes in operating cash during the year ended December 31, 2010 were $18.8 million of net loss, adjusted for non-cash charges of $ 4.3 million of depreciation, depletion and amortization expenses and accretion expense, $6.5 million of stock-based compensation and stock paid for services, $4.4 million of amortization of deferred financing costs, $2.8 million of impairment expense, $2.8 million of debt inducement expense, and offset by $3.3 million in non-cash gains on derivatives.

During the year ended December 31, 2011, net cash used by investing activities was $13.3 million. The primary changes in investing cash during the year ended December 31, 2011 was $9.4 million in expenditures related to our acquisitions which consisted primarily of the undeveloped acreage, and $7.0 million in drilling capital expenditures, offset by $3.0 million in proceeds received from the sale of certain undeveloped acreage.

During the year ended December 31, 2011, net cash provided by financing activities was $11.0 million. The primary changes in financing cash during the year ended December 31, 2011 were $8.0 million related to the issuance of convertible debt, $2.1 million derived from the issuance of common stock, and $.9 million in other changes in debt.

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

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

Our primary term debt of $19.5 million is currently due on December 31, 2013.   We will  need to replace or refinance this debt prior to its due date.  While we believe we have sufficient liquidity and other sources of capital available to us that will allow us to conduct our current operations for the next 12 months, we will need to find additional sources of capital  to fund our 2013 drilling budget and, if necessary, to replace our existing debt facility.  We will seek to obtain this additional capital through a combination of the issuance of additional equity or debt securities, use of existing working capital and operating cash flows, and from cash provided by potential joint venture participants.  We may also choose to sell certain non-strategic assets in order to supplement the funding of our 2013 capital budget.

Currently, we have no agreements or understandings with any third parties at this time for additional working capital. Further, under the terms of our credit agreements, we are prohibited from incurring any additional debt from third parties without prior consent from our lender. Our ability to obtain additional working capital through bank lines of credit and project financing would likely be subject to the repayment of the approximately $19.5 million debt related to our primary credit facility.  Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price will be materially adversely affected.

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Term Loans

The Company entered into three separate loan agreements with Hexagon during 2010.  All three loans bear annual interest of 15% and mature on December 31, 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 $6.00 million loan agreement, with an original maturity date of December 1, 2010.  Effective April 14, 2010, the Company entered into a $15 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 loans with the proceeds of the monthly net revenues from the production of the properties acquired using the loan proceeds.  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.

We 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 $1.60 million.  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 of the loans to September 1, 2011.  During the last six months of 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2.00 million as payment on the loans. In November 2011, Hexagon extended the maturity to January 1, 2013.  In November 2011, Hexagon also temporarily advanced the Company an additional amount of $0.31 million, which was repaid in full in February 2012.  In March 2012, Hexagon extended the maturity of the loans to June 30, 2013, and in connection therewith, the Company agreed to make minimum monthly loan payments of $0.33 million, effective immediately.  In July 2012, Hexagon extended the maturity date to September 30, 2013. In November 2012, Hexagon extended the maturity date to December 31, 2013.

As of September 30, 2012, the total debt outstanding under these facilities is $20.29 million, of which $0.87 million is reflected as the current portion of long term debt.

The Company is subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements.  As of September 30, 2012, 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 Debentures Payable

In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of 8% Senior Secured Convertible Debentures due February 2, 2014 (the "Debentures") with a group of accredited investors.  Initially, the Debentures were convertible at any time at the holders' option into shares of our 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 $0.40 million of Debentures equal to 5% of the gross proceeds from the sale.  The Company is amortizing the $0.40 million over the life of the loan as deferred financing costs.  The Company amortized $0.13 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.18 million of deferred financing costs to be amortized through February 2014. 

In December, 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share.

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This amendment was an inducement consideration to the Debenture holders for their agreement to release a mortgage on certain properties so the properties could be sold. The sale of these properties was effective December 31, 2011, and a final closing occurred during the three months ended March 31, 2012.

On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to increase the amount of its Debentures by up to an additional $5.0 million (the “Supplemental Debentures”).  Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of Supplemental Debentures are to be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other general corporate purposes. Any new producing properties that are developed from the proceeds of Supplemental Debentures are to be pledged as collateral under a mortgage to secure future payment of the Debentures and Supplemental Debentures. All terms of the Supplemental Debentures are substantively identical to the Debentures.  The Agreements also provided for the payment of additional consideration to the purchasers of Supplemental Debentures in the form of a proportionately reduced, 5% carried working interest in any properties developed with the proceeds of the Supplemental Debenture offering.

Through July 2012, we received $3.04 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development of six new wells, resulting in a total investment of $3.69 million.  Five of these wells resulted in commercial production, and one well was plugged and abandoned.

In August 2012, the Company and certain holders of the Supplemental Debentures agreed to renegotiate the terms of the Supplemental Debenture offering.  These negotiations concluded with the issuance of an additional $1.96 million of Supplemental Debentures.  The August 2012 modifications to the Supplemental Debenture agreements increased the carried working interest from 5% to 10% and also provided for a one-year, proportionately reduced net profits interest of 15% in the properties developed with the proceeds of the Supplemental Debenture offering, as well as the next four properties to be drilled and developed by the Company.

The Company has estimated the total value of consideration paid to Supplemental Debenture holders in the form of the modified net profits interest and carried working interest to be approximately $1.16 million, and recorded this amount as a debt discount to be amortized over the remaining life of the Debentures.

We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect to September 30, 2012, the Supplemental Debentures.  This valuation resulted in an estimated derivative liability as of September 30, 2012 and December 31, 2011 of $1.3 million and $1.3 million, respectively.  The portion of the derivative liability that is associated with the Supplemental Debentures, in the approximate amount of $0.70 million, has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.

During the nine and three months ended September 30, 2012, the Company amortized $1.65 million and $0.71 million, respectively of debt discounts.

On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures.  The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs.  The Company amortized $0.01 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.22 million of deferred financing costs to be amortized through February 2014. 

As of September 30, 2012 and December 31, 2011, the convertible debt is recorded as follows:

	As of				As of
		September 30, 2012				December 31, 2011
Convertible debentures		$	13,400,000			$	8,400,000
Debt discount			(3,804,947	)			(3,470,932	)
Total convertible debentures, net		$	9,595,053			$	4,929,068

Annual debt maturities as of September 30, 2012 are as follows:

Year 1	$	873,142
Year 2		32,819,197
Thereafter		-
Total	$	33,692,339

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Interest Expense

For the years ended December 31, 2011 and 2010, the Company incurred interest expense of approximately $8.2 million and $6.6 million, respectively, of which approximately $5.0 million and $3.9 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures payable interest paid in stock.

For the nine months ended September 30, 2012 and 2011, the Company incurred interest expense of approximately $6.32 million and $6.12 million, respectively, of which approximately $3.86 million and $3.70 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures payable interest paid in stock.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

2013 Capital Budget

Our 2013 Capital Budget is currently projected to be approximately $15 million, but is subject to securing sufficient capital to support planned drilling and development expenses.  We anticipate that approximately 50% of this budget will be allocated toward the development of two of our unconventional prospects located in the Wattenburg field of the DJ Basin that will target horizontal drilling and development of the Niobrara shale and Codell formations.  The remainder of our 2013 budget is anticipated to be directed principally toward the conventional development of certain lower risk offset wells to existing production.  We also anticipate the allocation of approximately 10% of our 2013 capital budget toward higher risk exploration activities, including the procurement of seismic and the drilling of one conventional exploratory well.

Our 2013 capital expenditure budget was subject to various factors, including market conditions, availability of capital, oilfield services and equipment availability, commodity prices and drilling results.  Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget as the cash flow from the wells could provide additional capital which we may use to increase our capital budget. We do not anticipate any significant expansion of our current acreage position.

Other factors that could cause us to further increase our level of activity and adjust our capital expenditure budget include a reduction in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, a further improvement in commodity prices or well performance that exceeds our forecasts, any of which could positively impact our operating cash flow. Factors that could cause us to reduce level of activity and adjust our capital budget include, but are not limited to, increases in service and materials costs, reductions in commodity prices or under-performance of wells relative to our forecasts, any of which could negatively impact our operating cash flow.

Capital Resources

Our 2013 capital program is subject to securing sufficient capital, principally via the issuance of additional equity and debt both to fund our capital program and to refinance the Hexagon loans which are due on December 31, 2013.   We may also secure additional capital by pursuing sales of certain assets that are considered non-strategic.  We may also seek to finance certain projects via joint venture agreements or other arrangements with strategic or industry partners.

Currently, the majority of our cash flows from operations are applied to the payment of principal and interest of our loans and to capital expenditures.  Due to the continuing operating losses and the large amounts of capital expenditures during 2011 and continuing through 2012, 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 address our upcoming debt maturities, and will also require substantial additional capital in order to fully test, develop and evaluate our 125,000 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.  Unless we are successful in competing a substantial debt and/or equity financing or other similar transaction in the near term, 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.

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We cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings, equity offerings or other financings, or sales of non-strategic assets will be sufficient to fund our anticipated 2013 capital expenditures.

Plan of Operations

Our plan of operations is to identify and develop oil and natural gas prospects from our existing inventory of undeveloped acreage.  We anticipate the investment of substantial capital during the next few years to evaluate, assess and develop this inventory.   Currently, our inventory of developed and undeveloped leases includes approximately 21,800 net acres that are held by production, approximately 11,600 net acres that expire in 2013, and approximately 25,000 net acres, 59,000 net acres and 7,600 net acres that expire in the years 2014, 2015 and thereafter, respectively.   Approximately 64% of our remaining inventory of undeveloped leases provide for extension of lease terms from two to five years, at the option of the Company, via payment of varying, but typically nominal, extension amounts.

The Company has one well in progress that has been drilled, completed and is pending further evaluation as to its potential to ultimately produce commercial quantities of hydrocarbons.  This well is carried at a cost of $3.82 million.  The Company believes that this well should be ultimately capable of commercial production, but will need to invest additional capital to obtain this status.  However, should this well be ultimately plugged and abandoned, all capitalized costs would be transferred to the full cost pool. 

Likewise, operations that are being conducted on this well are extending the primary terms of leases that comprise approximately 6,919 net acres that are currently being carried at a cost of approximately $4.1 million.  Absent a successful completion of this well, the lease terms of some or all of these acres may expire, and the carrying costs of these leases would also be transferred to the full cost pool.

The acquisition and development of properties and prospects and the pursuit of new opportunities require that we maintain access to adequate levels of capital.   We will strive for an optimal balance between our property portfolio and our capital structuring that will allow for growth designed to build shareholder value and profitability.   The decisions around the balancing of capital needs and property holdings will be a challenge to us as well as all companies in the entire energy industry during this time of continued disruption in the financial markets and an increasingly complex global economic picture.  As a function of balancing properties and capital, we may decide to monetize certain properties to reduce debt or to allow us to acquire interests in new prospects or producing properties that may be better suited to the current economic and energy industry environment.

The business of oil and natural gas acquisition, exploration and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. Therefore, a principal part of our plan of operations is to raise the additional capital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties.  As explained under “Financial Condition and Liquidity”, based on our present working capital and current rate of cash flow from operations, we will need to raise additional capital to partially fund our overhead, and  fund our exploration and development budget through, at least, December 31, 2013.  We will seek additional capital through the sale of our securities and we will endeavor to obtain additional capital through debt and project financing.  However,  under the terms of our $19.5 million in credit facilities, we are prohibited from incurring any additional debt from third parties without prior consent from our lender.  Our ability to obtain additional capital through new debt instruments and project financing may be subject to the repayment of our $19.5  million credit facility.

We intend to use the services of independent consultants and contractors to perform various professional services, including land, legal, environmental, investor relations and tax services.  We believe that by limiting our management and employee costs, we may be able to better control total costs and retain flexibility in terms of project management.  

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.

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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. 

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States, or GAAP, requires our management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period.  The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures.

Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial condition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.

Use of Estimates

The financial statements included herein were prepared from the records of Recovery in accordance with GAAP, and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods.  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 various issuances of common stock, options and warrants and estimated fair value of the asset held for sale.

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Oil and Natural Gas Reserves

We follow the full cost method of accounting.  All of our oil and gas properties are located within the United States, and therefore all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool.  Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves.  Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties.  Should capitalized costs exceed this ceiling, impairment would be recognized.  Under the SEC rules, we prepared our oil and gas reserve estimates as of September 30, 2012, using the average, first-day-of-the-month price during the 12-month period ending September 30, 2012.

Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process.  The process relies on interpretations of available geological, geophysical, engineering and production data.  The extent, quality and reliability of this technical data can vary.  The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate. 

We believe estimated reserve quantities and the related estimates of future net cash flows are the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties.  Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used.  For example, the standardized measure calculation requires us to apply a 10% discount rate.  Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change.  We evaluate and estimate our oil and natural gas reserves as of December 31 of each year and quarterly throughout the year.  For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions.  Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.

Oil and Natural Gas Properties—Full Cost Method of Accounting

We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.

Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations.  These undeveloped properties are assessed quarterly to ascertain whether impairment has occurred.  When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations.

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Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%.  Royalties paid, net of any tax credits received, are netted against oil and natural gas sales. 

In applying the full cost method, we perform a ceiling test on properties that restricts the capitalized costs, less accumulated depletion, from exceeding an amount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleum engineers.  The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the end of the applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financing costs, future site restoration costs and income taxes.  Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.

The Company has one well in progress that has been drilled, completed and is pending further evaluation as to its potential to ultimately produce commercial quantities of hydrocarbons.  This well is carried at a cost of $3.82 million.  The Company believes that this well should be ultimately capable of commercial production, but will need to invest additional capital to obtain this status.  However, should this well be ultimately plugged and abandoned, all capitalized costs would be transferred to the full cost pool. 

Likewise, operations that are being conducted on this well are extending the primary terms of leases that comprise approximately 6,919 net acres and that are currently being carried at a cost of approximately $4.1 million.  Absent a successful completion of this well, the lease terms of some or all of these acres may expire, and the carrying costs of these leases would also be transferred to the full cost pool.

Revenue Recognition

The Company derives revenue primarily from the sale of produced natural gas and crude oil.  The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses and are included in oil and gas production expense in the accompanying consolidated statements of operations.  Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production.  No revenue is recognized unless it is determined that title to the product has transferred to the purchaser.  At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive.  The Company uses its knowledge of its properties, their historical performance, NYMEX and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates.

Share Based Compensation

The Company accounts for share-based compensation by estimating the fair value of share-based payment awards made to employees and directors, including restricted stock grants, on the date of grant.  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.  

Derivative Instruments

Periodically, the Company entered into swaps to reduce the effect of price changes on a portion of our future oil production. We reflect the fair market value of our derivative instruments on our balance sheet.  Our estimates of fair value are determined by obtaining independent market quotes as well as utilizing a valuation model that is based upon underlying forward curve data and risk free interest rates.  Changes in commodity prices will result in substantially similar changes in the fair value of our commodity derivative agreements.  We do not apply hedge accounting to any of our derivative contracts, therefore we recognize mark-to-market gains and losses in earnings currently.

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DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth the names, ages and positions of the persons who are our directors and named executive officers as of the date of this prospectus:

Name	Age	Position
W. Phillip Marcum	68	Chief Executive Officer, Chairman
A. Bradley Gabbard	58	President, Chief Financial Officer, Director
Bruce B. White	60	Director
Timothy N. Poster	43	Director
D. Kirk Edwards	52	Director

Directors hold office for a period of one year from their election at the annual meeting of stockholders and until a particular director’s successor is duly elected and qualified. Officers are elected by, and serve at the discretion of, our board of directors. None of the above individuals has any family relationship with any others. It is expected that our board of directors will elect officers annually following each annual meeting of stockholders.

W. Phillip Marcum:  Chief Executive Officer and Chairman of the Board of Directors.  Mr. Marcum joined our board of directors in September, 2011. He has been a director of Houston Texas-based Key Energy Services (NYSE: KEG) since 1996.  Mr. Marcum was the non-executive chairman of the board of WellTech, Inc., an energy production services company, from 1994 until March 1996, when WellTech was merged into Key Energy Services. From January 1991 until April 2007, when he retired, he was chairman of the board, president and chief executive officer of Metretek Technologies, Inc. (now known as PowerSource International, Inc., and formerly known as Marcum Natural Gas Services, Inc.).  He has been a principal in MG Advisors, LLC since April 2007.  Mr. Marcum also serves as chairman of the board of ADA-ES, a Denver, Colorado based company (“ADA”), and chairman of the board of Applied Natural Gas Fuels, Inc. (formerly PNG Ventures, Inc.), a Westlake Village, California based company. He holds a bachelor's degree in business administration from Texas Tech University. When determining Mr. Marcum’s qualifications to serve as a director of the Company, the Company considered his leadership experience, as chairman of the board, president and CEO of PowerSecure International, Inc., director of Key Energy Services, non-executive chairman of WellTech and chairman of the boards of ADA and Applied Natural Gas Fuels, and his industry experience, which includes extensive experience in oil and gas development stage and public companies at the entities and in the capacities described above.

A. Bradley Gabbard: President, Chief Financial Officer and Director. Mr. Gabbard became our chief financial officer in July 2011. He has 35 years’ experience in the management and operations of energy and oil and gas companies. Prior to coming to Recovery Energy, he served as an officer of Applied Natural Gas Fuels, Inc., serving from September 2009 to May 2010 as vice-president—special projects, and from May 2010 through June 2011 as chief financial officer. From April 2007 through September 2009, Mr. Gabbard provided management and financial consulting services to companies involved in the oil and gas and energy related businesses. From 1991 to April 2007, Mr. Gabbard co-founded and served as chief financial officer, executive vice president and a director of PowerSecure International, Inc. (f/k/a Metretek Technologies, Inc.), a developer of energy and smart grid solutions for electric utilities, and their commercial, institutional, and industrial customers. Mr. Gabbard also serves as a director on the board of ADA. Mr. Gabbard received a bachelor of accountancy degree from the University of Oklahoma in 1977, and is a CPA. When determining Mr. Gabbard’s qualifications to serve as a director of the Company, the Company considered his experience as a senior officer of, and consultant to, several energy companies and his background in financial accounting.

Bruce B. White:  Director.  Mr. White joined our board in April 2012.  He is currently a senior vice president of High Sierra Water Services, LLC and has served in that capacity since the purchase of Conquest Water Services, LLC by High Sierra in June 2011. Mr. White co-founded Conquest Water Services in 1993 and served as a co-managing partner to build that company into a DJ Basin service company. Mr. White has more than 25 years of experience operating in the DJ basin, including exploration, drilling, development and other well operations, many of which were conducted through Conquest Oil Company, founded by White in 1984 which he continues to serve as president. White served as the Chairman of the University of Northern Colorado Foundation in 2003. White was also a founding member of the Denver Julesburg Petroleum Association, the predecessor to the Colorado Oil and Gas Association (COGA), and served as its president during 1987 and 1988.   A veteran of the Vietnam War, Mr. White served in the Navy for six years; he attended Grossmont College in El Cajon, California but does not hold a degree from there. When determining Mr. White’s qualifications to serve as a director of the Company, the Company considered his leadership experience as founder of Conquest Oil Company and Conquest Water Services and Senior Vice President of High Sierra Water Services, as well as his industry experience, including extensive experience in oil and gas development and services industries at the entities and in the capacities described above.

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D. Kirk Edwards: Director. Mr. Edwards became president of Las Colinas Energy Partners, LP and four affiliated entities in March, 2012, where he manages a diverse oil and gas royalty base, surface lands, and non-operated working interests in more than 9,000 wells located throughout the U.S. and the Gulf Coast of Mexico. He has served as president for the following oil and gas companies for more than five years:  MacLondon Royalty Company (and four affiliates), Alexis Energy GP, LP, and Noelle Land & Minerals LLC. Mr. Edwards worked in various disciplines as a petroleum engineer including Field, Reservoir, and drilling engineer for Texaco, Inc. from 1981-1986. In 1987, he founded Odessa Exploration, Inc., an independent oil and gas company, which he sold to Key Energy Services, Inc. in 1993. He served as a director, executive vice president and in other capacities of Key Energy Services until 2001. Mr. Edwards is a past president of the Permian Basin Petroleum Association, and is a past director and former chairman of the board of the Federal Reserve Bank of Dallas’ El Paso Branch. Mr. Edwards received a Bachelor of Science degree in Chemical Engineering from the University of Texas at Austin in 1981, and is a registered Professional Engineer in the State of Texas. When determining Mr. Edwards’s qualifications to serve as a director of the Company, the Company considered his experience running numerous oil and gas companies and his extensive business knowledge working with other companies in the energy industry.

Compensation of Directors

The table below sets forth the compensation earned by our non-employee directors during the 2012 fiscal year. There were no non-equity incentive plan compensation, stock options, change in pension value or any non-qualifying deferred compensation earnings during the 2012 fiscal year. All amounts are in dollars.

Name	Fees Earned or Paid in Cash Compensation		Stock Awards		All Other Compensation		Total
Timothy N. Poster	$	40,000.00	$	40,000.00	$	0.00	$	80,000.00
W. Phillip Marcum (1)	$	42,500.00	$	150,000.00	$	0.00	$	192,500.00
D. Kirk Edwards	$	24,835.16	$	150,000.00	$	0.00	$	174,835.16
Bruce B. White	$	27,472.52	$	150,000.00	$	0.00	$	177,472.52
Conway J. Schatz (2)	$	5,000.00	$	0.00	$	0.00	$	5,000.00

(1)  Mr. Marcum ceased being a non-employee director when he was appointed chief executive officer on November 15, 2012.

(2)  Mr. Schatz resigned as a director to pursue other professional and career obligations on January 31, 2012.

We currently pay each of our non-employee directors annual cash compensation of $40,000 ($10,000 per quarter), and annual equity compensation in common shares equal to $40,000 (payable on each anniversary of their initial appointment) at the then current fair market value of our shares. We pay additional cash compensation of $10,000 per year (payable quarterly) to the chairman of our audit and compensation committees. Mr. Poster currently serves as chair of our compensation committee, and Mr. Marcum served as chair of our audit committee until he was appointed an executive officer of the Company on November 15, 2012.

In May 2010 we granted Mr. Poster 125,000 shares of our common stock, 50% of which vested on January 1, 2011 and the other 50% of which will vest on January 1, 2012. In April 2012 we granted Mr. Marcum and Mr. White 50,000 shares of our common stock for their service as directors.  The shares vest in equal amounts on the first, second and third anniversaries of the date of their initial appointment to the board (September 9, 2011 for Mr. Marcum and April 24, 2012 for Mr. White). We also made an additional grant of 13,115 to Mr. Poster in April 2012 in accordance with his independent director agreement. In May 2012, when Mr. Edwards joined the board, we granted him 50,000 shares subject to vesting on the first, second and third anniversaries of the date of his initial appointment to the board (May 18, 2012).

We have entered into independent director agreements with our non-employee directors. These agreements provide that the shares granted to a director fully vest upon a change of control or termination of the director's services as a director by Recovery Energy other than for cause. The agreements permit a director to engage in other business activities in the energy industry, some of which may be in conflict with the best interests of Recovery Energy, and also states that if a director becomes aware of a business opportunity, he has no affirmative duty to present or make such opportunity available to us.

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EXECUTIVE COMPENSATION

Executive Compensation for Fiscal Year 2012

The compensation earned by our executive officers for fiscal 2012 consisted of base salary and long-term incentive compensation consisting of awards of stock grants.

Summary Compensation Table

The table below sets forth compensation paid to our executive officers for the 2012 and 2011 fiscal years.

Name and Principal Position	Year	Salary		Bonus		Stock Awards			Other Compensation			Total
Roger A. Parker	2012	$	217,700	$	-	$	-		$	141,903	(1)	$	359,603
(chief executive officer May 1, 2010 – November 15, 2012)(3)	2011	$	240,000	$	-	$	-		$	110,000	(2)	$	350,000
A. Bradley Gabbard	2012	$	182,146	$	-	$	97,689	(4)	$	5,275	(5)	$	285,110
(chief financial officer since July 12, 2011; president since November 15, 2012)	2011	$	84,000	$	-	$	166,000	(6)	$	-		$	250,000
Jeffrey A. Beunier	2012	$	-	$	-	$	-		$	70,459	(7)	$	-
(president and chief financial officer from May 1, 2010 to April 11, 2011)(8)	2011	$	225,000	$	-	$	-		$	12,000	(5)	$	237,000
W. Phillip Marcum (chief executive officer since November 15, 2012)(9)	2012	$	-	$	-	$	-		$	-		$	-

(1)	Reflects (a) $21,400 in vacation pay paid upon termination, (b) $21,400 in severance payments, (c) $16,603 in reimbursement of health insurance premiums, and (d) $82,500 of expense reimbursement pursuant to Mr. Parker's employment agreement.
(2)	Reflects payment of $90,000 of expense reimbursement pursuant to Mr. Parker's employment agreement and $20,000 in reimbursement of health insurance premiums.
(3)	Mr. Parker retired as an executive officer of the Company on November 15, 2012.
(4)	Mr. Gabbard was granted 26,042 shares of our common stock on November 23, 2012 at a cost basis of $1.78 per share and 29,167 shares of our common stock on November 30, 2012 at a cost basis of $1.76 per share.
(5)	Reflects reimbursement of health insurance premiums.
(6)	Mr. Gabbard was granted 100,000 shares of our common stock in 2011 as compensation.  We recognized $166,000 of compensation expense in 2011 for these shares.
(7)	Mr. Beunier resigned as an executive officer of the Company to pursue other professional and career obligations on April 11, 2011.
(8)	Reflects $65,625 in severance payments and $4,834 in continuing health insurance benefits.
(9)	As of December 31, 2012, Mr. Marcum had not received any stock or cash compensation as an officer of the Company.

Outstanding Equity Awards at Fiscal Year-End

	Stock Awards
Name	Number of shares or units of stock that have not vested (#)		Market value of shares of units of stock that have not vested ($)		Equity incentive plan awards: Number of unearned shares, units or other rights that have not vested (#)		Equity incentive plan awards: Market or payout value of unearned shares, units or other rights that have not vested ($)
Roger A. Parker		1,350,000		2,686,500		0		0
A. Bradley Gabbard		107,292		213,511		0		0

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There were no outstanding option awards at December 31, 2012.

The Board of Directors and Committees Thereof

Our board of directors conducts its business through meetings and through its committees. Our board of directors held 10 meetings in 2012, which all directors attended.  Our policy regarding directors’ attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances.

Affirmative Determinations Regarding Director Independence and Other Matters

Our board of directors follows the standards of independence established under the Nasdaq rules in determining if directors are independent and has determined that three of our current directors, Timothy N. Poster, D. Kirk Edwards and Bruce B. White are “independent directors” under those rules.  W. Phillip Marcum was an “independent director” prior to his appointment in November 2012 as our chief executive officer. No independent director receives, or has received, any fees or compensation from us other than compensation received in his or her capacity as a director. There were no transactions, relationships or arrangements not otherwise disclosed that were considered by the board of directors in determining that any of the directors are independent.

Committees of the Board of Directors

Pursuant to our amended and restated bylaws, our board of directors is permitted to establish committees from time to time as it deems appropriate. To facilitate independent director review and to make the most effective use of our directors’ time and capabilities, our board of directors has established an audit committee and a compensation committee. The membership and function of these committees are described below.

Compensation Committee

Our compensation committee currently consists of Mr. Edwards, Mr. Poster and Mr. White. Mr. Poster is chair of the compensation committee. The compensation committee did not meet during 2012, but acted by written consent. The compensation committee reviews, approves and modifies our executive compensation programs, plans and awards provided to our directors, executive officers and key associates. The compensation committee also reviews and approves short-term and long-term incentive plans and other stock or stock-based incentive plans. In addition, the committee reviews our compensation and benefit philosophy, plans and programs on an as-needed basis. In reviewing our compensation and benefits policies, the compensation committee may consider the recruitment, development, promotion, retention, compensation of executive and senior officers of Recovery Energy, trends in management compensation and any other factors that it deems appropriate. The compensation committee may engage consultants in determining or recommending the amount of compensation paid to our directors and executive officer. The compensation committee is governed by a written charter that will be reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.recoveryenergyco.com under “Investor Relations.”

Compensation Committee Interlocks and Insider Participation

None of the members of the compensation committee is or has been an officer or employee of the Company. None of our executive officers currently serves or has served on the compensation committee (or other board committee performing equivalent functions or, in the absence of any such committee, the entire board of directors) or as a director of another entity, one of whose executive officer serves or served as one of our directors or on our compensation committee.

Audit Committee

Our audit committee currently consists of Mr. Edwards, Mr. Poster and Mr. White.  Prior to Mr. Marcum’s appointment in November 2012 as our chief executive officer, he served as chair of our audit committee and met the Securities and Exchange Commission's definition of an audit committee financial expert. The Company is currently conducting a search for a new independent director to replace Mr. Marcum as audit committee financial expert. The audit committee is governed by a written charter that will be reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.recoveryenergyco.com under “Investor Relations.”

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Communications with the Board of Directors

Stockholders may communicate with our board of directors or any of the directors by sending written communications addressed to the board of directors or any of the directors, Recovery Energy, Inc., 1900 Grant Street, Suite #720, Denver, CO 80203, Attention: Corporate Secretary. All communications are compiled by the corporate secretary and forwarded to the board or the individual director(s) accordingly.

Nomination of Directors

Our board of directors has not established a nominating committee because the board believes that it is unnecessary in light of the board’s small size. In the event that vacancies on our board of directors arise, the board considers potential candidates for director, which may come to the attention of the board through current directors, professional executive search firms, stockholders or other persons.  Our board does not set specific, minimum qualifications that nominees must meet in order to be recommended as directors, but rather believes that each nominee should be evaluated based on his or her individual merits, taking into account the needs of Recovery and the composition of our board.  We do not have any formal policy regarding diversity in identifying nominees for a directorship, but rather consider it among the various factors relevant to any particular nominee.  In the event we decide to fill a vacancy that exists or we decide to increase the size of the board, we identify, interview and examine appropriate candidates.  We identify potential candidates principally through suggestions from our board and senior management.  Our chief executive officer and board members may also seek candidates through informal discussions with third parties.  We also consider candidates recommended or suggested by stockholders.

The board will consider candidates recommended by stockholders if the names and qualifications of such candidates are submitted in writing in accordance with the notice provisions for stockholder proposals set forth under the caption “General Information — Next Annual Meeting of Stockholders” in this prospectus to our corporate secretary, Recovery Energy, Inc., 1900 Grant Street, Suite #720, Denver, CO 80203, Attention: Corporate Secretary. The board considers properly submitted stockholder nominations for candidates for the board of directors in the same manner as it evaluates other nominees. Following verification of the stockholder status of persons proposing candidates, recommendations are aggregated and considered by the board and the materials provided by a stockholder to the corporate secretary for consideration of a nominee for director are forwarded to the board. All candidates are evaluated at meetings of the board. In evaluating such nominations, the board seeks to achieve the appropriate balance of industry and business knowledge and experience in light of the function and needs of the board of directors. The board considers candidates with excellent decision-making ability, business experience, personal integrity and reputation. Our management recommended our incumbent directors for election at our 2012 annual meeting. We did not receive any other director nominations.

Code of Conduct

Our board of directors has adopted a code of conduct that applies to all of our officers and employees, including our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. Our code of conduct codifies the business and ethical principles that govern all aspects of our business. A copy of our code of conduct is available on our website at www.recoveryenergyco.com under “Investor Relations” and “Corporate Governance.” We undertake to provide a copy of our code of conduct to any person, at no charge, upon a written request. All written requests should be directed to: Recovery Energy, Inc., 1900 Grant Street, Suite #720, Denver, CO 80203, Attention: Corporate Secretary.

Board Leadership Structure

The board’s current leadership structure does not separate the positions of chairman and principal executive officer. The board has determined our leadership structure based on factors such as the experience of the applicable individuals, the current business and financial environment faced by Recovery, particularly in view of its financial condition and industry conditions generally and other relevant factors. After considering these factors, we determined that not separating the positions of chairman of the board and principal executive officer is the appropriate leadership structure at this time. The board, through the chairman and the chief executive officer, is currently responsible for the strategic direction of the company. The chief executive officer is currently responsible for the day to day operation and performance of the company.  The board feels that this provides an appropriate balance of strategic direction, operational focus, flexibility and oversight.

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The Board’s Role in Risk Oversight

It is management’s responsibility to manage risk and bring to the board's attention any material risks to the company. The board has oversight responsibility for Recovery's risk policies and processes relating to the financial statements and financial reporting processes and the guidelines, policies and processes for mitigating those risks.

Employment Agreements and Other Compensation Arrangements

Until his resignation in November 2012, we had an employment agreement with Mr. Parker.  Under his employment agreement Mr. Parker received an annual base salary of $240,000 and was eligible for an annual cash bonus based on performance goals that included targets related to earnings before interest taxes, depreciation and amortization, hydrocarbon production level, and hydrocarbon reserve amounts, with a targeted bonus of no less than $100,000 (with board approval).  Mr. Parker also received a monthly, non-accountable expense reimbursement of $7,500 for expenses related to company business. Mr. Parker received grants totaling 1,375,000 shares of our common stock, 100,000 of which vested on January 1, 2011. Pursuant to the terms of the severance agreement we entered into with Mr. Parker on November 15, 2012, the remainder of Mr. Parker’s outstanding restricted stock will vest in two equal installations, one on May 15, 2013 and one on November 15, 2013. 

In 2012, Mr. Gabbard received an annual salary of $187,250, and was granted 104,167 shares of our common stock, 26,042 shares of which vested immediately and 78,125 shares of which vest annually over three years beginning on November 23, 2013.

The compensation committee is currently negotiating compensation arrangements with Mr. Marcum and Mr. Gabbard.  Although final agreements have not been completed, the general terms of these arrangements are expected to be as follows:

Each of Mr. Marcum and Mr. Gabbard will receive an annual salary of $220,000. Each executive will be eligible for a performance bonus in an amount up to 50% of annual base compensation payable on an annual basis and subject to determination by the compensation committee of the Board, based on the achievement by the Company of performance goals established by the compensation committee for the preceding fiscal year, which may include targets related to the Company’s earnings before interest, taxes, depreciation and amortization, hydrocarbon production level, and hydrocarbon reserve amounts. Each executive will also receive an incentive grant of 300,000 stock options with a fair market value vesting price, with vesting occurring 33.33% on each of the next three anniversaries of the grant date.  Such stock options will vest 100% upon a termination of employment by the Company without cause, by the executive for good reason, upon a change of control of the Company or upon the death or disability of the executive. Upon a termination due to death or disability, a termination initiated by the executive for any reason except for good reason, or a termination initiated by the Company with cause, the Company’s obligation to pay any compensation or benefits ceases on the separation date.  If the separation is initiated by the executive for good reason or by the Company for any reason other than cause, the Company will continue to pay the executive’s monthly salary as then in effect for a period equal to twelve (12) months commencing on the separation date.

Compensation Discussion and Analysis

Overview

The following Compensation Discussion and Analysis describes the material elements of compensation for the named executive officers identified in the Summary Compensation Table above. As more fully described below, the compensation committee reviews and recommends to the full board of directors the total direct compensation programs for our named executive officers. Our chief executive officer also reviews the base salary, annual bonus and long-term compensation levels for the other named executive officers.

Compensation Philosophy and Objectives

Our compensation philosophy has been to encourage growth in our oil and natural gas reserves and production, encourage growth in cash flow, and enhance stockholder value through the creation and maintenance of compensation opportunities that attract and retain highly qualified executive officers. To achieve these goals, the compensation committee believes that the compensation of executive officers should reflect the growth and entrepreneurial environment that has characterized our industry in the past, while ensuring fairness among the executive management team by recognizing the contributions each individual executive makes to our success.

Based on these objectives, the compensation committee has recommended an executive compensation program that includes the following components:

● a base salary at a level that is competitive with the base salaries being paid by other oil and natural gas exploration and production enterprises that have some characteristics similar to Recovery and could compete with Recovery for executive officer level employees;

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● annual incentive compensation to reward achievement of Recovery's objectives, individual responsibility and productivity, high quality work, reserve growth, performance and profitability and that is competitive with that provided by other oil and natural gas exploration and production enterprises that have some characteristics similar to Recovery; and

● long-term incentive compensation in the form of stock-based awards that is competitive with that provided by other oil and natural gas exploration and production enterprises that have some characteristics similar to Recovery.

As described below, the compensation committee periodically reviews data about the compensation of executives in the oil and gas industry. Based on these reviews, we believe that the elements of our executive compensation program have been comparable to those offered by our industry competitors.

Elements of Recovery’s Compensation Program

The three principal components of Recovery’s compensation program for its executive officers, base salary, annual incentive compensation and long-term incentive compensation in the form of stock-based awards, are discussed below.

Base Salary.  Base salaries (paid in cash) for our executive officers have been established based on the scope of their responsibilities, taking into account competitive market compensation paid by the peer companies for similar positions. We have reviewed our executives’ base salaries in comparison to salaries for executives in similar positions and with similar responsibilities at companies that have certain characteristics similar to Recovery. Base salaries are reviewed annually, and typically are adjusted from time to time to realign salaries with market levels after taking into account individual responsibilities, performance, experience and other criteria.

The compensation committee reviews with the chief executive officer his recommendations for base salaries for the named executive officers, other than himself, each year. New base salary amounts have historically been based on an evaluation of individual performance and expected future contributions to ensure competitive compensation against the external market, including the companies in our industry with which we compete. The compensation committee has targeted base salaries for executive officers, including the chief executive officer, to be competitive with the base salaries being paid by other oil and natural gas exploration and production enterprises that have some characteristics similar to Recovery. We believe this is critical to our ability to attract and retain top level talent.

Long Term Incentive Compensation.  We believe the use of stock-based awards creates an ownership culture that encourages the long-term performance of our executive officers. Each of our named executive officers received a stock grant upon becoming an employee of Recovery. These grants vest over time.

Other Benefits.  All employees may participate in our 401(k) retirement savings plan, or 401(k) plan. Each employee may make before tax contributions in accordance with the Internal Revenue Service limits. We provide this 401(k) plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. We make a matching contribution in an amount equal to 100% of the employee’s elective deferral contribution below 3% of the employee’s compensation and 50% of the employee’s elective deferral that exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’s compensation.

All fulltime employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, dental and vision care coverage, disability insurance and life insurance.

Indemnification of Directors and Officers

Pursuant to our certificate of incorporation we provide indemnification of our directors and officers to the fullest extent permitted under Nevada law.  We believe that this indemnification is necessary to attract and retain qualified directors and officers.

Narrative Disclosure of Compensation Policies and Practices as they Relate to Risk Management

In accordance with the requirements of Regulation S-K, Item 402(e), to the extent that risks may arise from our compensating policies and practices that are reasonably likely to have a material adverse effect on Recovery, we are required to discuss these policies and practices for compensating our employees (including employees that are not named executive officers) as they relate to our risk management practices and the possibility of incentivizing risk-taking.  We have determined that the compensation policies and practices established with respect to our employees are not reasonably likely to have a material adverse effect on Recovery and, therefore, no such disclosure is necessary.  The compensation committee and the board for directors are aware of the need to routinely assess our compensation policies and practices and will make a determination as to the necessity of this particular disclosure on an annual basis.

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TRANSACTIONS WITH RELATED PERSONS

During fiscal year 2010 through the date of this prospectus, we have engaged in the following transactions with related parties:

Edward Mike Davis. We have acquired most of our oil and gas properties from Edward Mike Davis, L.L.C. and Spottie, Inc., both owned by Edward Mike Davis. We paid for these acquisitions in a combination of cash and stock. As a result of these transactions, the Davis entities received an aggregate of 3,291,667 shares of our common stock. As of December 31, 2012, Davis had sold substantially all of his Recovery stock. The Davis entities were not a related party prior to these transactions. The specific transactions with the Davis entities are:

●  The Wilke Field acquisition agreement entered into in December 2009 did not close. The agreement provided for a purchase price of $2,200,000 and 387,500 shares of common stock. 362,500 shares were given as a non-refundable deposit.   

●  The Wilke Field acquired in January 2010, for $4,500,000 in cash effective as of January 1, 2010. Included in the acquisition were seven producing wells and a 50% working interest in two development prospects located in Nebraska and Colorado. 

●  The Albin Field acquired in March 2010, for $6,000,000 cash and 137,500 shares of our common stock which we valued at approximately $412,500. Included in the acquisition were four producing wells.

●  The State Line Field acquired in April 2010, for $15,000,000 cash and 625,000 shares of our common stock which we valued at approximately $1,875,000. Included in the acquisition were six producing wells and interests in 1240 acres.

●  Approximately 60,000 acres located in Banner and Kimball Counties, Nebraska and Laramie and Goshen Counties, Wyoming acquired in May, 2010 for $20,000,000 cash and 500,000 shares of our common stock which we valued at $1,500,000.

 ●  Approximately 33,800 net acres located in Laramie County and Goshen County, Wyoming, and Banner County, Kimball County, and Scotts Bluff County, Nebraska, and rights below the base of the Greenhorn on approximately 23,000 net acres in Laramie County and Goshen County, Wyoming, and Banner County and Kimball County, Nebraska, acquired in December, 2010.  These properties were undeveloped with no proved reserves or production. The purchase price was $8,000,000 in cash which was due to the sellers on or before December 20, 2010.  We issued 1,666,667 shares of our common stock as security against the cash payment, which were to be returned to us upon the cash payment.  We did not make the cash payment and the Davis entities kept the 1,666,667 shares of common stock. 

●  In November 2010, we completed a well located on a 640 acre oil and gas lease in Arapahoe County, Colorado known as Comanche Creek. We acquired 50% interests in this prospect and the Omega prospect in January 2010 from the Davis entities as part of the Wilke acquisition. We acquired an additional 12.5% working interest in the Comanche Creek prospect in June 2010 from Davis in exchange for a 1% overriding royalty interest on our existing 50% working interest, resulting in us owning a 62.5% working interest. The remaining 37.5% working interest is split between Davis and Timothy N. Poster, a member of our board of directors, with Davis holding 12.5% and Mr. Poster holding 25% of the working interest. The operations of the well are covered by a joint operating agreement and will require both Davis and Mr. Poster to pay their proportionate share of operating costs as well as an overhead/operating fee to us.

Hexagon, LLC.  We financed several of our acquisitions with loans from Hexagon, LLC.  Hexagon has the right to designate one member of our board of directors pursuant to a stockholders agreement.  Conway Schatz, who resigned from our board in January 2012, was designated by Hexagon.  Hexagon has not designated a replacement for Mr. Schatz.  Hexagon was not a related party prior to these loans.  The specific transactions with Hexagon are:

●  $4,500,000 loan in January 2010, to finance the purchase of the Wilke Field properties. The loan bears annual interest of 15%, will mature on June 30, 2013 and is secured by mortgages on the Wilke Field properties. Hexagon received 62,500 shares of our common stock in connection with the financing which we valued at approximately $2,250,000.

· $6,000,000 loan in March 2010, to finance the cash portion of the purchase price for the Albin Field properties. The loan bears annual interest of 15%, will mature on June 30, 2013 and is secured by mortgages on the Albin Field properties. In connection with the financing Hexagon received 46,875 shares of our common stock which we valued at approximately $562,500 and a one-half percent overriding royalty in the leases and wells acquired which we valued at $175,322.

· $15,000,000 loan in April 2010, to finance the cash portion of the purchase price for the Laramie County, Wyoming purchases.  The loan bears annual interest of 15%, will mature on June 30, 2013 and is secured by a mortgage on the acquired property. In connection with the financing Hexagon received 203,125 shares of our common stock which we valued at approximately $2,437,500, a warrant to purchase 125,000 shares of our common stock exercisable at $10.00 per share which we valued at approximately $184,589 and a one percent overriding royalty in the leases and wells acquired which we valued at $184,589.

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· In connection with the May 2010, acquisition of 60,000 acres from the Davis entities, we issued Hexagon Investments a five year warrant to purchase 62,500 shares of our common stock at $6.00 per share which we valued at approximately $369,153 as compensation for amendments to our credit agreements and agreed that if the loans were not repaid in full on or before January 1, 2011 we would issue Hexagon Investments a second five year warrant to purchase 62,500 shares of our common stock at $6.00 per share The loans remain outstanding, on January 1, 2011 and the warrant was issued to Hexagon which we valued at approximately $1,049,095.

· In November 2010, we entered into a Put Option Agreement with Grandhaven Energy, LLC whereby Grandhaven Energy has the right to require us to purchase for up to $2,400,000 25% of certain overriding royalty interests in undeveloped oil and gas leasehold in Laramie County it and several other purchasers acquired from the Davis entities.  The put option was exercisable until March 31, 2011 and expired unexercised.  Grandhaven Energy is an affiliate of Hexagon.  

· In December 2010, the maturity date of the Hexagon loans was extended to September 1, 2012, and in November 2011 the maturity date of the Hexagon loans was extended to January 1, 2013.  We did not pay any consideration for the extension.

· In November 2011 Hexagon loaned us $309,000 which was repaid in February 2012.

· In March 2012 the maturity date of the Hexagon loans was extended to June 30, 2013 and in connection therewith we agreed to make minimum monthly note payments of $325,000.

Convertible Debentures.  The Steven B. Dunn and Laura Dunn Revocable Trust and Wallington Investment Holdings, Ltd., each of whom owns more than 5% of our outstanding common stock, hold $2,000,000 and $4,110,000 respectively, aggregate principal amount of our outstanding Debentures.  

T.R. Winston

On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures. The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs. The Company amortized $0.01 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.22 million of deferred financing costs to be amortized through February 2014.

In December 2011, we issued 1,500,000 unregistered shares of our common stock to TRW Exploration, LLC to purchase oil and gas interests in 15,644 gross, 2,400 net acres in the Chugwater prospect located in Laramie County, Wyoming, including two horizontal wells drilled in that prospect and mutual releases in connection with termination of a joint venture with TRW Exploration.  Our board of directors approved the transaction which closed in December, 2011.  TRW Exploration was majority owned by several of our shareholders, at least one of whom owned more than 5% of our outstanding common stock at the time the shares were issued.

Under the December 2010 joint venture agreement, TRW Exploration paid us $2,000,000 for the purchase of an interest in the 2,400 net acres and also agreed to pay $7,100,000 of the drilling and completion costs of two horizontal wells to be drilled on the acreage in order to earn a 60% working interest in each well.  These two wells were drilled and completed in 2011 and are currently being evaluated as to their potential to sustain commercial production.  In addition to the $2,000,000 initial payment, TRW paid  $7,100,000 of the drilling and completion costs of the two wells. Upon termination of the joint venture, TRW sold back its interest in the wells along with all of its rights to the undeveloped acreage in consideration for the issuance by the Company of 1,500,000 shares of unregistered common stock that we valued at $4,875,000 and the mutual releases.

Conflict of Interest Policy

We have a corporate conflict of interest policy that prohibits conflicts of interests unless approved by the board of directors. Our board of directors has established a course of conduct whereby it considers in each case whether the proposed transaction is on terms as favorable or more to the Company than would be available from a non-related party. Our board also looks at whether the transaction is fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Each of the related party transactions was presented to our board of directors for consideration and each of these transactions was unanimously approved by our board of directors after reviewing the criteria set forth in the preceding two sentences. Each of our purchases from Davis was individually negotiated, and none of the transactions was contingent upon or otherwise related to any other transaction.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information with respect to beneficial ownership of our common stock as of January 18, 2013 by each of our executive officers and directors and each person known to be the beneficial owner of 5% or more of the outstanding common stock.  This table is based upon the total number of shares outstanding as of January 18, 2013 of 18,361,220.  Unless otherwise indicated, the persons and entities named in the table have sole voting and sole investment power with respect to the shares set forth opposite the stockholder’s name, subject to community property laws, where applicable. Beneficial ownership is determined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended. In computing the number of shares beneficially owned by a person or a group and the percentage ownership of that person or group, shares of our common stock subject to options or warrants currently exercisable or exercisable within 60 days after the date hereof are deemed outstanding, but are not deemed outstanding for the purpose of computing the percentage ownership of any other person. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Recovery Energy, 1900 Grant Street, Suite #720, Denver, CO 80203.

Name and Address of Beneficial Owner	Beneficially Owned			Percent of Class Beneficially Owned
Directors and Executive Officers
W. Phillip Marcum, Chief Executive Officer and Chairman of Board of Directors		128,096	(1)		0.70	%
A. Bradley Gabbard, President and Chief Financial Officer		100,375	(2)		0.55	%
Timothy N. Poster, Director		164,440			0.90	%
Bruce White, Director		100,000	(3)		0.55	%
D. Kirk Edwards, Director		132,627	(3)		0.72	%
Officers and directors as a group (six persons)		629,705	(4)		3.43	%
Roger A. Parker		25,000	(5)		0.14	%
Hexagon Investments, LLC		2,675,000	(6)		13.82	%
Labyrinth Enterprises LLC		2,675,000	(6)		13.82	%
Reiman Foundation		2,675,000	(6)		13.82	%
Scott J. Reiman		2,675,000	(6)		13.82	%
Steven B. Dunn and Laura Dunn Revocable Trust		1,293,546	(7)		6.78	%
J. Steven Emerson		1,261,657	(8)		6.87	%
Wallington Investment Holdings, Ltd		1,733,432	(9)		8.44	%

(1)	Does not include 33,333 shares of restricted stock subject to vesting, which will not vest within 60 days after the date hereof.
(2)	Does not include 107,292 shares of restricted stock subject to vesting, which will not vest within 60 days after the date hereof.
(3)	Does not include 50,000 shares of restricted stock subject to vesting, which will not vest within 60 days after the date hereof.
(4)	Does not include 278,125 shares of restricted stock subject to vesting, which will not vest within 60 days after the date hereof.
(5)	Does not include 1,350,000 shares of restricted stock subject to vesting, which will not vest within 60 days after the date hereof.
(6)	Includes (i) 1,250,000 shares owned by Hexagon, LLC, (ii) 1,000,000 shares underlying warrants held by Hexagon, (iii) 129,008 shares owned by Labyrinth Enterprises LLC, which is controlled by Scott J. Reiman, (iv) 245,992 shares owned by Reiman Foundation, which is controlled by Scott J. Reiman and (v) 50,000 shares owned by Scott J. Reiman. Mr. Reiman is President of Hexagon Investments. Based on a Schedule 13D filed on December 13, 2012.
(7)	Includes (i) 1,119,628 shares owned by Steven B. Dunn and Laura Dunn Revocable Trust (including 258,350 restricted shares), (ii) 86,959 shares owned by Beau 8, LLC, and (iii) 86,959 shares owned by Winston 8, LLC. Does not 713,242 shares issuable upon conversion of convertible securities, because such shares are not issuable within 60 days after the date hereof.  Steven B. Dunn and Laura Dunn, mailing address is 16689 Schoenborn Street, North Hills, CA 91343, are trustees of the Trust and also share voting and dispositive power with respect to the shares owned by the LLCs. Based on information received from a representative of Steven B. Dunn and Laura Dunn.
(8)	Includes (i) 710,000 shares owned by J. Steven Emerson Roth IRA, (ii) 236,657 shares owned by J. Steven Emerson IRA R/O II, (iii) 105,000 shares owned by Emerson Partners, (iv) 150,000 shares owned by J. Steven Emerson and (v) 60,000 shares owned by Emerson Family Foundation. J. Steven Emerson controls each of these entities. Based on information received from a representative of J. Steven Emerson.
(9)	Does not include 2,185,880 shares issuable upon conversion of convertible securities, because such shares are not issuable within 60 days after the date hereof. Based on information received from a representative of Wallington Investment Holdings, Ltd.

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DISCLOSURE OF COMMISSION POSITION ON INDEMNIFICATION FOR SECURITIES ACT LIABILITY

Indemnification

Our director and officer are indemnified as provided by the Nevada Revised Statutes and our Bylaws. We have agreed to indemnify each of our directors and certain officers against certain liabilities, including liabilities under the Securities Act. Insofar as indemnification for liabilities arising under the Securities Act may be permitted to our directors, officers and controlling persons pursuant to the provisions described above, or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than our payment of expenses incurred or paid by our director, officer or controlling person in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

At present, there is no pending litigation or proceeding involving any of our directors, officers, employees or agents where indemnification will be required or permitted. We are not aware of any threatened litigation or proceeding that might result in a claim for such indemnification.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling Recovery Energy, we have been informed that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. No dealer, sales person or any other person has been authorized in connection with this offering to give any information or to make any representations other than those contained in this prospectus and, if given or made, such information or representations must not be relied upon as having been authorized by us. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any of the securities offered hereby in any jurisdiction in which such offer or solicitation is not authorized or in which the person making such offer or solicitation is not qualified to do so or to any person to whom it is unlawful to make such an offer or solicitation. Neither the delivery of this prospectus nor any sale made hereunder shall, under any circumstances, create an implication that there has been no change in the circumstances of Recovery Energy or the facts herein set forth since the date hereof.

LEGAL MATTERS

Davis Graham & Stubbs LLP will pass upon the validity of the common stock on our behalf.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 with respect to the common stock offered by this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all the information set forth in the registration statement or the exhibits and schedules that are part of the registration statement. Statements made in this prospectus regarding the contents of any contract or other documents are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. In addition, we are required to file periodic and current reports and other information with the SEC by reason of the registration of our senior notes under the Securities Act. For further information pertaining to us and to the common stock offered by this prospectus, reference is made to the registration statement and those periodic and current reports, including the exhibits and schedules thereto, copies of which may be inspected without charge at the Public Reference Room of the SEC at 100 F Street N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for information regarding the operation of the Public Reference Room. In addition, the SEC maintains a web site that contains reports, proxy and information statements and other information that is filed electronically with the SEC. The web site can be accessed at www.sec.gov.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as of December 31, 2011 and December 31, 2010	F-2
Consolidated Statements of Operations for the years ended December  31, 2011 and December 31, 2010	F-4
Consolidated Statements of Shareholders’ Equity for the years ended December  31, 2011 and December 31, 2010	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2011 and December  31, 2010	F-6
Notes to Financial Statements for the year ended December 31, 2011	F-8 to F-31
Condensed Consolidated Balance Sheets as of and September 30, 2012 (unaudited) and December  31, 2011	F-32
Condensed Consolidated Statements of Operations for the nine months ended September 30, 2012 (unaudited) and September 30, 2011 (unaudited)	F-34
Condensed Consolidated Statements of Cash Flows for the nine months ended September  30, 2012 (unaudited) and September 30, 2011 (unaudited)	F-35
Notes to Financial Statements for the period ended September 30, 2012	F-36 to F-45

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Recovery Energy, Inc.

We have audited the accompanying consolidated balance sheets of Recovery Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the years ended December 31, 2011 and 2010 and for the period from March 6, 2009 (inception) through December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Recovery Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for the years ended December 31, 2011 and 2010, and for the period from March 6, 2009 (inception) through December 31, 2009, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Recovery Energy, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our report dated March 29, 2012expressed an opinion that Recovery Energy, Inc. had not maintained effective internal control over financial reporting as of December 31, 2011.

Hein & Associates LLP

Denver, Colorado

March 29, 2012

F-1

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

	December 31,			December 31,
	2011			2010
ASSETS
Current assets:
Cash	$	2,707,722		$	5,528,744
Restricted cash		932,165			1,150,541
Accounts receivable		2,227,466			857,554
Prepaid assets		75,376			27,772
Total current assets		5,942,729			7,564,611
Oil and gas properties (full cost method), at cost:
Unevaluated properties		45,697,481			33,605,594
Evaluated properties		32,113,143			26,307,975
Wells in progress		6,425,509			1,219,397
Total oil and gas properties, at cost		84,236,133			61,132,966
Less accumulated depreciation, depletion and amortization		(12,099,098	)		(5,003,499	)
Net oil and gas properties, at cost		72,137,035			56,129,467
Other assets:
Office equipment, net		106,286			51,129
Prepaid advisory fees		574,160			979,449
Deferred financing costs		2,341,595			3,211,566
Restricted cash and deposits		186,055			185,707
Total other assets		3,208,096			4,427,851
Total Assets	$	81,287,860		$	68,121,929

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

F-2

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

	December 31,			December 31,
	2011			2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	2,050,768		$	968,295
Commodity price derivative liability		75,609			398,840
Related party payable		16,475			11,638
Accrued expenses		1,354,204			1,540,592
Short-term note		1,150,967			208,881
Total current liabilities		4,648,023			3,128,246
Asset retirement obligation		612,874			507,280
Term-note payable		20,129,670			20,229,801
Convertible notes payable, net of discount		4,929,068			-
Convertible notes conversion derivative liability		1,300,000			-
Total long-term liabilities		26,971,612			20,737,081
Total liabilities		31,619,635			23,865,327
Commitments and contingencies – Note 8		-			-
Preferred stock, 10,000,000 authorized, none issued and outstanding as of December 31, 2011 and 2010.		-			-
Common stock subject to redemption rights, $0.0001 par value; 0 and 10,625 shares issued and outstanding as of December 31, 2011 and December 31, 2010, respectively		-			86,257
Common Stock, $0.0001 par value: 100,000,000 shares authorized; 17,436,825 and 14,453,592 shares issued and outstanding (excluding 0 and 10,625 shares subject to redemption) as of December 31, 2011 and December 31, 2010, respectively		1,744			1,445
Additional paid-in capital		118,146,119			93,819,314
Accumulated deficit		(68,479,638	)		(49,650,414	)
Total  shareholders' equity		49,668,225			44,170,345
Total liabilities and shareholders' equity	$	81,287,860		$	68,121,929

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

F-3

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31, 2011			Year Ended  December 31, 2010			March 6, 2009 (Inception) through December 31, 2009
Revenues:
Oil sales	$	7,148,110		$	9,504,737		$	-
Gas sales		547,190			68,075			-
Operating fees		117,360			13,487			-
Realized gain on price hedges		625,043			570,233			-
Unrealizedlosses price hedges		(75,609	)		(398,840	)		-
Total revenues		8,362,094			9,757,692			-
Costs and expenses:
Production costs		1,514,784			862,042			-
Production taxes		838,714			1,056,244			-
General and administrative (includes non-cash consideration of $6,656,152, $13,097,346, and $684,778 for the periods ended December 31, 2011, 2010 and 2009)		10,544,347			15,530,248			1,057,306
Depreciation, depletion,accretion, and amortization		4,347,117			5,036,648			-
Impairment of equipment		-			-			2,750,000
Impairment of evaluated properties		2,821,176			-			-
Bad debt expense		-			400,000			-
Fair value of common stock and warrants issued in aborted property acquisitions		-			-			8,404,106
Restructuring and related consulting costs		-			-			17,700,000
Total costs and expenses		20,066,138			22,885,182			29,911,412
Loss from operations		(11,704,044	)		(13,127,490	)		(29,911,412	)
Other income		71,253			-			-
Convertible notes conversion derivative gain		3,821,792			-			-
Interest expense (includes non-cash interest expense of $ 4,993,997, $3,989,649, and $0 for the periods ended December 31, 2011, 2010 and 2009)		(8,218,225	)		(6,640,209	)		31
Unrealized gain on lock-up		-			28,666			-
Debt inducement expense		(2,800,000	)		-			-
Net loss	$	(18,829,224	)	$	(19,739,033	)	$	(29,911,381	)
Earnings per common share
Basic and diluted	$	(1.21	)	$	(2.15	)	$	(12.19	)
Weighted average shares outstanding:
Basic and diluted		15,543,758			9,167,803			2,453,921

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

F-4

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

For the year ended December 31, 2011, December 31, 2010 and from March 6, 2009 (Inception) through December 31, 2009

	Common Stock
	Subject to Redemption						Common Stock
	Shares			Amount			Shares			Amount			Additional Paid-In Capital			Accumulated Deficit			Total
Balance, March 6, 2009 (Inception)	$	-			-			-		$	-		$	-		$	-		$	-
Common stock issued in reverse merger		-			-			524,750			52			(33,957	)		-			(33,905	)
Common stock issued in exchange of debt		-			-			525,000			53			3,249,790			-			3,249,843
Common stock issued in lock-up agreement		21,250			172,516			-			-			-			-			-
Common stock issued in restructuring		-			-			1,250,000			125			17,499,500			-			17,499,625
Common stock issued in attempted acquisition		-			-			425,000			43			5,824,830			-			5,824,873
Common stock issued for cash		-			-			31,250			3			499,988			-			499,991
Restricted stock and performance options issued to employees and directors		-			-			-			-			684,778			-			684,778
Warrants issued for financing commitment		-			-			-			-			3,329,106			-			3,329,106
Common stock reacquired in attempted acquisition		-			-			(62,500	)		(6	)		(749,975	)		-			(749,981	)
1:4 Reverse stock split		-			-			-			-			808			-			808
Net loss		-			-			-			-			-			(29,911,381	)		(29,911,381	)
Balance, December 31, 2009		21,250			172,516			2,693,500			269			30,304,868			(29,911,381	)		393,756
Common stock issued for property acquisitions		-			-			2,929,167			293			15,786,328			-			15,786,621
Common stock issued in connection with financing property acquisitions		-			-			1,250,000			125			5,249,500			-			5,249,625
Common stock issued for cash		-			-			3,978,789			398			14,924,142			-			14,924,540
Common stock issued for services		-			-			502,216			50			2,256,038			-			2,256,088
Restricted stock issued to employees and directors		-			-			2,235,797			223			8,375,327			-			8,375,550
Warrants exercised for cash		-			-			853,500			85			5,120,658			-			5,120,743
Warrants issued for cash, services and fees		-			-			-			-			11,712,671			-			11,712,671
Common stock no longer subject to redemption		(10,625	)		(86,258	)		10,625			1			86,258			-			86,258
1:4 Reverse stock split		-			-			-			-			3,525			-			3,525
Net loss		-			-			-			-			-			(19,739,033	)		(19,739,033	)
Balance, December 31, 2010		10,625			86,258			14,453,593			1,444			93,819,315			(49,650,414	)		44,170,344
1:4 Reverse stock split		-			-			-			-			387			-			387
Common stock issued for property acquisitions		-			-			2,269,543			228			10,895,665			-			10,895,893
Common stock no longer subject to redemption (1)		(10,625	)		(86,258	)		10,625			1			86,254			-			86,255
Common stock issued in connection with interest payment of the financing		-			-			78,982			8			559,863			-			559,872
Common stock issued for services		-			-			10,000			1			81,996			-			81,997
Restricted stock issued to employees and directors		-			-			238,750			24			6,161,041			-			6,161,065
Warrants issued for cash		-			-			375,333			38			2,129,801			-			2,129,804
Warrants issued for debt extension		-			-			-			-			1,611,797						1,611,832
Debt conversion expense		-			-			-			-			2,800,000			-			2,800,000
Net loss		-			-			-			-			-			(18,829,224	)		(18,829,224	)
Balance, December 31, 2011		-			-			17,436,825		$	1,744		$	118,146,119		$	(68,479,638	)	$	49,668,225

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

F-5

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended  December 31, 2011			Year Ended  December 31, 2010			March 6, 2009 (Inception) through December 31, 2009
Cash flows from operating activities:
Net loss	$	(18,829,224	)	$	(19,739,033	)	$	(29,911,381	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Impairment of equipment		-			-			2,750,000
Impairment of evaluated properties		2,821,176			-			-
Debt inducement and warrant modification expense		2,800,000			2,953,450			-
Common stock issued for convertible note interest		559,873			-			-
Bad debt expense		-			400,000			-
Common stock for services and  compensation		6,566,152			8,701,263			884,778
Fair value of warrants issued		-			-			3,329,106
Non-cash restructuring costs		-			-			17,500,000
Loss on aborted property acquisitions		-			-			5,075,000
Changes in the fair value of commodity price derivatives		(549,434	)		398,840			-
Compensation expense recognized for assignment of overrides		-			1,578,080			-
Amortization of deferred financing costs		4,446,911			3,989,649			-
Change in fair value of convertible notes conversion derivative		(3,821,792	)		-
Depreciation, depletion, and amortization and accretion of asset retirement obligation		4,347,117			5,036,648			-
Changes in operating assets and liabilities:
Accounts receivable		73,940			(757,554	)		(100,000	)
Restricted cash		218,376			(1,129,665	)		(20,876	)
Other assets		39,451			(34,066	)		15,627
Accounts payable and other accrued expenses		757,207			2,361,082			96,507
Net cash provided by (used in) operating activities		(570,247	)		3,758,694			(381,239	)
Cash flows from investing activities:
Additions of evaluated properties and equipment (net of purchase price adjustment)		-			(25,580,793	)		-
Acquisition of unevaluated properties		(9,433,073	)		(18,560,412	)		-
Drilling capital expenditures		(7,017,523	)		(4,637,111	)		-
Sale of unevaluated property interests		3,000,000			2,000,000			1,500,000
Sale of drilling rigs		-			100,000			-
Additions of office equipment		(83,727	)		(55,767	)		(750,470	)
Proceeds from hedge settlement		226,203			-			-
Investment in operating bonds		(348	)		(75,675	)		(109,891	)
Net cash provided by (used in) investing activities		(13,308,468	)		(46,809,758	)		639,639
Cash flows from financing activities:
Proceeds from sale of common stock, units and exercise of warrants		2,129,870			28,132,727			500,000
Proceeds from debt		9,411,597			28,500,000			-
Common stock reacquired in attempted Church acquisition		-			-			(750,000	)
Common stock issuable		-			(100,000	)		100,000
Payment of debt		(483,774	)		(8,061,319	)		-
Net cash provided by (used in) financing activities		11,057,693			48,471,408			(150,000	)
Net increase in cash and cash equivalents		(2,821,023	)		5,420,344			108,400
Cash and cash equivalents, beginning of period		5,528,744			108,400			-
Cash and cash equivalents, end of period	$	2,707,722		$	5,528,744		$	108,400

F-6

Supplemental disclosure of non-cash investing and financing activities:
Cash paid for interest	$	3,201,312	$	2,655,131	$	-
Cash paid for income taxes	$	-	$	-	$	-
Non-cash transactions:
Purchase of rigs for note payable	$	-	$	-	$	3,250,000
Sale of property for receivable	$	1,443,852	$	-	$	-
Debt issuance cost	$	400,000	$	-	$	-
Purchase of properties for common stock	$	10,895,893	$	15,787,500	$	8,025,000
Stock and warrants issued for deferred financing costs	$	1,611,832	$	6,867,735	$	-
Stock and warrants issued for prepaid financial advisory fees	$	-	$	1,234,510	$	-
Stock and warrants issued for prepaid financial office rent	$	81,997	$	-	$	-
Default on note in property acquisition	$	-	$	-	$	(2,200,000	)
Property additions for asset retirement obligation	$	61,469	$	479,238	$	-
Stock issued for payment on  long-term debt	$	559,872	$	-	$	-

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

F-7

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – ORGANIZATION

On September 21, 2009, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC (“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to Recovery Energy, Inc. (“Recovery”, “Recovery Energy”, “we”, “our”, and the “Company”). The Agreement was accounted for as a reverse acquisition with Coronado being treated as the acquirer for accounting purposes. Accordingly, the financial statements of Coronado have been adopted as the historical financial statements of Recovery.

The Company is an independent oil and gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 130,000 net acres.  Recovery drills for, operates and produces oil and natural gas wells through the Company’s land holdings located in Wyoming, Colorado, and Nebraska.

All common stock share information is retroactively adjusted for the effect of a 4:1 reverse stock split that was effective October 19, 2011.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

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

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

Use of Estimates in the Preparation of Financial Statements

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

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

Principle 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.  Both subsidiaries were inactive and were dissolved in the 4th quarter of 2011.

Liquidity

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

F-8

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

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

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

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks and highly liquid debt securities which have original maturities of 90 days or less at the purchase date.

Restricted Cash

Restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities and amounts 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. The Company did not record any allowance for uncollectible receivables for years ended December 31, 2011or December 31, 2010.  Receivables which derive from sales of certain oil and gas production are collateral for our Loan Agreements (see Note 7).

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

Assets Held For Sale

Assets held for sale are recorded at the lower of cost or estimated net realizable value. As of December 31, 2011 and 2010, the Company did not have any assets held for sale.

F-9

Concentration of Credit Risk

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

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

Significant Customers

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

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.

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

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

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

Unproved Properties

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

F-10

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 December 31, 2011, the Company had two wells in progress, both of which have been drilled and completed and are pending evaluation as to their potential to produce commercial quantities of oil and gas reserves.

Deferred Financing Costs

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

Prepaid Advisory Fees

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

The following schedule details the future expense of the prepaid advisory fees.

2012	$	405,289
2013		168,871
Total	$	574,160

Property and Equipment

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

Impairment of Long-lived Assets

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

F-11

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

Fair Value of Financial Instruments

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

Commodity Derivative Instrument

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

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

Revenue Recognition

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

Asset Retirement Obligation

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

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

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

F-12

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

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

Share Based Compensation

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

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

Warrant Modification Expense

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

Loss per Common Share

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

F-13

Income Taxes

For tax reporting, the Company continues to file its tax returns on an April 30 year end, which is the legal tax year end of its predecessor.  

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

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

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

Recently Issued Accounting Pronouncements 

The Company did not adopt any new authoritative guidance for the year ended December 31, 2011 that had a material impact on its financial statements.

NOTE 3 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS AND DIVESTITURES

DJ Basin Properties Acquisitions – Accounted for as a Business Combination

During the fourth quarter of 2009, the Company pursued a number of acquisition opportunities.  The Company entered into two purchase and sale agreements with Edward Mike Davis, LLC and affiliates (“Davis”) for the purchase of multiple oil and gas properties.  The Company was not successful in fulfilling the requirements under the purchase and sale agreements and forfeited 1,450,000 shares of our common stock with an estimated fair value of $5,075,000.

In January 2010, the Company acquired the Wilke Field from Davis for $4,500,000.   The Company simultaneously entered into a credit agreement with Hexagon to finance 100% of the purchase of the Wilke Field properties.  Hexagon received 1,000,000 shares of the Company's common stock in connection with the financing.  The Company recorded $2.25 million in deferred financing costs related to the shares issued in conjunction with the loan (see Note 7).  

In March 2010, the Company acquired the Albin Field properties from Davis for $6,000,000 and 550,000 shares of common stock with an estimated fair value of $412,500. The Company simultaneously entered into a loan agreement with Hexagon to finance 100% of the cash portion of the purchase price.  The Company recorded approximately $737,822 in deferred financing costs related to 750,000 shares of the Company’s common stock and a one-half percent overriding royalty in the leases and wells in connection with the financing from Hexagon (see Note 7).    

F-14

In April 2010, the Company acquired the State Line Field properties from Davis for $15,000,000 and 2,500,000 shares of common stock with an approximate fair value of $1,875,000. The Company simultaneously entered into a loan agreement with Hexagon to finance 100% of the cash portion of the purchase price. The Company recorded approximately $2,780,775 in deferred financing costs related to 3,250,000 shares of the Company’s common stock, 2,000,000 warrants to acquire the Company’s common stock at $2.50 per share and a one percent overriding royalty interest in connection with the financing from Hexagon (see Note 7).

All three of the acquisitions above were recorded at their fair values as of the acquisition date. The following table summarizes the fair values of assets acquired and liabilities assumed for each acquisition as of the related acquisition date:

	Wilke Field			Albin Field			State Line Field
Consideration given:
Cash payment funded by debt	$	4,500,000		$	6,000,000		$	15,000,000
Stock		-			412,500			1,875,000
Total consideration attributable to allocation	$	4,500,000		$	6,412,500		$	16,875,000
Allocation of purchase price:
Proved oil and gas properties	$	4,418,267		$	4,675,099		$	15,529,268
Unproved oil and gas properties		83,200			1,791,619			1,070,975
Total fair value of oil and gas properties acquired		4,501,467			6,466,718			16,600,243
Oil and gas revenue receivable		195,594			-			-
Total assets		4,697,061			6,466,718			16,600,243
Accounts payable		-			-			(52,147	)
Asset retirement obligation		(197,061	)		(54,218	)		(149,151	)
Total liabilities acquired		(197,061	)		(54,218	)		(201,298	)
Net assets acquired	$	4,500,000		$	6,412,500		$	16,398,945
Supplemental information:
Value attributable to ORRI paid to lender	$	-		$	(175,322	)	$	(158,685	)
Value attributable to ORRI awarded to management	$	(125,220	)	$	(701,290	)	$	(317,370	)

The following unaudited supplemental pro forma information presents the results of operations for the years ended December 31, 2010 and 2009, as if the Wilke, Albin, and State Line acquisitions had occurred as of the earliest period presented, January 1, 2009. These unaudited pro forma results of operations are based on the historical financial statements and related notes of the Company, and the related historical audited statements of revenue and direct expenses for the Wilke, Albin and State Line acquisitions included in the related filings on Form 8-K. These pro forma results of operations contain adjustments to depreciation, depletion and amortization for the effects of purchase price allocation, and to interest expense and amortization of deferred financing costs related to financing the acquisitions. The pro forma results are presented for informational purposes only and are not necessarily indicative of what actually would have occurred if the acquisitions had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

F-15

	For the Year Ended December 31,
	2010			2009
	(Unaudited)			(Unaudited)
Operating revenues	$	12,941,108		$	6,070,500
Operating loss	$	(10,599,304	)	$	(29,001,745	)
Net loss	$	(19,063,015	)	$	(33,489,536	)
Pro forma loss per common share:
Basic and diluted	$	(2.08	)	$	(12.92	)

Also in May 2010, the Company acquired additional undeveloped leasehold acreage and certain overriding royalty interests on existing Company owned acreage and wells in the DJ Basin from Davis for 2,000,000 shares of common stock valued at $1,500,000 and a cash payment of $20 million.

In August 2010, the Company farmed into approximately 240 net acres in exchange for carrying Davis, the lease owner, for a 26% working interest in one well, which has been drilled. The Company also farmed into approximately 533 net acres in the state of Nebraska in exchange for carrying Davis, the lease owner, for a 33% working interest in one well which has been drilled.

In November 2010, the Company purchased certain oil and gas interests of approximately 33,800 net acres located in Laramie County and Goshen County, Wyoming, and Banner County, Kimball County, and Scotts Bluff County, Nebraska from Davis. Additionally, the Company acquired rights below the base of the Greenhorn on approximately 23,000 net acres in Laramie County and Goshen County, Wyoming, and Banner County and Kimball County, Nebraska.  The Company issued 6,666,667 shares of our common stock to acquire the property with an estimated fair value of approximately $12,000,000.

In December 2010, the Company entered into an acquisition and development agreement with TRW Exploration, LLC (a related party, see note 9) whereby TRW paid $2,000,000 for the purchases of an interest in approximately 2,000 net undeveloped acres and also agreed to carry the Company’s 40% interest in two horizontal wells to be drilled on lands defined by the agreement. TRW subsequently funded the drilling and completion costs of two horizontal wells on the lands covered by the leases, at a total cost of approximately $7 million. This agreement was terminated in December, 2011 and TRW sold back its interest in the wells along with all of its rights to the undeveloped acreage, in consideration for the issuance by the Company of 1,500,000 shares of unregistered common stock valued at $4,875,000. Additional amounts were incurred in drilling the wells and were paid by the Company. The Company allocated $2 million of this purchase price to the undeveloped leases, and the remainder to the purchase of the two wells.

The two wells are in progress and currently being evaluated as to their potential to establish commercial production of oil and gas. These wells are carried as wells in progress as of December 31, 2011 at a total cost of $6.4 million.

F-16

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 shares of common stock valued at $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.

DJ Basin Properties Divestitures

Effective December 31, 2011 the Company sold 2,838 net acres of undeveloped leases for consideration of approximately $4.5 million.  A gain of $1.8 million related to the sale of this acreage was applied as a credit to the carrying costs of evaluated oil and gas properties.

Depreciation, depletion and amortization (“DD&A”) expenses related to the proved properties were  approximately $4,274,215 and $5,036,000 for the years ended December 31, 2011 and December 31, 2010, respectively. During the year ended December 31, 2011, the company impaired the carrying costs of its evaluated oil and gas properties by $2.8 million as a result of an excess of carrying costs above the applicable ceiling threshold. Prior to January 1, 2010, the Company did not own any oil and gas properties therefore we did not incur DD&A expense in 2009.

The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized as of December 31, 2011:

	As of  December 31, 2011
Leasehold acquisitions
2010		$	33,605,594
2011			12,091,887
Unevaluated properties			45,697,481
Wells in progress exploration  2011			6,425,509
Total		$	52,122,990

The Company plans to evaluate exploration costs (wells-in progress) in 2012 and will likely develop, sell or reclassify to evaluated properties its inventory of unevaluated leasehold over the next three years.   Included in its inventory of unevaluated leases are certain undeveloped leases with an approximate carrying value of $11 million that are being held and extended by the conducting of continuous operations on the two wells in progress. If commercial production is not eventually established in one or both of the two wells in progress, some or all of these leases may expire, and require such cases to be reclassified to evaluated property and subject to the Company’s full cost lid calculation.

NOTE 4 – WELLS IN PROGRESS

The following table reflects the net changes in capitalized additions to wells in progress during 2010 and 2009:

F-17

	For the Year Ended December 31,
	2011			2010
Beginning balance	$	1,219,254			-
Additions to capital wells in progress costs		8,904,532			1,219,254
Reclassifications to proved properties		(3,698,563	)		-
Ending balance	$	6,425,509		$	1,219,254

All wells in progress have been capitalized for less than one year.

NOTE 5 - FINANCIAL INSTRUMENTS AND DERIVATIVES

Periodically, the Company enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. During the year ended December 31, 2011, the Company terminated and settled certain future commodity swaps resulting in a realized gain of approximately $625,000.

As of December 31, 2011, the Company maintained an active commodity swap for 100 barrels per day through December 31, 2012, at a price of $96.25 per barrel.

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

	For the Year Ended December 31,
	2011			2010			2009(1)
Realized gain on oil price hedges	$	625,043		$	570,233		$	-
Unrealized loss oil price hedges	$	(75,609	)	$	(398,840	)	$	-

(1)   Prior to January 1, 2010, the Company did not enter any derivative financial instruments. 

Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are recognized in the unrealized gain (loss) on hedge contracts line on the consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the realized gain (loss)  line on the consolidated statement of income. As of December 31, 2011, the Company recorded an unrealized loss on its only active swap of $75,609.

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value:

● Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

● Level 2 – Include other inputs that are directly or indirectly observable in the marketplace.

● Level 3 – Unobservable inputs which are supported by little or no market activity.

The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

F-18

The Company measures its cash equivalents and investments at fair value. The Company’s cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits are primarily classified within Level 1. Cash equivalents and short-term investments are valued primarily using quoted market prices utilizing market observable inputs.

Derivative Instruments

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

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

At December 31, 2011, the types of derivative instruments utilized by the Company included commodity swaps (see Note 5). The oil derivative markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange.  As such, the Company has classified these instruments as Level 2.

Asset Retirement Obligation

The income valuation technique is utilized determine the fair value of its asset retirement obligation liability at the point of inception by taking into account 1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which is based on estimates from reserve engineers; 3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.

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 (“Debentures”) with a group of accredited investors. As of December 31, 2011, the Debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $4.25 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 Company engaged a third party to complete a valuation of this conversion feature as of December 31, 2011 (see Note 7). The valuation was completed using Level 3 inputs.

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

December 31, 2011

	Level 1		Level 2			Level 3			Total
Liability
Derivative instruments	$	-	$	(75,609	)	$	-		$	(75,609	)
Convertible notes payable  Conversion feature		-		-			(1,300,000	)		(1,300,000	)
Total liability at fair value	$	-	$	(75,609	)	$	(1,300,000	)	$	(1,375,609	)

F-19

December 31, 2010

	Level 1		Level 2			Level 3		Total
Liability
Derivative instruments	$	-	$	(398,840	)	$	-	$	(398,840	)
Total liability at fair value	$	-	$	(398,840	)	$	-	$	(398,840	)

The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of December 31, 2011:

	Convertible debt feature (1)
Beginning balances, December 31, 2010		-
Additions of convertible debt feature		(1,300,000	)
Ending balance as of December 31, 2011		(1,300,000	)

(1)   The Company entered into the convertible debt during the year ended December 31, 2011.

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 twelve months ended December 31, 2011 and December 31, 2010.

NOTE 7 - 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 June 30, 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.

F-20

In December 2010, Hexagon extended the maturity to September 1, 2011. During the last half of 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2 million as payment on the notes. In November 2011, Hexagon extended the maturity to January 1, 2013.  In March 2012, Hexagon agreed to extend the maturity of the notes to June 30, 2013, and in connection there with, the Company agreed to make minimum monthly note payments of $325,000, effective immediately.  In November 2011, Hexagon also temporarily advanced the Company an additional amount of $309,000, which was repaid in full in February 2012.

The Company is subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements. As of December 31, 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 completed a private placement of $8,400,000 aggregate principal amount of three year 8% Senior Secured Convertible Debentures (the "Debentures") with a group of accredited investors. Initially, the Debentures were 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.  The Company is amortizing the $400,000 over the life of the loan as deferred financing costs.  The Company amortized $88,888 of deferred financing costs into interest expense during the year ended December 31, 2011 and has $311,112 of deferred financing costs to be amortized over a straight-line basis until January 2014.

In December, 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share. Therefore, the Debenture are currently convertible into shares of common stock. This amendment was consideration to the Debenture holders in exchange for their agreement to release a mortgage on certain properties so the properties could be sold. The sale of these properties was completed effective December 31, 2011.

The Company engaged a third party valuation firm to complete a valuation of both the conversion feature and the inducement. This valuation resulted in an estimate of the inducement expense of $2.8 million and estimate of the derivative liability as of December 31, 2011 of $1.3 million. A previous independent valuation of the derivative liability estimated the derivative liability as of March 31, 2011 at approximately $5.1 million. The reduction in the derivative value from $5.1 million as of March 31, 2011 to $1.3 million as of December 31, 2011 resulted in a derivative gain of $3.8 million during the year ended December 31, 2011. As of December 31, 2011, the convertible debt is recorded as follows:

	As of  December 31, 2011
Convertible debt		8,400,000
Debt discount		(3,470,932	)
Total convertible debt, net		4,929,068

F-21

Annual debt maturities for our debt under our term notes and convertible notes payable obligations as of December 31, 2011 are as follows:

2012	1,150,966
2013	20,129,670
2014	8,400,000
Thereafter	--
Total	29,680,636

Interest Expense

For the years ending December 31, 2011 and December 31, 2010, the Company incurred interest expense of approximately $8,218,000 and $6,600,000, respectively, of which approximately $5.0 million and $4.0 million, respectively, were 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.

NOTE 8 - COMMITMENTS and CONTINGENCIES

Environmental and Governmental Regulation

At December 31, 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 December 31, 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.

Operating Leases

The Company leases an office space under a one year operating lease in Denver, Colorado.  Rent expense for the years ended December 31, 2011 and December 31, 2010, was $82,068 and $54,500, respectively. The Company will have minimum lease payments of $72,000 for the year ending December 31, 2012.

F-22

NOTE 9 - RELATED PARTY TRANSACTIONS

Since its inception, five property acquisitions the Company completed have been with the same seller, Davis.  As of December 31, 2011, Davis owned approximately 19.1 % of the common stock of the Company. The cash portion of the purchase price for the first three acquisitions was financed with loans from Hexagon, which owned approximately 15.7% of the stock issued and outstanding at December 31, 2011.  Hexagon received overriding royalty interests in both the Albin Field assets and the State Line Field assets. Hexagon also received warrants to purchase 500,000 shares of the Company’s common stock at $10.00 per share in connection with the financing of an acquisition and warrants to purchase 250,000 shares the Company’s common stock for $6.00 per share in connection with amendments to the loan agreements. A representative of Hexagon also served on the Company’s Board of Directors, until his resignation on January 31, 2012.

The Company entered into an exploration and development agreement with TRW to drill two wells.  The joint venture partners of TRW are also shareholders of the Company.

NOTE 10 - INCOME TAXES

The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2011 and 2010 were:

	2011			2010
Deferred tax assets:
Oil and gas properties and equipment	$	(515,123	)	$	(1,335,490	)
Net operating loss carry-forward		11,291,513			7,285,426
Share based compensation		4,675,241			3,902,007
Abandonment obligation		205,145			188,728
Derivative instruments		176,514			148,384
Other		(91,304	)		(30,896	)
Total deferred tax asset		15,741,986			10,158,159
Valuation allowance		(15,741,986	)		(10,158,159	)
Net deferred tax asset	$	-		$	-

Reconciliation of the Company’s effective tax rate to the expected federal tax rate is:

	2011			2009
Effective federal tax rate		35.00	%		35.00	%
Effect of permanent differences		-7.54	%		-21.78	%
State tax rate		2.20	%		2.20	%
Change in rate		0.00	%		-0.23	%
Other		0.00	%		3.07	%
Valuation allowance		-29.66	%		-18.26	%
Net		0	%		0	%

F-23

At December 31, 2011 and 2010, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $25,957,000 and $19,582,000, respectively,that may be offset against future taxable income. The Company has established a valuation allowance for the full amount of the deferred tax assets as management does not currently believe that it is more likely than not that these assets will be recovered in the foreseeable future. To the extent not utilized, the net operating loss carry-forwards as of December 31, 2011 will expire in 2031.

NOTE 11 - SHAREHOLDERS’ EQUITY

As of December 31, 2011, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 17,436,825 shares of common stock were issued and outstanding. No preferred shares were issued or outstanding. Preferred shares may be issued in such series as Preferred as determined by the Board of Directors. No lock-up or restricted shares were outstanding as of December 31, 2011.

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

In December 2011, the Company provided the 8% convertible debenture holders an inducement to convert their conversion price from $9.40 to $4.25.  An inducement expense of $2.8 million was recognized in 2011. This transaction also increased additional paid-in capital by $2.8 million.  This reduction in conversion price also increased potential dilutive shares outstanding as of December 31, 2011 by 1,082,854 shares from 893,617 to 1,926,471 shares reserved for possible conversion.

In connection with this inducement, the Company entered into an amendment to our 8% senior secured convertible debentures whereby, in addition to the inducement, the mortgage on certain of the Company's oil and gas leases was released and in substitution, we granted a lien on certain replacement oil and gas leases in Nebraska and Wyoming. As partial consideration for the substitution of this collateral, the amendment also provides the holders of the debentures with the first right of refusal to purchase up to 15% of any common stock, preferred stock or convertible debt offering by Recovery through December 31, 2012 at the offering price.

During the year ending December 31, 2011, the Company issued 2,983,233 shares of common stock. The stock issuances were comprised of 2,983,233 shares issued for acquisitions valued at $10,896,071, 10,000 shares issued for services valued at $82,000, 238,824 shares issued as restricted stock grants to employees valued at $6,161,111, 78,972 shares is for interest expense on the convertible notes payable valued at $559,860, 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 current conversion price of $4.25 per share, these notes would convert into 1,976,471 shares of common stock. The conversion price is subject to other adjustments (See Note 7).

During the year ended December 31, 2010, the Company issued 11,749,467 shares of common stock.  The stock issuances were comprised of 2,929,167 shares issued for acquisitions valued at $15,787,500, 502,216 shares issued for services valued at $2,256,239, 1,250,000 shares issued in connection with the loan agreements valued at $5,250,000, 2,235,797 shares issued as restricted stock grants to employees valued at $10,283,622, and 3,978,788 shares issued for $20,046,733 of cash.

During the year ended December 31, 2010, the Company issued common shares for cash. Included in these shares was a private placement of 3,975,300 units at $1.50 per unit, which included one share of common stock and one common stock purchase warrant. The warrants are exercisable at $1.50 per share through May 23, 2015. Warrants of 853,500 were subsequently exercised during 2010 for $5,121,000 of cash. In connection with the exercise, the Company granted a new warrant for each warrant exercised. The new warrants have an exercise price of $8.80 per share, which was slightly greater than the concurrent market price of the Company's common stock, and expire on September 29, 2015. The value of the new warrants, calculated at $2,953,450 using the Black Scholes method, was expensed as a warrant modification and included in general and administrative expenses.

F-24

Temporary Equity

As part of the reverse merger in 2009, 5,313 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 5,313 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 2,658 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 2,658 shares covered under the lock-up agreement were moved to permanent on equity. 

Warrants

During 2010, the Company issued common shares for cash. Included in these shares was a private placement of 15,901,200 units at $1.50 per unit, which included one share of common stock and one common stock purchase warrant. The warrants are exercisable at $1.50 per share through May 23, 2015. 3,414,000 of these warrants were subsequently exercised during 2010 for $5,121,000 of cash. In connection with the exercise, the Company granted a new warrant for each warrant exercised. The new warrants have an exercise price of $2.20 per share, which was slightly greater than the concurrent market price of the Company's common stock, and expire on September 29, 2015. The value of the new warrants, calculated at $2,953,450 using the Black Scholes method, was expensed as a warrant modification and included in general and administrative expenses

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 Note7).

A summary of warrant activity for the years ended December 31, 2011 and December 31, 2010 is presented below:

	Warrants (1)			Weighted-Average  Exercise  Price (1)
Outstanding at December 31, 2009		187,500		$	14.00
Granted		6,430,233			6.68
Exercised, forfeited, or expired		(853,500	)		6.00
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 December 31, 2011		5,638,900		$	6.33

(1)   On October 17, 2011, the Company performed a 4:1 reverse stock split.  The values shown are reflecting the reverse stock split.

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 December 31, 2011 and December 31, 2010, respectively, and the weighted average remaining contract life was 3.68 years and 4.15 years.  

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

F-25

	For the years ended December 31,
	2011			2010
Weighted-average volatility		97	%		80	%
Expected dividends		0.00	%		0.00	%
Expected term (in years)		3 – 5			3 – 5
Risk-free rate		2.02	%		1.49	%

The Company has not adopted a stock incentive plan for its management team.  Members of the board of directors and the management team are periodically awarded restricted stock grants. 

NOTE 12 - SHARE BASED COMPENSATION

The costs of employee services received in exchange for an award of equity instruments are 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.

During the year ended December 31, 2011, the Company granted 238,750 shares of restricted common stock to employees of which 207,016, vest during the year ended December 31, 2011. The Company will vest restricted stock of 192,000, 120,000, and 2,500 for the years ending December 31, 2012, 2013, and 2014, respectively. The fair value of these share grants was calculated to be approximately $4,370,808.

The Company recognized stock compensation expense of approximately $6,161,000, $917,000 and $2,714,000 for the years ended December 31, 2011, 2010 and 2009, respectively. During the year ended December 31, 2011, the Company had a one-time charge of $3,551,000 for stock compensation expense with the grant of 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 year ended December 31, 2011 is presented below

	Shares (1)
Outstanding at March 6,2009	$	-
Granted		371,050
Vested		-
Outstanding at December 31, 2009		371,050
Granted		1,864,747
Vested		-
Outstanding at December 31, 2010		2,235,797
Granted		932,500
Vested		(828,062	)
Outstanding at December 31, 2011	$	2,340,235

(1)   On October 17, 2011, the Company affected a 4:1 reverse stock split.  The values shown are reflecting the reverse stock split.

The Company will recognize $1,066,000, $366,615 and $12,478 for the years ending December 31, 2012, 2013, and 2014, respectively.

F-26

NOTE 13 – DRILLING RIGS

In May 2009, two drilling rigs were contributed to the Company for a note of $3,250,000.  These rigs were recorded at estimated fair value as this was lower than their predecessor cost basis. The note holder subsequently converted the note for 2,100,000 shares of common stock (Note 3).  These rigs required certain capital improvements prior to their ability to be functional in operations.

In 2009, management determined that future drilling operations were not part of their strategic plans.  Management estimated the net realizable value to be $500,000; therefore, an impairment of $2,750,000 was recorded for the period ending December 31, 2009. 

In May 2010, the Company entered into a purchase and sale agreement for the rigs.  The Company sold the rigs for $700,000 under which the Company received $100,000 in cash and the balance in a five-year secured note. The acquirer defaulted on the note and the Company is now pursuing the remedies afforded to it under the note and security agreement.  The Company believes it is in a first lien position on the underlying collateral, however, in 2010 the Company elected to fully reserve the $400,000 note receivable as the ability to recover the amount and the value of the underlying collateral was uncertain.

NOTE 14: SUBSEQUENT EVENTS

On March 19, 2012, the Company entered into agreements with its existing convertible debenture holders to extend the amount of its debenture debt by up to an additional $5.0 million. Proceeds resulting from the increase in the debentures will be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other working capital purposes. Any new producing properties that are developed from the proceeds of this offering will be pledged as collateral to secure the expanded debt.

The initial closing related to these agreements will be in the amount of $1.5 million and is expected to occur prior to March 23, 2012. On or before September 15, 2012, convertible debenture holders may elect to purchase up to an additional $3.5 million in additional debentures. All terms of the expansion convertible debentures are substantively identical to the existing convertible debentures (see Note 7).

NOTE 15- SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The following table sets forth information for the years ended December 31, 2011, 2010 and 2009 with respect to changes in the Company's proved (i.e. proved developed and undeveloped) reserves:

	Crude Oil (Bbls)			Natural Gas  (Mcf)
December 31, 2009		-			-
Purchase of reserves		643,955			-
Revisions of previous estimates		123,679			-
Extensions and discoveries		58,463			323,493
Sale of reserves		-			-
Production		(133,709	)		(14,914	)
December 31, 2010		692,388			308,579
Purchase of reserves		-			-
Revisions of previous estimates		(268,718	)		(44,919	)
Extensions, discoveries		266,000			-
Sale of reserves
Production		(81,433	)		(115,583	)
December 31, 2011		608,237			148,077
Proved Developed Reserves, included above:
Balance, December 31, 2009		-			-
Balance, December 31, 2010		277,669			308,579
Balance, December 31, 2011		215,693			148,077
Proved Undeveloped Reserves, included above:
Balance, December 31, 2009		-			-
Balance, December 31, 2010		414,719			-
Balance, December 31, 2011		392,545			-

F-27

The Company did not have any reserves as of December 31, 2009.

As of December 31, 2011 and December 31, 2010, we had estimated proved reserves of 608,237 and 692,388 barrels of oil, respectively and 24,680 and 308,579 thousand cubic feet ("MCF") of natural gas, respectively.  Our reserves are comprised of 96% and 93% crude oil and 4% and 7% natural gas on an energy equivalent basis.

The following values for the December 31, 2011 and December 31, 2010 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31 natural gas price of $3.96 and $4.39 per MMBtu (NYMEX price) and crude oil price of $88.16 and $77.78 per barrel (West Texas Intermediate price). All prices are then further adjusted for transportation, quality and basis differentials.

During the years ended December 31, 2010, the Company completed multiple acquisitions which included proved reserves associated with producing properties. Included in the Company's December 31, 2010 proved reserves classified as 'Purchase of reserves' in the table above, are $3,760,000 and 643,955 barrels of crude oil attributable to the acquisitions.

The following summary sets forth the Company's future net cash flows relating to proved oil and gas:

	For the Year Ended December 31, (in thousands)
	2011			2010			2009 (1)
Future oil and gas sales	$	55,295		$	51,816		$	-
Future production costs		(16,579	)		(11,614	)		-
Future development costs		(8,481	)		(8,063	)		-
Future income tax expense (2)		-			-			-
Future net cash flows		30,235			32,139			-
10% annual discount		(10,221	)		(8,544	)		-
Standardized measure of discounted future net cash flows	$	20,014		$	23,595		$	-

(1) Prior to January 2010, the Company did not own any oil and gas assets.

(2) Our calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all years reported. We expect that all of our Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company's operations, and resulting NOLs, are attributable to our oil and gas assets. There were no taxes in any year as the tax basis and NOL's exceeded the future net revenue.

F-28

The principle sources of change in the standardized measure of discounted future net cash flows are:

	2011			2010			2009 (1)
Balance at beginning of period	$	23,595		$	-		$	-
Sales of oil and gas, net		(5,342	)		(7,655	)		-
Net change in prices and production costs		8,006			3,084			-
Net change in future development costs		-			(4,563	)		-
Extensions and discoveries		5,883			5,067			-
Acquisition of reserves					18,967			-
Sale of reserves					-			-
Revisions of previous quantity estimates		(14,804	)		5,245			-
Previously estimated development costs incurred					-			-
Net change in income taxes					-			-
Accretion of discount		2,360			2,043			-
Other		316			1,407			-
Balance at end of period	$	20,014		$	23,595		$	-

Revisions in 2011 of previous quantity estimates relate principally to the exclusion of certain proven undeveloped well locations that were included in the reserve estimates dated December 31, 2010.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

F-29

NOTE 16- QUARTERLY RESULTS (UNAUDITED)

The following tables contain selected unaudited statement of operations information for each quarter of 2011 and 2010. The Company believes that the following information reflects all normal recurring adjustments necessary for a fair presentation of the information for the periods presented. The operating results for any quarter are not necessarily indicative of results for any future period.

	Year Ended December 31, 2011
	Fourth				Third				Second				First
	Quarter				Quarter				Quarter				Quarter
Revenues		$	1,944,454			$	2,630,933			$	2,811,429			$	1,273,675
Income (loss) from operations			(6,297,854	)			(939,330	)			(4,069,541	)			(2,052,133	)
Net earnings (loss)			(7,295,537	)			(3,027,618	)			(4,762,881	)			(3,743,187	)
Net earnings per common share:
Basic and diluted		$	(0.47	)		$	(0.19	)		$	(0.30	)		$	(0.25	)
Weighted average shares outstanding
Basic and diluted			15,543,758				15,775,135				15,635,346				14,778,206

F-30

	Year Ended December 31, 2010
	Fourth				Third				Second				First
	Quarter				Quarter				Quarter				Quarter
Revenues		$	1,519,702			$	2,552,790			$	5,194,849			$	490,351
Income (loss) from operations			(4,191,728	)			(5,900,630	)			(792,880	)			(2,242,252	)
Net earnings (loss)			(6,230,293	)			(7,491,246	)			(3,196,779	)			(2,820,715	)
Net earnings per common share:
Basic and diluted		$	(1.47	)		$	(2.53	)		$	(1.99	)		$	(1.04	)
Weighted average shares outstanding
Basic and diluted			9,167,803				2,962,882				6,362,922				2,927,759

F-31

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30,			December 31,
	2012			2011
Assets
Current assets
Cash	$	698,276			$	2,707,722
Restricted cash		949,618				932,165
Accounts receivable		1,217,181				2,227,466
Prepaid assets		96,671				75,376
Commodity price derivative receivable		370,000				-
Total current assets		3,331,746				5,942,729
Oil and gas properties (full cost method), at cost:
Unevaluated properties		43,541,930				45,697,481
Evaluated properties		40,460,933				32,113,143
Wells in progress		3,986,919				6,425,509
Total oil and gas properties, at cost		87,989,782				84,236,133
Less accumulated depreciation, depletion ,amortization, and impairment		(18,174,968	)			(12,099,098	)
Net oil and gas properties, at cost		69,814,814				72,137,035
Other assets:
Office equipment, net		95,980				106,286
Prepaid advisory fees		304,402				574,160
Deferred financing costs, net		1,026,192				2,341,595
Restricted cash and deposits		186,240				186,055
Total other assets		1,612,814				3,208,096
Total assets	$	74,759,374			$	81,287,860

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

F-32

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30,			December 31,
	2012			2011
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable	$	1,183,415		$	2,050,768
Commodity price derivative liability		-			75,609
Related party payable		-			16,475
Accrued expenses		2,183,053			1,354,204
Short term loans payable		873,142			1,150,967
Total current liabilities		4,239,610			4,648,023
Long term liabilities
Asset retirement obligation		893,754			612,874
Term loanspayable		19,419,197			20,129,670
Convertible debentures notes payable, net of discount		9,595,053			4,929,068
Convertible debentures conversion derivative liability		1,300,000			1,300,000
Total long-term liabilities		31,208,004			26,971,612
Total liabilities		35,447,614			31,619,635
Commitments and contingencies – Note 8
Shareholders’ equity
Preferred stock, 10,000,000 authorized, none issued and outstanding as of September 30, 2012 and December 31, 2011		-			-
Common stock, $0.0001 par value: 100,000,000 shares authorized;  18,016,143 and 17,436,825 shares issued and outstanding  as of September 30, 2012 and December 31, 2011, respectively		1,801			1,744
Additional paid in capital		120,566,897			118,146,119
Accumulated deficit		(81,256,938	)		(68,479,638	)
Total shareholders' equity		39,311,760			49,668,225
Total liabilities and shareholders’ equity	$	74,759,374		$	81,287,860

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

F-33

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Revenue
Oil sales	$	1,775,383		$	1,650,702		$	4,685,713		$	5,534,325
Gas sales		168,897			161,029			397,298			446,386
Operating fees		42,853			85,372			132,362			110,282
Realized gain on commodity price derivatives		37,341			733,830			49,729			402,256
Unrealized gains (losses) on commodity price derivatives		(130,000	)		-			445,609			222,788
Total Revenues		1,894,474			2,630,933			5,710,711			6,716,037
Costs and expenses
Production costs		397,793			344,927			1,033,635			1,114,220
Production taxes		198,781			191,364			561,278			630,718
General and administrative		1,515,868			1,981,026			5,099,932			8,837,802
Depreciation, depletion and amortization		1,069,068			1,052,946			2,897,156			3,194,301
Impairment of evaluated properties		-			-			3,274,718			-
Total costs and expenses		3,181,510			3,570,263			12,866,719			13,777,041
Loss from operations		(1,287,036	)		(939,330	)		(7,156,008	)		(7,061,004	)
Other income (expense)		333			62,000			(372	)		63,115
Convertible debentures conversion derivative gain (losses)		600,000			(13,338	)		700,000			1,587,699
Interest expense		(2,149,931	)		(2,136,950	)		(6,320,919	)		(6,123,496	)
Net Loss	$	(2,836,634	)	$	(3,027,618	)	$	(12,777,299	)	$	(11,533,686	)
Net loss per common share
Basic and diluted	$	(0.16	)	$	(0.19	)	$	(0.72	)	$	(0.75	)
Weighted average shares outstanding:
Basic and diluted		17,833,466			15,775,135			17,732,304			15,388,772

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

F-34

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine months ended September 30,
	2012			2011
Cash flows provided by (used in) operating activities:
Net loss	$	(12,777,299	)	$	(11,533,686	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Amortization of stock issued for services		707,504			373,234
Share based compensation		1,066,154			5,592,638
Impairment of evaluated properties		3,274,718			-
Change in fair value of commodity price derivatives		(445,609	)		(398,840	)
Change in fair value of convertible debentures conversion derivative		(700,000	)		(1,587,699	)
Amortization of deferred financing costs, issuance of stock for convertible debentures interest, and accretion of debt discount		3,843,457			3,701,373
Depreciation, depletion, amortization and accretion		2,897,156			3,194,301
Changes in operating assets and liabilities:
Accounts receivable		(433,567	)		(891,076	)
Other assets		(21,294	)		(19,674	)
Accounts payable and other accruals		(867,353	)		2,428,101
Restricted cash		(17,453	)		144,001
Related party payable		(16,475	)		15,067
Accrued expenses		742,982			297,330
Net cash provided by (used in) operating activities		(2,747,079	)		1,315,070
Cash flows used in investing activities:
Acquisition of undeveloped properties		(436,023	)		(9,033,007	)
Sale of unevaluated properties		1,443,852			-
Investment in operating bonds		(184	)		(160	)
Drilling capital expenditures		(4,278,785	)		(6,876,232	)
Additions of office equipment		(2,928	)		(40,648	)
Net cash used in investing activities		(3,274,068	)		(15,950,047	)
Cash flows provided by (used in) financing activities:
Proceeds from sale of common stock, units and exercise of warrants		-			2,129,801
Net change in debts		(988,299	)		(377,498	)
Proceeds from debts		5,000,000			8,000,000
Net cash provided by (used in) financing activities		4,011,701			9,752,303
Change in cash and cash equivalents		(2,009,446	)		(4,882,674	)
Cash and cash equivalents at beginning of period		2,707,722			5,528,744
Cash and cash equivalents at end of period	$	698,276		$	646,070

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

F-35

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012

(UNAUDITED)

NOTE 1 – ORGANIZATION

Recovery Energy, Inc. (“Recovery”, “ours”, “us” or the “Company”), a Nevada corporation, is an independent oil and gas company engaged in the exploration, development and production of crude oil and natural gas.  The Company has focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 126,000 net acres located in Wyoming, Colorado, and Nebraska.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited interim consolidated financial statements were prepared by Recovery 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/A filed with the Securities and Exchange Commission (the "SEC") for the year ended December 31, 2011.  The current interim period reported herein should be read in conjunction with the financial statements and summary of significant accounting policies and notes included in the Company's Annual Report on Form 10-K/A.

All common stock share information is retroactively adjusted for the effect of a 4:1 reverse stock split that was effective October 19, 2011.

Reclassification

Certain amounts in the December 31, 2011 consolidated financial statements have been reclassified to conform to the September 30, 2012 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.  Both subsidiaries were inactive and were dissolved in the fourth quarter of 2011. 

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 ongoing 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 debentures payable. 

Liquidity
 

Cash used in operating activities during the nine months ended September 30, 2012 was $2.75 million; this use of cash, coupled with the cash used in investing activities, exceeded cash provided by financing activities by $2.0 million, and resulted in a corresponding decrease in cash.  This net use of cash also substantially contributed to a $2.20 million decrease in working capital as of September 30, 2012 as compared to working capital as of December 31, 2011.

In the immediate term, the Company expects that additional capital will be required to fund its remaining capital budget for 2012, partially to fund some of its ongoing overhead, and to provide additional capital to generally improve its working capital position.  In March 2012, the Company secured commitments to fund up to $5.0 million of additional convertible debentures, all of which had been funded as of September 30, 2012.  (See Note 7—Loan Agreements.)

F-36

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012

(UNAUDITED)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Pursuant to our credit agreements with Hexagon, LLC (“Hexagon”), a substantial portion of our monthly net revenues from our producing properties is required to be used for debt and interest payments.  In addition, our debt instruments contain provisions that, absent consent of the lenders, may restrict our ability to raise additional capital.  Also, the Hexagon debt is currently due on December 31, 2013, and will need to be extended or retired prior to that date.

The Company will continue to pursue alternatives to address its working capital position and capital structure and to provide funding for the balance of its planned 2012 expenditures.

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.

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 unevaluated 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 full cost pool which is 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.

The Company recognized impairment charges of $3.27 million during the nine months ended September 30, 2012.

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 the full cost pool and become subject to both depletion and the ceiling test calculations.  During the nine months ended September 30, 2012, the Company transferred $4.98 million of costs from wells in progress in to the full cost pool.

Loss per Common Share

Earnings (losses) per share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earnings (losses)  per share are computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares.  Potentially dilutive securities, such as conversion derivatives and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive.  As of September 30, 2012, a total of 6,238,900 and 3,152,941, respectively of outstanding warrants and derivative shares related to convertible debentures 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.

F-37

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012

(UNAUDITED)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recent Accounting Pronouncements

The Company evaluates the pronouncements of various authoritative accounting organizations to determine the impact of new GAAP pronouncements and the impact on the Company.

In December 2011, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Balance Sheet (Topic 210):  Disclosures about Offsetting Assets and Liabilities.  This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company is required to implement this guidance effective for the first quarter of fiscal 2014 and does not expect the adoption of ASU 2011-11 to have a material impact on its financial statements.

Various other accounting standards updates recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, are not expected to a have a material impact on the Company's financial position, results of operations or cash flows.

NOTE 3 – OIL AND GAS PROPERTIES

The Company did not complete any major purchases of undeveloped or producing oil and gas properties during the nine and three months ended September 30, 2012.

Effective December 31, 2011, the Company sold 2,838 net acres of undeveloped leases for consideration of approximately $4.5 million.  An initial closing occurred on December 31, 2011, resulting in the Company receiving a cash payment on that date of $3.1 million.  The final closing of this transaction occurred during the three months ended March 31, 2012, at which time the Company received additional net proceeds, after deductions of all closing expenses, of $1.4 million. 

NOTE 4 – WELLS IN PROGRESS
 

As of September 30, 2012, the Company has one well in progress that has been drilled, completed and is pending further evaluation as to its potential to ultimately produce commercial quantities of hydrocarbons.  This well is currently carried at a cost of $3.82 million.  The Company believes that this well should be ultimately capable of commercial production, but will need to invest additional capital to obtain this status.  However, should this well be ultimately plugged and abandoned, all capitalized costs would be transferred to the full cost pool.  Given the current status of the ceiling tests as of September 30, 2012, the current carrying costs would exceed the ceiling by the amount of $1.44 million, which would flow through the income statement as an expense if the well were assumed to be non-productive as of September 30, 2012.

Likewise, operations that are being conducted on this well are extending the primary terms of leases that comprise approximately 6,919 net acres and that are currently being carried at a cost of approximately $4.1 million.  Absent a successful completion of this well, the lease terms of some or all of these acres may expire, and the carrying costs of these leases would also be subject to the ceiling test.

NOTE 5 - FINANCIAL INSTRUMENTS AND DERIVATIVES

The Company periodically enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices.   As of September 30, 2012, the Company maintained an active commodity swap for 100 barrels per day through December 31, 2012 at a price of $96.25 per barrel, a swap for 100 barrels per day for the period of January 1, 2013 through June 30, 2013 at a price of $106.25 per barrel, and a swap for 100 barrels per day for the period of January 1, 2013 through December 31, 2013 at a price of $96.90.

The amounts of gains and losses recognized as a result of our derivative financial instruments were as follows:

F-38

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012

(UNAUDITED)

NOTE 5 - FINANCIAL IN-STRUMENTS AND DERIVATIVES (Continued)

	Three months ended September 30,					Nine months ended September 30,
	2012			2011		2012		2011
Realized gain on commodity price derivatives	$	37,341		$	733,830	$	49,729	$	402,256
Unrealized gains (losses) on commodity price derivatives	$	(130,000	)	$	-	$	445,609	$	222,788

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 6 — “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. On November 5, 2012, the company liquidated all of its price derivatives for proceeds of $0.60 million.

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs, used in the valuation methodologies in measuring fair value:

●          Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

●          Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

●          Level 3 – Unobservable inputs which are supported by little or no market activity.

The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

The Company measures its cash equivalents and investments at fair value.  The Company’s cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits are primarily classified within Level 1.  Cash equivalents and short-term investments are valued primarily using quoted market prices utilizing market observable inputs.

Derivative Instruments

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

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

At September 30, 2012, the types of derivative instruments utilized by the Company included commodity swaps.  The oil derivative markets are highly active.  Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange.  As such, the Company has classified these instruments as Level 2.

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

F-39

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012

(UNAUDITED)

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

Asset Retirement Obligation

The income valuation technique is utilized to determine the fair value of its asset retirement obligation liability at the point of inception by taking into account: 1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which are based on estimates from reserve engineers; 3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money.  Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.

Convertible Debentures Payable Conversion Feature

In February 2011, the Company issued in a private placement $8.40 million aggregate principal amount of three year 8% Senior Secured Convertible Debentures (“Debentures”) with a group of accredited investors.  During the nine months ended September 30, 2012, the Company issued an additional $5.00 million of Debentures, resulting in a total of $13.40 million of Debentures outstanding as of September 30, 2012.  As of September 30, 2012, the Debentures are convertible at any time at the holders’ option into shares of our common stock at $4.25 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 Company engaged a third party to complete a valuation of this conversion feature as of September 30, 2012 (see Note 7—Loan Agreements). The valuation was completed using Level 3 inputs.

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

September 30, 2012

	Level 1		Level 2		Level 3			Total
Assets
Commodity derivative instruments	$	-	$	370,000	$	-		$	370,000
Total assets, at fair value	$	-	$	370,000	$	-		$	370,000
Liability
Convertible debentures conversion derivative liability	$	-	$	-	$	(1,300,000	)	$	(1,300,000	)
Total liability, at fair value	$	-	$	-	$	(1,300,000	)	$	(1,300,000	)

December 31, 2011

	Level 1		Level 2			Level 3			Total
Liability
Commodity derivative instruments	$	-	$	(75,609	)		-		$	(75,609	)
Convertible debentures conversion derivative liability		-		-			(1,300,000	)		(1,300,000	)
Total liability at fair value	$	-	$	(75,609	)	$	(1,300,000	)	$	(1,375,609	)

The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of September 30, 2012: 

Beginning balance, December 31, 2011	$	(1,300,000	)
Convertible debentures conversion derivative gain		700,000
Additions to derivative liability from Supplemental Debenture		(700,000	)
Ending balance, September 30, 2012	$	(1,300,000	)

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 nine and three months ended September 30, 2012. 

F-40

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012

(UNAUDITED)

NOTE 7 – LOAN AGREEMENTS

Term Loans

The Company entered into three separate loan agreements with Hexagon during 2010.  All three loans bear annual interest of 15% and mature on December 31, 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 $6.00 million loan agreement, with an original maturity date of December 1, 2010.  Effective April 14, 2010, the Company entered into a $15 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 loans 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.

We 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 $1.60 million.  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 date of the loans to September 1, 2011.  During the last six months of 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2.00 million as payment on the loans. In November 2011, Hexagon extended the maturity to January 1, 2013.  In November 2011, Hexagon also temporarily advanced the Company an additional amount of $0.31 million, which was repaid in full in February 2012.  In March 2012, Hexagon extended the maturity of the loans to June 30, 2013, and in connection there with, the Company agreed to make minimum monthly note payments of $0.33 million, effective immediately.  In July 2012, Hexagon extended the maturity date to September 30, 2013. In November 2012, Hexagon extended the maturity date of the loans to December 31, 2013.

As of September 30, 2012, the total debt outstanding under these facilities is $20.29 million, of which $0.87 million is the current portion of long term debt.

The Company is subject to certain non-financial covenants with respect to the Hexagon loan agreements.  As of September 30, 2012, 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 Debentures Payable

In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of Debentures.  Initially, the Debentures were convertible at any time at the holders' option into shares of our 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 $0.40 million of Debentures equal to 5% of the gross proceeds from the sale.  The Company is amortizing the $0.40 million over the life of the loan as deferred financing costs.  The Company amortized $0.13 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.18 million of deferred financing costs to be amortized through February 2014. 

F-41

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012

(UNAUDITED)

NOTE 7 – LOAN AGREEMENTS (Continued)

In December, 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share. This amendment was an inducement consideration to the Debenture holders for their agreement to release a mortgage on certain properties so the properties could be sold. The sale of these properties was effective December 31, 2011, and a final closing occurred during the three months ended March 31, 2012.

On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to increase the amount of its Debentures by up to an additional $5.0 million (the “Supplemental Debentures”).  Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of Supplemental Debentures are to be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other general corporate purposes. Any new producing properties that are developed from the proceeds of Supplemental Debentures are to be pledged as collateral under a mortgage to secure future payment of the Debentures and Supplemental Debentures. All terms of the Supplemental Debentures are substantively identical to the Debentures.  The Agreements also provided for the payment of additional consideration to the purchasers of Supplemental Debentures in the form of a proportionately reduced, 5% carried working interest in any properties developed with the proceeds of the Supplemental Debenture offering.

Through July 2012, we received $3.04 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development of six new wells, resulting in a total investment of $3.69 million.  Five of these wells resulted in commercial production, and one well was plugged and abandoned.

In August 2012, the Company and certain holders of the Supplemental Debentures agreed to renegotiate the terms of the Supplemental Debenture offering.  These negotiations concluded with the issuance of an additional $1.96 million of Supplemental Debentures.  The August 2012 modifications to the Supplemental Debenture agreements increased the carried working interest from 5% to 10% and also provided for a one-year, proportionately reduced net profits interest of 15% in the properties developed with the proceeds of the Supplemental Debenture offering, as well as the next four properties to be drilled and developed by the Company.

The Company has estimated the total value of consideration paid to Supplemental Debenture holders in the form of the modified net profits interest and carried working interest to be approximately $1.16 million, and recorded this amount as a debt discount to be amortized over the remaining life of the Supplemental Debentures. 

We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect to September 30, 2012, the Supplemental Debentures.  This valuation resulted in an estimated derivative liability as of September 30, 2012 and December 31, 2011 of $1.3 million and $1.3 million, respectively.  The portion of the derivative liability that is associated with the Supplemental Debentures, in the approximate amount of $0.70 million, has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.

During the nine and three months ended September 30, 2012, the Company amortized $1.65 million and $0.71 million, respectively of debt discounts.

On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures.  The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs.  The Company amortized $0.01 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.22 million of deferred financing costs to be amortized through February 2014. 

F-42

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012

(UNAUDITED)

NOTE 7 – LOAN AGREEMENTS (Continued)

As of September 30, 2012 and December 31, 2011, the convertible debt is recorded as follows:

	As of				As of
		September 30,  2012				December 31, 2011
Convertible debentures		$	13,400,000			$	8,400,000
Debt discount			(3,804,947	)			(3,470,932	)
Total convertible debentures, net		$	9,595,053			$	4,929,068

Annual debt maturities as of September 30, 2012 are as follows:

Year 1	$	873,142
Year 2		32,819,197
Thereafter		-
Total	$	33,692,339

Interest Expense

For the three months ended September 30, 2012 and 2011, the Company incurred interest expense of approximately $2.15 million and $2.14 million, respectively, of which approximately $1.29 million and $1.50 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures payable interest paid in stock.

For the nine months ended September 30, 2012 and 2011, the Company incurred interest expense of approximately $6.32 million and $6.12 million, respectively, of which approximately $3.8 million and $3.70 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures payable interest paid in stock.

NOTE 8 - COMMITMENTS AND CONTINGENCIES

Environmental and Governmental Regulation

At September 30, 2012, 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, 2012, 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 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.

Other Contingencies

We could be liable for liquidated damages under registration rights agreements covering approximately 3.2 million shares of our common stock if we fail to maintain the effectiveness of a prior registration statement as required in the agreements.  In such case, we would be required to pay monthly liquidated damages of up to $0.23 million. The maximum aggregate liquidated damages are capped at $1.37 million.  

F-43

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012

(UNAUDITED)

Under the terms of the Supplemental Debenture agreements, the Company has a commitment to drill four additional wells.  Such agreements do not specify the location, timing, target zones, or other conditions related to these wells.  However, the Company anticipates that the capital provision required to satisfy this provision will be approximately $3.3 million.

NOTE 9 - SHAREHOLDERS’ EQUITY

Common Stock

Effective October 19, 2011, the Company completed a four-for-one reverse stock split of 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, 2012, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 18,016,143 shares of common stock were issued and outstanding.  No preferred shares were issued or outstanding.  

During the nine months ended September 30, 2012, the Company granted 356,865 shares of common stock as restricted stock grants to employees, board members, and consultants valued at $1.49 million.  The Company also issued 197,619 shares for payment of quarterly interest expense on the convertible debentures valued at $0.69 million, and 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as placement agent of the Supplemental Debentures.

Warrants

During September 2012, the Company entered into an agreement to issue 600,000 warrants to a financial advisory group. The 600,000 warrants vest monthly in six equal amounts over the six month term of the agreement, have a term of 3 years, and a strike price of $5.00 per share.  The Company records an expense for the value of the warrants on each vesting date.  During the three months ended September 30, 2012, the Company recorded an expense of $0.08 million for the 100,000 warrants that were vested as of September 30, 2012.  Additionally, the agreement provides that the Company will pay a monthly consulting fee of $10,000, with a final payment of $90,000 during the last month of the contract.  The Company may cancel the agreement at any time to avoid any future cash payments or vesting of remaining unvested warrants.

A summary of warrant activity for the nine months ended September 30, 2012 is presented below:

			Weighted-Average
	Warrants		Exercise Price
Outstanding at December 31, 2011		5,638,900	$	7.04
Granted		600,000		5.00
Exercised, forfeited, or expired		-		-
Outstanding at September 30, 2012		6,238,900	$	6.84

The aggregate intrinsic value of the warrants was approximately $0 as of both September 30, 2012 and December 31, 2011, based on the Company’s closing common stock price of $4.40 and $3.01, respectively; and the weighted average remaining contract life was 2.81 years and 3.18 years, respectively.

F-44

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2012

(UNAUDITED)

NOTE 10 - SHARE BASED COMPENSATION

In September 2012, the Company adopted the 2012 Equity Incentive Plan (the “Plan”).  Each member of the board of directors and the management team has been periodically awarded restricted stock grants, and in the future will be awarded such grants under the terms of the Plan.

The costs of employee services received in exchange for an award of equity instruments are 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.

During the nine months ended September 30, 2012, the Company granted 256,866 shares of restricted common stock to employees and directors of which 52,698, 81,250, 81,250, and 25,001 shares vest during the years ended December 31, 2012, 2013, 2014, and 2015, respectively. The fair value of these share grants was calculated to be approximately $0.78 million.  The Company also granted 100,000 shares to a consultant and 50,000 shares to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures, valued at $0.58 million

The Company recognized stock compensation expense of approximately $0.80 million and $0.37 million, respectively for the nine and three months ended September 30, 2012, and $5.59 million, and $0.92 million, respectively for the nine and three months ended September 30, 2011.

A summary of restricted stock grant activity for the nine months ended September 30, 2012 is presented below:

	Shares
Balance outstanding at December 31, 2011		2,340,235
Granted		356,865
Vested		(385,749	)
Expired		(25,167	)
Balance outstanding at September 30, 2012		2,286,184

Total unrecognized compensation cost related to unvested stock grants was approximately $2.187 million as of September 30, 2012.  The cost at September 30, 2012 is expected to be recognized over a weighted-average remaining service period of 3 years.

NOTE 11—SUBSEQUENT EVENTS

On November 5, 2012, the Company liquidated all of its price derivatives for proceeds of $0.60 million.

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PART II. INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other expenses of issuance and distribution.

The following expenses incurred in connection with the sale of the securities being registered will be borne by the Registrant. Other than the SEC registration fee and NASDAQ filing fee, the amounts stated are estimates.

SEC Registration Fee	$	421
Legal Fees and Expenses	$	20,000
Accounting Fees and Expenses	$	5,000
Miscellaneous	$	3,000
Total:	$	28,421

Item 14. Indemnification of directors and officers.

The Registrant is incorporated under the laws of the State of Nevada.  The Nevada Revised Statutes provide that a director or officer is not individually liable to the corporation or its stockholders or creditors for any damages as a result of any act or failure to act in his capacity as a director or officer unless it is proven that his act or failure to act constituted a breach of his fiduciary duties as a director or officer and his breach of those duties involved intentional misconduct, fraud or a knowing violation of law.

Section 78.7502 of the Nevada Revised Statutes permits a corporation to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, except an action by or in the right of the corporation, by reason of the fact that the person is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement actually and reasonably incurred by the person in connection with the action, suit or proceeding if the person: (1) is not liable pursuant to NRS 78.138; or (2) acted in good faith and in a manner which he or she reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe the conduct was unlawful.

The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent, does not, of itself, create a presumption that the person is liable pursuant to NRS 78.138 or did not act in good faith and in a manner which he or she reasonably believed to be in or not opposed to the best interests of the corporation, or that, with respect to any criminal action or proceeding, he or she had reasonable cause to believe that the conduct was unlawful.

In the case of actions brought by or in the right of the corporation, however, no indemnification may be made for any claim, issue or matter as to which such person has been adjudged by a court of competent jurisdiction, after exhaustion of all appeals therefrom, to be liable to the corporation or for amounts paid in settlement to the corporation, unless and only to the extent that the court in which the action or suit was brought or other court of competent jurisdiction determines upon application that in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses as the court deems proper.

To the extent that a director, officer, employee or agent of a corporation has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to above, or in defense of any claim, issue or matter therein, the corporation shall indemnify him or her against expenses, including attorneys’ fees, actually and reasonably incurred by him or her in connection with the defense.

Section 78.751 of the Nevada Revised Statutes permits any discretionary indemnification under Section 78.7502 of the Nevada Revised Statutes, unless ordered by a court or advanced to a director or officer by the corporation in accordance with the Nevada Revised Statutes, to be made by a corporation only as authorized in each specific case upon a determination that indemnification of the director, officer, employee or agent is proper in the circumstances. The determination of indemnification must be made (1) by the stockholders, (2) by the board of directors by majority vote of a quorum consisting of directors who were not parties to the action, suit or proceeding, (3) if a majority vote of a quorum consisting of directors who were not parties to the action, suit or proceeding so orders, by independent legal counsel in a written opinion, or (4) if a quorum consisting of directors who were not parties to the action, suit or proceeding cannot be obtained, by independent legal counsel in a written opinion.

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Our Articles of Incorporation provide for indemnification to the fullest extent permissible under Nevada law. They also provide for the payment of expenses of any person who is or was a director or officer of the Registrant, or, while a director or officer of the Registrant, is or was serving at the request of the Registrant as a director or officer, employee or agent of another corporation, partnership, joint venture, trust, association or other enterprise, who is deemed to have acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful.

Our By-Laws provide that we shall indemnify any person who is a director or officer of the Corporation, or, while a director or officer of the Corporation, is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, association or other enterprise, who is deemed to have acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful.  No indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the Registrant unless and only to the extent that the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the court shall deem proper.

We maintain directors’ and officers’ insurance which, subject to certain exclusions, insures our directors and officers against certain losses which arise out of any neglect or breach of duty (including, but not limited to, any error, misstatement, act, or omission) by the directors or officers in the discharge of their duties, and insures us against amounts which we have paid or may become obligated to pay as indemnification to our directors and/or officers to cover such losses.

Item 15.  Recent Sales of Unregistered Securities.

On March 19, 2012, the Company entered into agreements with some of the existing holders of its three year 8% Senior Secured Convertible Debentures (the “Debentures”) to increase the amount of the Debentures by up to an additional $5.0 million (the “Supplemental Debentures”).  Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of Supplemental Debentures are to be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other working capital purposes.  Any new producing properties that are developed from the proceeds of Supplemental Debentures are to be pledged as collateral to secure future payment of the Debentures.  All terms of the Supplemental Debentures are substantively identical to the Debentures.

As of June 30, 2012, we had received $2.80 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development of six new wells, resulting in a total investment of $3.80 million.  Five of these wells resulted in commercial production, and one well was plugged and abandoned.  In August 2012, the Company agreed to restructure the Supplemental Debenture offering in order to secure funding of the additional $2.2 million, which occurred on August 9, 2012.

The $5.0 million of convertible debentures that have been issued are currently convertible into 1,176,471 shares of common stock, at the rate of $4.25 per common share, subject to adjustment under certain circumstances.   Under the terms of the March 19, 2012 agreements as amended, we have no obligation to register any of the convertible debentures that are or may be issued, or any of the underlying common stock that may be issued upon conversion of any such convertible debentures. In May, August and November 2012, we issued shares of our common stock as payment of interest under the Debentures (including the Supplemental Debentures, as applicable).

On September 7, 2012, we granted a three-year warrant (the “Warrant”) to purchase 600,000 shares of common stock of the Company at an exercise price of $5.00 per share (or $3,000,000 in the aggregate) in exchange for certain financial advisory and investment and/or investment banking services.  However, in connection with the termination of the relationship with the financial advisory firm, the Warrant was forfeited in its entirety.

The issuance of the Debentures, the Supplemental Debentures and the Warrant was exempt from registration, pursuant to Section 4(2) of the Securities Act of 1933.  These securities qualified for exemption since the issuance of the securities by us did not involve a public offering and the purchasers are all accredited investors as defined in Regulation D under the Securities Act. 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 each agreed to and received share certificates bearing a legend stating that such securities are restricted pursuant to Rule 144 of the 1933 Securities Act. This restriction ensures that these securities 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 for this transaction.

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Item 16. Exhibits and Financial Statement Schedules.

a) Exhibits

The following exhibits are either filed herewith or incorporated herein by reference:

2.1 Membership Unit Purchase Agreement by and among Recovery Energy, Lanny M. Roof, Judith Lee and Michael Hlvasa dated as of September 21, 2009 (incorporated herein by reference to Exhibit 2.1 from our current report filed on form 8-K filed on September 22, 2009).

3.1	Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to Company's form S-1 filed on July 28, 2008).
3.2	Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to Company's periodic report on form 8-K filed on June 18, 2010).
4.1	2012 Equity Incentive Plan (incorporated herein by reference to Exhibit 4.1 to Company's periodic report on form 8-K filed on September 5, 2012).
5.1	Legal Opinion of Davis Graham & Stubbs LLP.
10.1	Cancellation agreements, dated September 21, 2009 between Universal Holdings, Inc. and two former shareholders (incorporated herein by reference to Exhibit 10.1 to the Company's annual report on form 10-K for the year ended December 31, 2010).
10.2	Lock-Up Agreement with Tryon Capital Ventures, LLC as of September 21, 2009 (incorporated herein by reference to Exhibit 10.2 to Company's current report filed on form 8-K filed on September 22, 2009).
10.3	Equipment Purchase Agreement, dated May 31, 2009 (incorporated herein by reference to Exhibit 10.3 to Company's current report filed on form 8-K filed on September 22, 2009).
10.4	Agreement with New Century Capital Partners dated as of November 16, 2009 (incorporated herein by reference to Exhibit 10.4 to Company's current report filed on form 8-K filed on November 23, 2009).
10.5	Purchase and Sale Agreement with Edward Mike Davis, L.L.C. for purchase of 100% interest in Church field dated as of October 1, 2009 (incorporated herein by reference to Exhibit 10.5 to Company's current report filed on form 8-K filed on November 13, 2009).
10.6	Purchase and Sale Agreement with Duane M. Freund Irrevocable Trust 2 for purchase of 50% interest in Church field dated as of October 1, 2009 (incorporated herein by reference to Exhibit 10.6 to Company's current report filed on form 8-K filed on November 13, 2009).
10.7	Purchase and Sale Agreement with Roger A. Parker for Church field dated effective as of October 1, 2009 (incorporated herein by reference to Exhibit 10.11 to Company's current report filed on form 8-K filed on January 21, 2010).

10.8	Purchase and Sale Agreement with Edward Mike Davis, L.L.C. for Wilke Field dated effective as of January 1, 2010 (incorporated herein by reference to Exhibit 10.8 to Company's annual report on form 10-K for the year ended December 31, 2009).
10.9	Credit Agreement with Hexagon Investments, LLC dated effective as of January 29, 2010 (incorporated herein by reference to Exhibit 10.12 to Company's current report filed on form 8-K filed on March 4, 2010).

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10.10	Promissory Note for financing with Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.13 to Company's current report filed on form 8-K filed on March 4, 2010).
10.11	Nebraska Mortgage to Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.14 to Company's current report filed on form 8-K filed on March 4, 2010).
10.12	Colorado Mortgage to Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.15 to Company's current report filed on form 8-K filed on March 4, 2010).
10.13	Purchase and Sale Agreement with Edward Mike Davis, L.L.C. dated effective as of April 1, 2010 (incorporated herein by reference to Exhibit 10.16 to Company's current report filed on form 8-K filed on March 25, 2010).
10.14	Credit Agreement with Hexagon Investments, LLC dated effective as of March 25, 2010 (incorporated herein by reference to Exhibit 10.17 to Company's current report filed on form 8-K filed on March 25, 2010).
10.15	Promissory Note for financing with Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.18 to Company's current report filed on form 8-K filed on March 25, 2010).
10.16	Nebraska Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.19 to Company's current report filed on form 8-K filed on March 25, 2010).
10.17	Wyoming Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.20 to Company's current report filed on form 8-K filed on March 25, 2010).
10.18	Purchase and Sale Agreement with Edward Mike Davis, L.L.C. for purchase of oil and gas properties dated as of April 1, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on April 20, 2010).
10.19	Credit Agreement with Hexagon Investments, LLC dated as of April 14, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on April 20, 2010).
10.20	Promissory Note with Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on April 20, 2010).
10.21	Warrant to Purchase Common Stock by Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.4 to the Company's current report filed on form 8-K filed on April 20, 2010).
10.22	Wyoming Mortgage to Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.5 to the Company's current report filed on form 8-K filed on April 20, 2010).
10.23	Securities Purchase Agreement dated as of April 26, 2020 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on April 30, 2010).
10.24	Agreement with C.K. Cooper dated April 8, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on May 4, 2010).
10.25	Purchase Agreement dated May 6, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on May 12, 2010).
10.26	Promissory Note dated May 6, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on May 12, 2010).
10.27	Security Agreement dated May 6, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on May 12, 2010).
10.28	Purchase Agreement with Edward Mike Davis, L.L.C. and Spottie, Inc. dated May 15, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on May 20, 2010).

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10.29	Form of Warrant Issued in Private Placement (incorporated herein by reference to Exhibit 4.1 to the Company's current report filed on form 8-K filed on June 4, 2010).
10.30	Warrant issued to Hexagon Investments, LLC (incorporated herein by reference to Exhibit 4.2 to the Company's current report filed on form 8-K filed on June 4, 2010).
10.31	Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 4, 2010).
10.32	Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K.
10.33	Form of Lockup Agreement (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on June 4, 2010).
10.34	Letter Agreement with Hexagon Investments, LLC (incorporated herein by reference to Exhibit 10.4 to the Company's current report filed on form 8-K filed on June 4, 2010).
10.35	Independent Director Appointment Agreement with Timothy N. Poster (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 7, 2010).
10.36	Consulting Agreement with Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 18, 2010).
10.37	Five Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on June 18, 2010).
10.38	Three Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on June 18, 2010).
10.39	Warrant to Globe Media (incorporated herein by reference to Exhibit 10.4 to the Company's current report filed on form 8-K filed on June 18, 2010).
10.40	Registration Rights Agreement with Hexagon Investments, Inc. (incorporated herein by reference to Exhibit 10.5 to the Company's current report filed on form 8-K filed on June 18, 2010).

10.41	Stockholders Agreement with Hexagon Investments Incorporated (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 29, 2010).
10.42	Form of $2.20 Warrant Issued to Persons Exercising $1.50 Warrants (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on October 8, 2010).
10.43	Purchase Agreement with Edward Mike Davis, L.L.C. and Spottie, Inc. dated November 19, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on November 26, 2010).
10.44	Put Option Agreement with Grandhaven Energy, LLC dated November 19, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company's current report on form 8-K filed on November 26, 2010).
10.45	Warrant Issued to Hexagon Investments, LLC on January 1, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on January 4, 2011).
10.46	Amendments to Hexagon Investments, LLC Promissory Notes (incorporated herein by reference to Exhibit 10.2 to the Company's current report on form 8-K filed on January 4, 2011).

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10.47	Form of Convertible Debenture Securities Purchase Agreement dated February 2, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on February 3, 2011).
10.48	Form of Convertible Debenture (incorporated herein by reference to Exhibit 10.2 to the Company's current report on form 8-K filed on February 3, 2011).
10.49	Purchase Agreement with Wapiti Oil & Gas, L.L.C. (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on February 24, 2011).
10.50	Termination Agreement dated as of December 15, 2009 with Edward Mike Davis, L.L.C. (incorporated herein by reference to Exhibit 10.54 to the Company's annual report on form 10-K for the year ended December 31, 2010).
10.51	Amendments to three Credit Agreements with Hexagon, LLC, dated March 15, 2012 (incorporated herein by reference to Exhibit 10.55 to the Company's annual report on form 10-K for the year ended December 31, 2011).

10.52 Second Amendment to 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.56 to the Company's annual report on form 10-K for the year ended December 31, 2011).

10.53 Securities Purchase Agreement for additional 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.57 to the Company's annual report on form 10-K for the year ended December 31, 2011).

10.54	Form of 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.58 to the Company's annual report on form 10-K for the year ended December 31, 2011).
10.55	Independent Director Appointment Agreement with Bruce B. White, dated as of April 27, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on form 8-K filed May 10, 2012).
10.56	Independent Director Appointment Agreement with W. Phillip Marcum, dated as of April 27, 2012 (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on form 8-K filed May 10, 2012).
10.57	Amended and Restated Independent Director Appointment Agreement with Timothy N. Poster, dated as of June 1, 2012 (incorporated herein by reference to Exhibit 10.3 to the Company’s current report on form 8-K filed May 10, 2012).
10.58	Independent Director Appointment Agreement with D. Kirk Edwards, dated as of May 18, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on form 8-K filed May 21, 2012).
10.59	Second Amendment to Credit Agreements with Hexagon, LLC, dated as of July 31, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on form 8-K for the quarter ended June 30, 2012).
10.60	Amendment to Securities Purchase Agreement dated as of March 12, 2012 relating to issuance of 8% Senior Secured Convertible Debentures due February 8, 2014 (incorporated herein by reference to Exhibit 10.2 to the Company’s quarterly report on form 10-Q for the quarter ended June 30, 2012).
10.61	Amendment to Securities Purchase Agreement dated as of February 2, 2011 relating to issuance of 8% Senior Secured Convertible Debentures due February 8, 2014 (incorporated herein by reference to Exhibit 10.1 to the Company’s current quarterly report on form 10-Q filed August 9, 2012).
10.62	Separation Agreement with Roger A. Parker, dated November 15, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on form 8-K filed December 5, 2012).
14.1	Code of Ethics (incorporated herein by reference to Exhibit 14.1 to the Company's annual report on form 10-K for the year ended December 31, 2009).
21.1	List of subsidiaries of the registrant (incorporated herein by reference to Exhibit 21.1 to the Company's registration statement on Form S-1 (333-164291).

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23.1	Consent of Hein & Associates, LLP.
23.2	Consent of RE Davis.
23.3	Consent of Davis Graham & Stubbs, LLP (included in Exhibit 5.1).

b) Financial statement schedules

Not applicable.

Item 17. Undertakings.

The undersigned registrant hereby undertakes:

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

● To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

● To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement.

● To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser:

● Each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference in the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

● Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

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● Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

● The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

● Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors officers, and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this registration statement to be signed on its behalf, thereunto duly authorized, in the City of Denver, State of Colorado, on January 18, 2013.

RECOVERY ENERGY, INC.,

a Nevada corporation

By:	/s/ A. Bradley Gabbard
Name:	A. Bradley Gabbard
Title:	President and Chief Financial Officer

POWER OF ATTORNEY

We, the undersigned officers and directors of Recovery Energy, Inc. hereby severally constitute W. Phillip Marcum and A. Bradley Gabbard, or each of them, our true and lawful attorney with full power to him to sign for us and in our names in the capacities indicated below the amendment to registration statement filed herewith and any and all amendments to said registration statement, and generally to do all such things in our name and behalf in our capacities as officers and directors to enable Recovery Energy, Inc. to comply with the provisions of the Securities Act of 1933, as amended, and all requirements of the Securities and Exchange Commission, hereby ratifying and confirming our signatures as they may be signed by our said attorneys, or any of them, to said registration statement and any and all amendments thereto.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated on January 18, 2013:

Name and Signature	Title
/s/ W. Phillip Marcum	Chairman of the Board and Chief Executive Officer
W. Phillip Marcum
/s/ A. Bradley Gabbard	Director, President and Chief Financial Officer
A. Bradley Gabbard
/s/ D. Kirk Edwards	Director
D. Kirk Edwards
/s/ Timothy N. Poster	Director
Timothy N. Poster
/s/Bruce B. White	Director
Bruce B. White

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EXHIBITS INDEX

2.1 Membership Unit Purchase Agreement by and among Recovery Energy, Lanny M. Roof, Judith Lee and Michael Hlvasa dated as of September 21, 2009 (incorporated herein by reference to Exhibit 2.1 from our current report filed on form 8-K filed on September 22, 2009).

3.1	Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to Company's form S-1 filed on July 28, 2008).
3.2	Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to Company's periodic report on form 8-K filed on June 18, 2010).
4.1	2012 Equity Incentive Plan (incorporated herein by reference to Exhibit 4.1 to Company's periodic report on form 8-K filed on September 5, 2012).
5.1	Legal Opinion of Davis Graham & Stubbs LLP.
10.1	Cancellation agreements, dated September 21, 2009 between Universal Holdings, Inc. and two former shareholders (incorporated herein by reference to Exhibit 10.1 to the Company's annual report on form 10-K for the year ended December 31, 2010).
10.2	Lock-Up Agreement with Tryon Capital Ventures, LLC as of September 21, 2009 (incorporated herein by reference to Exhibit 10.2 to Company's current report filed on form 8-K filed on September 22, 2009).
10.3	Equipment Purchase Agreement, dated May 31, 2009 (incorporated herein by reference to Exhibit 10.3 to Company's current report filed on form 8-K filed on September 22, 2009).
10.4	Agreement with New Century Capital Partners dated as of November 16, 2009 (incorporated herein by reference to Exhibit 10.4 to Company's current report filed on form 8-K filed on November 23, 2009).
10.5	Purchase and Sale Agreement with Edward Mike Davis, L.L.C. for purchase of 100% interest in Church field dated as of October 1, 2009 (incorporated herein by reference to Exhibit 10.5 to Company's current report filed on form 8-K filed on November 13, 2009).
10.6	Purchase and Sale Agreement with Duane M. Freund Irrevocable Trust 2 for purchase of 50% interest in Church field dated as of October 1, 2009 (incorporated herein by reference to Exhibit 10.6 to Company's current report filed on form 8-K filed on November 13, 2009).
10.7	Purchase and Sale Agreement with Roger A. Parker for Church field dated effective as of October 1, 2009 (incorporated herein by reference to Exhibit 10.11 to Company's current report filed on form 8-K filed on January 21, 2010).

10.8	Purchase and Sale Agreement with Edward Mike Davis, L.L.C. for Wilke Field dated effective as of January 1, 2010 (incorporated herein by reference to Exhibit 10.8 to Company's annual report on form 10-K for the year ended December 31, 2009).
10.9	Credit Agreement with Hexagon Investments, LLC dated effective as of January 29, 2010 (incorporated herein by reference to Exhibit 10.12 to Company's current report filed on form 8-K filed on March 4, 2010).
10.10	Promissory Note for financing with Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.13 to Company's current report filed on form 8-K filed on March 4, 2010).
10.11	Nebraska Mortgage to Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.14 to Company's current report filed on form 8-K filed on March 4, 2010).

II-10

10.12	Colorado Mortgage to Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.15 to Company's current report filed on form 8-K filed on March 4, 2010).
10.13	Purchase and Sale Agreement with Edward Mike Davis, L.L.C. dated effective as of April 1, 2010 (incorporated herein by reference to Exhibit 10.16 to Company's current report filed on form 8-K filed on March 25, 2010).
10.14	Credit Agreement with Hexagon Investments, LLC dated effective as of March 25, 2010 (incorporated herein by reference to Exhibit 10.17 to Company's current report filed on form 8-K filed on March 25, 2010).
10.15	Promissory Note for financing with Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.18 to Company's current report filed on form 8-K filed on March 25, 2010).
10.16	Nebraska Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.19 to Company's current report filed on form 8-K filed on March 25, 2010).
10.17	Wyoming Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.20 to Company's current report filed on form 8-K filed on March 25, 2010).
10.18	Purchase and Sale Agreement with Edward Mike Davis, L.L.C. for purchase of oil and gas properties dated as of April 1, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on April 20, 2010).
10.19	Credit Agreement with Hexagon Investments, LLC dated as of April 14, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on April 20, 2010).
10.20	Promissory Note with Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on April 20, 2010).
10.21	Warrant to Purchase Common Stock by Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.4 to the Company's current report filed on form 8-K filed on April 20, 2010).
10.22	Wyoming Mortgage to Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.5 to the Company's current report filed on form 8-K filed on April 20, 2010).
10.23	Securities Purchase Agreement dated as of April 26, 2020 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on April 30, 2010).
10.24	Agreement with C.K. Cooper dated April 8, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on May 4, 2010).
10.25	Purchase Agreement dated May 6, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on May 12, 2010).
10.26	Promissory Note dated May 6, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on May 12, 2010).
10.27	Security Agreement dated May 6, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on May 12, 2010).
10.28	Purchase Agreement with Edward Mike Davis, L.L.C. and Spottie, Inc. dated May 15, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on May 20, 2010).

10.29 Form of Warrant Issued in Private Placement (incorporated herein by reference to Exhibit 4.1 to the Company's current report filed on form 8-K filed on June 4, 2010).

II-11

10.30	Warrant issued to Hexagon Investments, LLC (incorporated herein by reference to Exhibit 4.2 to the Company's current report filed on form 8-K filed on June 4, 2010).
10.31	Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 4, 2010).
10.32	Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K.
10.33	Form of Lockup Agreement (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on June 4, 2010).
10.34	Letter Agreement with Hexagon Investments, LLC (incorporated herein by reference to Exhibit 10.4 to the Company's current report filed on form 8-K filed on June 4, 2010).
10.35	Independent Director Appointment Agreement with Timothy N. Poster (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 7, 2010).
10.36	Consulting Agreement with Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 18, 2010).
10.37	Five Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on June 18, 2010).
10.38	Three Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on June 18, 2010).
10.39	Warrant to Globe Media (incorporated herein by reference to Exhibit 10.4 to the Company's current report filed on form 8-K filed on June 18, 2010).
10.40	Registration Rights Agreement with Hexagon Investments, Inc. (incorporated herein by reference to Exhibit 10.5 to the Company's current report filed on form 8-K filed on June 18, 2010).

10.41	Stockholders Agreement with Hexagon Investments Incorporated (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 29, 2010).
10.42	Form of $2.20 Warrant Issued to Persons Exercising $1.50 Warrants (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on October 8, 2010).
10.43	Purchase Agreement with Edward Mike Davis, L.L.C. and Spottie, Inc. dated November 19, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on November 26, 2010).
10.44	Put Option Agreement with Grandhaven Energy, LLC dated November 19, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company's current report on form 8-K filed on November 26, 2010).
10.45	Warrant Issued to Hexagon Investments, LLC on January 1, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on January 4, 2011).
10.46	Amendments to Hexagon Investments, LLC Promissory Notes (incorporated herein by reference to Exhibit 10.2 to the Company's current report on form 8-K filed on January 4, 2011).
10.47	Form of Convertible Debenture Securities Purchase Agreement dated February 2, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on February 3, 2011).

II-12

10.48	Form of Convertible Debenture (incorporated herein by reference to Exhibit 10.2 to the Company's current report on form 8-K filed on February 3, 2011).
10.49	Purchase Agreement with Wapiti Oil & Gas, L.L.C. (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on February 24, 2011).
10.50	Termination Agreement dated as of December 15, 2009 with Edward Mike Davis, L.L.C. (incorporated herein by reference to Exhibit 10.54 to the Company's annual report on form 10-K for the year ended December 31, 2010).
10.51	Amendments to three Credit Agreements with Hexagon, LLC, dated March 15, 2012 (incorporated herein by reference to Exhibit 10.55 to the Company's annual report on form 10-K for the year ended December 31, 2011).

10.52 Second Amendment to 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.56 to the Company's annual report on form 10-K for the year ended December 31, 2011).

10.53 Securities Purchase Agreement for additional 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.57 to the Company's annual report on form 10-K for the year ended December 31, 2011).

10.54	Form of 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.58 to the Company's annual report on form 10-K for the year ended December 31, 2011).
10.55	Independent Director Appointment Agreement with Bruce B. White, dated as of April 27, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on form 8-K filed May 10, 2012).
10.56	Independent Director Appointment Agreement with W. Phillip Marcum, dated as of April 27, 2012 (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on form 8-K filed May 10, 2012).
10.57	Amended and Restated Independent Director Appointment Agreement with Timothy N. Poster, dated as of June 1, 2012 (incorporated herein by reference to Exhibit 10.3 to the Company’s current report on form 8-K filed May 10, 2012).
10.58	Independent Director Appointment Agreement with D. Kirk Edwards, dated as of May 18, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on form 8-K filed May 21, 2012).
10.59	Second Amendment to Credit Agreements with Hexagon, LLC, dated as of July 31, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on form 8-K for the quarter ended June 30, 2012).
10.60	Amendment to Securities Purchase Agreement dated as of March 12, 2012 relating to issuance of 8% Senior Secured Convertible Debentures due February 8, 2014 (incorporated herein by reference to Exhibit 10.2 to the Company’s quarterly report on form 10-Q for the quarter ended June 30, 2012).
10.61	Amendment to Securities Purchase Agreement dated as of February 2, 2011 relating to issuance of 8% Senior Secured Convertible Debentures due February 8, 2014 (incorporated herein by reference to Exhibit 10.1 to the Company’s current quarterly report on form 10-Q filed August 9, 2012).
10.62	Separation Agreement with Roger A. Parker, dated November 15, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on form 8-K filed December 5, 2012).
14.1	Code of Ethics (incorporated herein by reference to Exhibit 14.1 to the Company's annual report on form 10-K for the year ended December 31, 2009).
21.1	List of subsidiaries of the registrant (incorporated herein by reference to Exhibit 21.1 to the Company's registration statement on Form S-1 (333-164291).
23.1	Consent of Hein & Associates, LLP.
23.2	Consent of RE Davis.
23.3	Consent of Davis Graham & Stubbs, LLP (included in Exhibit 5.1).

II-13

EX-5.1

Exhibit 5.1

January 18, 2013

Recovery Energy, Inc.

1900 Grant Street, Suite 720

Denver, CO 80203

Ladies and Gentlemen:

We have acted as counsel to Recovery Energy, Inc., a Nevada corporation (the “Company”), in connection with the preparation and filing with the Securities and Exchange Commission (the “Commission”) under the Securities Act of 1933, as amended (the “Securities Act”), of the Company’s registration statement on Form S-1 (the “Registration Statement”) relating to the 1,600,000 shares of common stock, par value $0.0001 per share, proposed to be offered by the Company to the holders of an aggregate principal amount of $5,000,000 of the Company’s 8% Senior Secured Debentures due February 8, 2014 (the “Debentures”) as interest payments and in the event of conversion of the Debentures (the “Issuer Shares”), and 30,096 shares of common stock, par value $0.0001 per share (the “Selling Shareholder Shares” and together with the Issuer Shares, the “Shares”) issued previously on a restricted basis to holders of the Debentures as interest payments and being registered for resale on behalf of such holders. 

In rendering the opinion set forth below, we have examined the Registration Statement.  We have also examined the originals, or duplicates or certified or conformed copies, of such corporate and other records, agreements, documents and other instruments and have made such other investigations as we deemed relevant and necessary in respect of the authorization and issuance of the Shares, and such other matters as we deemed appropriate.  We have also assumed the genuineness of all signatures, the legal capacity of natural persons, the authenticity of all documents submitted to us as originals, the conformity to original documents of all documents submitted to us as duplicates or certified or conformed copies, and the authenticity of the originals of such latter documents.  

Based upon the foregoing, and subject to the limitations, qualifications, exceptions and assumptions expressed herein, we are of the opinion that

1.   The Issuer Shares have been duly authorized and, when and to the extent issued in accordance with the terms of the Debentures, will be validly issued, fully paid and non-assessable.

2.   The Selling Shareholder Shares have been duly authorized and validly issued, and are fully paid and non-assessable.

We are opining herein as to the Nevada Private Corporations Chapter of the Nevada Revised Statutes, Nev. Rev. Stat. 78, including interpretations thereof in published decisions of the Nevada courts, and we express no opinion with respect to any other laws.

This opinion is given as of the date hereof and we have no obligation to update this opinion to take into account any change in applicable law or facts that may occur after the date hereof.

We hereby consent to be named in the Registration Statement, as amended from time to time, as the attorneys who will pass upon legal matters in connection with the issuance of the Shares, and to the filing of this opinion as an Exhibit to the Registration Statement.  In giving this consent, we do not thereby admit that we are in the category of persons whose consent is required under Section 7 of the Securities Act or the rules of the Securities and Exchange Commission.

Very truly yours,

/s/ DAVIS GRAHAM & STUBBS LLP

DAVIS GRAHAM & STUBBS LLP

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use in this Registration Statement on Form S-1 of Recovery Energy, Inc. of our report dated March 29, 2012, relating to our audits of the consolidated financial statements and internal control over financial reporting, appearing in the Prospectus, which is part of this Registration Statement.

Our report dated March 29, 2012, on the effectiveness of internal control over financial reporting as of December 31, 2011, expressed an opinion that Recovery Energy, Inc. had not maintained effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Hein & Associates LLP

Denver, Colorado

January 18, 2013

EX-23.2

Exhibit 23.2

January 15, 2013

Recovery Energy, Inc.

1900 Grant Street, Suite 720

Denver, CO 80203

Attention: A. Bradley Gabbard

Dear Mr. Gabbard:

Ralph E. Davis Associates, Inc. hereby consents to the inclusion in this Registration Statement on Form S-1, including the related prospectus, of information from our report dated March 5, 2012, which appeared in the Annual Report on Form 10-K of Recovery Energy, Inc. for the year ended December 31, 2011.

Sincerely,

Ralph E. Davis Associates, Inc.

/s/ Allen C. Barron                            

Allen C Barron, P.E.

President

XML

Summary of Significant Accounting Policies (Details Textual) (USD $)	1 Months Ended		3 Months Ended		9 Months Ended		10 Months Ended	12 Months Ended
	Mar. 31, 2012	Oct. 31, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2009	Dec. 31, 2011 Well	Dec. 31, 2010	Dec. 31, 2009
Summary of Significant Accounting Policies (Textual)
Conversion ratio of reverse stock split (effective October 19, 2011)		4:1			four-for-one			four-for-one
Net cash provided by (used in) operating activities					$ (2,747,079)	$ 1,315,070	$ (381,239)	$ (570,247)	$ 3,758,694
Change in cash and cash equivalents					(2,009,446)	(4,882,674)	108,400	(2,821,023)	5,420,344
Decrease in working capital					2,200,000
Value of debt and equity securities raised through private placement since inception	5,000,000							72,000,000
Description of relationship between capitalized costs and the proved reserves attributable to the costs					Sale of 25% or more of proved reserves
Capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes, description					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
Impairment of evaluated properties					3,274,718			2,821,176
Cost from well in progress					4,980,000
Outstanding warrants excluded from the diluted share calculations					6,238,900
Derivative shares related to convertible notes payable excluded from the diluted share calculations					3,152,941
Proceeds from land sold								4,500,000
Remittance of monthly net revenues on the Hexagon debt								2,000,000
Maturity Date								Jan. 01, 2013
Additional advance received from Hexagon								309,000
Payment of related party advance								309,000
Payment of notes								325,000
Extended maturity date								Jun. 30, 2013
Cash and cash equivalents maturity period, Maximum								90 days
Bad debt expense									400,000
Assets Held-for-sale								0	0
Percentage of revenue sold to Shell Trading (US)								76.00%	64.00%
Percentage of sale of reserves								25% or more.
Percentage of discounted estimated future net revenues								10.00%
Impairment Expense								2,821,176	0
Impairment of unproved property								3,861,875	0
Number of well in progress								2
Unamortized deferred financing costs								2,300,000	3,200,000
Amortization expense								5,000,000	4,000,000
Prepaid financial advisory fees								574,000	979,000
Prepaid fees non cash consideration paid									1,234,000
Amortization of prepaid fees								405,000	247,000
Property and equipment estimated useful life								One to 7 years
Depreciation								34,000	5,000
Impairment of long-lived assets of two medium depth drilling rigs								0	0	2,750,000
Net asset								592,150	540,707
Related liability								$ 612,874	$ 507,280
Warrant [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from the diluted share calculations								5,638,900	5,638,900
Derivative [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive securities excluded from the diluted share calculations								5,764,233	5,764,233

XML

Related Party Transactions (Details) (USD $)	1 Months Ended	12 Months Ended
	May 31, 2010	Dec. 31, 2011 Property Well	Dec. 31, 2010	May 28, 2010	Apr. 30, 2010
Related Party Transactions (Textual)
Hexagon received warrants stock, shares			853,500	2,000,000	2,000,000
Warrants exercise price, per share	$ 6.00		$ 6.00
Number of property acquired		5
Number of wells to be drilled under agreement		2
Financing Acquisition [Member]
Related Party Transactions (Textual)
Hexagon received warrants stock, shares		500,000
Warrants exercise price, per share		10.00
Loan Agreements [Member]
Related Party Transactions (Textual)
Hexagon received warrants stock, shares		250,000
Warrants exercise price, per share		6.00
Davis [Member]
Related Party Transactions (Textual)
Ownership interest in common stock		19.10%
Hexagon [Member]
Related Party Transactions (Textual)
Ownership interest in common stock		15.70%

XML

Fair Value of Financial Instruments (Details) (USD $)	Sep. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Liability
Derivative instruments		$ (75,609)	$ (398,840)
Convertible notes payable Conversion feature	(1,300,000)	(1,300,000)
Total liability at fair value	(1,300,000)	(1,375,609)	(398,840)
Level 1 [Member]
Liability
Derivative instruments
Convertible notes payable Conversion feature
Total liability at fair value
Level 2 [Member]
Liability
Derivative instruments		(75,609)	(398,840)
Convertible notes payable Conversion feature
Total liability at fair value		(75,609)	(398,840)
Level 3 [Member]
Liability
Derivative instruments
Convertible notes payable Conversion feature	(1,300,000)	(1,300,000)
Total liability at fair value	$ (1,300,000)	$ (1,300,000)

XML

Income Taxes (Details) (USD $)	Dec. 31, 2011	Dec. 31, 2010
Deferred tax assets:
Oil and gas properties and equipment	$ (515,123)	$ (1,335,490)
Net operating loss carry-forward	11,291,513	7,285,426
Share based compensation	4,675,241	3,902,007
Abandonment obligation	205,145	188,728
Derivative instruments	176,514	148,384
Other	(91,304)	(30,896)
Total deferred tax asset	15,741,986	10,158,159
Valuation allowance	(15,741,986)	(10,158,159)
Net deferred tax asset

XML

Financial Instruments and Derivatives (Details) (USD $)	3 Months Ended		9 Months Ended		10 Months Ended	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010
Amounts of gains (losses) recognized as a result of derivative financial instruments
Realized gain on oil price hedges	$ 37,341	$ 733,830	$ 49,729	$ 402,256		$ 625,043	$ 570,233
Unrealized loss oil price hedges	$ (130,000)		$ 445,609	$ 398,840		$ 549,434	$ (398,840)

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Schedule of changes in deferred tax liabilities and deferred tax assets

	2011			2010
Deferred tax assets:
Oil and gas properties and equipment	$	(515,123	)	$	(1,335,490	)
Net operating loss carry-forward		11,291,513			7,285,426
Share based compensation		4,675,241			3,902,007
Abandonment obligation		205,145			188,728
Derivative instruments		176,514			148,384
Other		(91,304	)		(30,896	)
Total deferred tax asset		15,741,986			10,158,159
Valuation allowance		(15,741,986	)		(10,158,159	)
Net deferred tax asset	$	-		$	-

Reconciliation of the Company’s effective tax rate to the expected federal tax rate

	2011			2009
Effective federal tax rate		35.00	%		35.00	%
Effect of permanent differences		-7.54	%		-21.78	%
State tax rate		2.20	%		2.20	%
Change in rate		0.00	%		-0.23	%
Other		0.00	%		3.07	%
Valuation allowance		-29.66	%		-18.26	%
Net		0	%		0	%

XML

Income Taxes (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Income Taxes (Textual)
Operating loss carryforwards	$ 25,957,000	$ 19,582,000
Expiration period of operating loss carryforward	2031

XML

Financial Instruments and Derivatives (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Financial Instruments and Derivatives [Abstract]

Amounts of gains (losses) recognized as a result of derivative financial instruments

	Three months ended September 30,					Nine months ended September 30,
	2012			2011		2012		2011
Realized gain on commodity price derivatives	$	37,341		$	733,830	$	49,729	$	402,256
Unrealized gains (losses) on commodity price derivatives	$	(130,000	)	$	-	$	445,609	$	222,788

	For the Year Ended December 31,
	2011			2010			2009(1)
Realized gain on oil price hedges	$	625,043		$	570,233		$	-
Unrealized loss oil price hedges	$	(75,609	)	$	(398,840	)	$	-

(1)   Prior to January 1, 2010, the Company did not enter any derivative financial instruments. 

XML

Fair Value of Financial Instruments (Details Textual) (USD $) In Millions, except Per Share data, unless otherwise specified	1 Months Ended
	Feb. 28, 2011	Sep. 30, 2012	Dec. 31, 2011
Fair Value of Financial Instruments (Textual)
Convertible debentures issued through private placement	$ 8.40
Maturity period of senior secured convertible debentures	3 years
Senior Secured Convertible Debentures, interest rate, stated percentage	8.00%		8.00%
Additional convertible debentures issued		5.00
Debentures outstanding, total		$ 13.40
Debentures, convertible, conversion price (per share)	$ 9.40	$ 4.25	$ 4.25

XML

Oil and Gas Properties (Details 2) (USD $)	Sep. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Leasehold acquisitions
2010		$ 33,605,594
2011		12,091,887
Unevaluated properties	43,541,930	45,697,481	33,605,594
Wells in progress exploration 2011	3,986,919	6,425,509	1,219,397
Total oil and gas properties, at cost		$ 52,122,990

XML

Summary of Significant Accounting Policies (Details) (USD $)	Sep. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Summary of future expense of the prepaid advisory fees
2012		$ 405,289
2013		168,871
Total	$ 304,402	$ 574,160	$ 979,449

XML

Loan Agreements (Details Textual) (USD $)	1 Months Ended												3 Months Ended		9 Months Ended		12 Months Ended
	Nov. 30, 2012	Sep. 30, 2012	Aug. 31, 2012	Jul. 31, 2012 Well	Mar. 31, 2012	Nov. 30, 2011	Feb. 28, 2011	Dec. 31, 2010	May 31, 2010	Apr. 30, 2010	Mar. 31, 2010	Jan. 31, 2010	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011 Well	Dec. 31, 2010 Agreement	Sep. 08, 2012	Mar. 31, 2011	May 28, 2010	Apr. 14, 2010	Mar. 25, 2010	Jan. 29, 2010
Loan Agreements (Textual)
Number of separate loan agreements																		3
Annual interest rate on loan (in percentage)																		15.00%
Maturity date of loan				Sep. 30, 2013						Dec. 01, 2010	Dec. 01, 2010	Dec. 01, 2010						Dec. 31, 2013
Amount of loan agreement																						$ 15,000,000	$ 6,000,000	$ 4,500,000
Loan modification agreement															On May 28, 2010, which extended the maturity date of the loans to December 1, 2011		On May 28, 2010, which extended the maturity date of the loans to December 1, 2011
Deferred financing cost and amortized over the remaining term of the loan																					1,600,000
Warrants common stock, shares issued																					250,000
Hexagon received warrants stock, shares								853,500		2,000,000								853,500			2,000,000
Warrants exercise price, per share									$ 6.00									$ 6.00
Period of warrants that issued to purchase common stock									5 years
Additional warrants common stock, shares issued																					250,000
Total payment on the notes																	2,000,000
Suspension period for requirement to remit monthly net revenues																5 months	5 months
Temporarily advanced by Hexagon						310,000
Minimum monthly notes payments					330,000
Extended maturity date of loan agreements	Dec. 31, 2013			Sep. 30, 2013	Jun. 30, 2013	Jan. 01, 2013		Sep. 01, 2011
Debt outstanding term facilities		20,290,000											20,290,000		20,290,000		0
Current portion of long term debt		870,000											870,000		870,000		0
Additional consideration to the purchasers of Supplemental Debentures					5.00%												0.00%
Proceeds from private placement				3,040,000			8,400,000
Debentures, convertible, conversion price (per share)		$ 4.25					$ 9.40						$ 4.25		$ 4.25		$ 4.25
Description of interest payment on debentures other than cash							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.
Description of redemption price of debenture							115% of principal plus accrued interest
Period of remaining interest of the original issue date							18 months
Amount received by placement agent							400,000
Additional supplemetal debenture offering to secure funding			1,960,000				0
Increased in the carried working interest of supplemental debenture agreements due to drilled of four properties, minimum			5.00%				0.00%
Increased in the carried working interest of supplemental debenture agreements due to drilled of four properties, maximum			10.00%				0.00%
Supplemental debentures period			1 year				0 years
Proportionately reduced net profits interest rate			15.00%				0.00%
Percentage of gross sales received by placement agent							5.00%
Amortization of deferred financing costs into interest expense under private placement															130,000		88,888
Amount of deferred financing costs to be amortized		230,000					400,000								180,000		311,112
Debentures percentage							8.00%
Additional increase in the convertible debenture under supplemental debenture agreements					5,000,000												0
Convertible debentures issued through private placement							8,400,000
Number of wells are in progress				6													0
Number of wells resulted in commercial production				5													0
Number of wells plugged and abandoned from production				1													0
Investment of issuance debenture				3,690,000													0
Debt discount		3,804,947	1,160,000										3,804,947		3,804,947		3,470,932
Debt discount associated with supplement debentures amortized over remaining life of debentures															700,000		0
Estimated derivative liability		1,300,000											1,300,000		1,300,000		1,300,000			5,100,000
Estimate of inducement expense																	2,800,000
Reduction In Derivative Value																				1,300,000
Derivative gain																	3,800,000
Amortized debt discount													710,000		1,650,000		0
Shares issued by company acting as placement agent of supplemental debentures																	0		50,000
Value of Shares issued by company to T.R. Winston & Company LLC for acting as placement agent of supplemental debentures																	0		230,000
Amortization of deferred financing costs into interest expense															10,000		0
Deferred financing costs to be amortized															220,000		0
Interest expense incurred													2,150,000	2,140,000	6,320,000	6,120,000	8,218,000	6,600,000
Non-cash interest expense and amortization of the deferred financing costs													$ 1,290,000	$ 1,500,000	$ 3,800,000	$ 3,700,000	$ 5,000,000	$ 4,000,000

XML

Supplemental Oil and Gas Reserve Information (Unaudited) (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary of change in the standardized measure of discounted future net cash flows
Balance at beginning of period	$ 23,595
Sales of oil and gas, net	(5,342)	(7,655)
Net change in prices and production costs	8,006	3,084
Net change in future development costs		(4,563)
Extensions and discoveries	5,883	5,067
Acquisition of reserves		18,967
Sale of reserves
Revisions of previous quantity estimates	(14,804)	5,245
Previously estimated development costs incurred
Net change in income taxes
Accretion of discount	2,360	2,043
Other	316	1,407
Balance at end of period	$ 20,014	$ 23,595

XML

Share Based Compensation (Details) (Restricted Stock [Member])	9 Months Ended	10 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010
Restricted Stock [Member]
Summary of restricted stock grant activity
Beginning Balance	2,340,235		2,235,797	371,050
Granted	356,865	371,050	932,500	1,864,747
Vested	(385,749)		(828,062)
Expired	(25,167)
Ending Balance	2,286,184	371,050	2,340,235	2,235,797

XML

Financial Instruments and Derivatives (Details Textual) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended		10 Months Ended	12 Months Ended
	Nov. 30, 2012	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010
Financial Instruments and Derivatives (Textual)
Realized gain on settlement of commodity swaps							$ 625,000
Unrealized loss oil price hedges		(130,000)		445,609	398,840		549,434	(398,840)
Proceed from liquidation of price derivative	$ 600,000
Through December 31, 2012 [Member]
Financial Instruments and Derivatives (Textual)
Quantity of commodity swap oil per day, barrels				100			100
Commodity swap strike price, per barrel				96.25			96.25
January 1, 2013 through June 30, 2013 [Member]
Financial Instruments and Derivatives (Textual)
Quantity of commodity swap oil per day, barrels				100
Commodity swap strike price, per barrel				106.25
January 1, 2013 through December 31, 2013 [Member]
Financial Instruments and Derivatives (Textual)
Quantity of commodity swap oil per day, barrels				100
Commodity swap strike price, per barrel				96.90

XML

Summary of Significant Accounting Policies

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited interim consolidated financial statements were prepared by Recovery 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/A filed with the Securities and Exchange Commission (the "SEC") for the year ended December 31, 2011.  The current interim period reported herein should be read in conjunction with the financial statements and summary of significant accounting policies and notes included in the Company's Annual Report on Form 10-K/A.

All common stock share information is retroactively adjusted for the effect of a 4:1 reverse stock split that was effective October 19, 2011.

Reclassification

Certain amounts in the December 31, 2011 consolidated financial statements have been reclassified to conform to the September 30, 2012 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.  Both subsidiaries were inactive and were dissolved in the fourth quarter of 2011. 

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 ongoing 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 debentures payable. 

Liquidity
 

Cash used in operating activities during the nine months ended September 30, 2012 was $2.75 million; this use of cash, coupled with the cash used in investing activities, exceeded cash provided by financing activities by $2.0 million, and resulted in a corresponding decrease in cash.  This net use of cash also substantially contributed to a $2.20 million decrease in working capital as of September 30, 2012 as compared to working capital as of December 31, 2011.

In the immediate term, the Company expects that additional capital will be required to fund its remaining capital budget for 2012, partially to fund some of its ongoing overhead, and to provide additional capital to generally improve its working capital position.  In March 2012, the Company secured commitments to fund up to $5.0 million of additional convertible debentures, all of which had been funded as of September 30, 2012.  (See Note 7—Loan Agreements.)

Pursuant to our credit agreements with Hexagon, LLC (“Hexagon”), a substantial portion of our monthly net revenues from our producing properties is required to be used for debt and interest payments.  In addition, our debt instruments contain provisions that, absent consent of the lenders, may restrict our ability to raise additional capital.  Also, the Hexagon debt is currently due on December 31, 2013, and will need to be extended or retired prior to that date.

The Company will continue to pursue alternatives to address its working capital position and capital structure and to provide funding for the balance of its planned 2012 expenditures.

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.

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 unevaluated 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 full cost pool which is 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.

The Company recognized impairment charges of $3.27 million during the nine months ended September 30, 2012.

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 the full cost pool and become subject to both depletion and the ceiling test calculations.  During the nine months ended September 30, 2012, the Company transferred $4.98 million of costs from wells in progress in to the full cost pool.

Loss per Common Share

Earnings (losses) per share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earnings (losses)  per share are computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares.  Potentially dilutive securities, such as conversion derivatives and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive.  As of September 30, 2012, a total of 6,238,900 and 3,152,941, respectively of outstanding warrants and derivative shares related to convertible debentures 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.

Recent Accounting Pronouncements

The Company evaluates the pronouncements of various authoritative accounting organizations to determine the impact of new GAAP pronouncements and the impact on the Company.

In December 2011, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Balance Sheet (Topic 210):  Disclosures about Offsetting Assets and Liabilities.  This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company is required to implement this guidance effective for the first quarter of fiscal 2014 and does not expect the adoption of ASU 2011-11 to have a material impact on its financial statements.

Various other accounting standards updates recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, are not expected to a have a material impact on the Company's financial position, results of operations or cash flows.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

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

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

Use of Estimates in the Preparation of Financial Statements

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

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

Principle 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.  Both subsidiaries were inactive and were dissolved in the 4th quarter of 2011.

Liquidity

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

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

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

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

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks and highly liquid debt securities which have original maturities of 90 days or less at the purchase date.

Restricted Cash

Restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities and amounts 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. The Company did not record any allowance for uncollectible receivables for years ended December 31, 2011or December 31, 2010.  Receivables which derive from sales of certain oil and gas production are collateral for our Loan Agreements (see Note 7).

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

Assets Held For Sale

Assets held for sale are recorded at the lower of cost or estimated net realizable value. As of December 31, 2011 and 2010, the Company did not have any assets held for sale.

Concentration of Credit Risk

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

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

Significant Customers

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

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.

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

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

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

Unproved Properties

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

Wells in Progress

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

Deferred Financing Costs

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

Prepaid Advisory Fees

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

The following schedule details the future expense of the prepaid advisory fees.

2012	$	405,289
2013		168,871
Total	$	574,160

Property and Equipment

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

Impairment of Long-lived Assets

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

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

Fair Value of Financial Instruments

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

Commodity Derivative Instrument

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

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

Revenue Recognition

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

Asset Retirement Obligation

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

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

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

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

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

Share Based Compensation

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

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

Warrant Modification Expense

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

Loss per Common Share

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

Income Taxes

For tax reporting, the Company continues to file its tax returns on an April 30 year end, which is the legal tax year end of its predecessor.  

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

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

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

Recently Issued Accounting Pronouncements 

The Company did not adopt any new authoritative guidance for the year ended December 31, 2011 that had a material impact on its financial statements.

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Share Based Compensation (Details Textual) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended		10 Months Ended	12 Months Ended
	Oct. 31, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share Based Compensation (Textual)
Recognized stock compensation expense		$ 370,000	$ 920,000	$ 800,000	$ 5,590,000	$ 2,714,000	$ 6,161,000	$ 917,000	$ 2,714,000
Additional Share Based Compensation (Textual)
Unrecognized compensation cost, non-vested stock grants		2,187,000		2,187,000			0
Unrecognized compensation cost, non-vested stock grants, period for recognition (in years)				3 years			0 years
Reverse stock split	4:1			four-for-one			four-for-one
Recognized share based compensation expenses in 2012							1,066,000
Recognized share based compensation expenses in 2013							366,615
Recognized share based compensation expenses in 2014							12,478
Restricted Stock [Member]
Share Based Compensation (Textual)
Grant of restricted shares to employess, former chief financial officer during the period				356,865		371,050	932,500	1,864,747
Restricted common stock, vested				(385,749)			(828,062)
Restricted Stock [Member] | Employees [Member]
Share Based Compensation (Textual)
Grant of restricted shares to employess, former chief financial officer during the period							238,750
Grant of restricted shares to employees, former chief financial office during the period, fair value							4,370,808
Restricted common stock, vested							207,016
Restricted common stock, vested in the year ended December 31, 2012							192,000
Restricted common stock, vested in the year ended December 31, 2013							120,000
Restricted common stock, vested in the year ended December 31, 2014							2,500
Restricted Stock [Member] | Chief Financial Officer [Member]
Share Based Compensation (Textual)
Grant of restricted shares to employess, former chief financial officer during the period							481,250
Recognized stock compensation expense							3,551,000
Restricted Stock [Member] | Employees and Directors [Member]
Share Based Compensation (Textual)
Grant of restricted shares to employess, former chief financial officer during the period				256,866
Grant of restricted shares to employees, former chief financial office during the period, fair value				780,000
Restricted common stock, vested in the year ended December 31, 2012				52,698
Restricted common stock, vested in the year ended December 31, 2013				81,250
Restricted common stock, vested in the year ended December 31, 2014				81,250
Restricted common stock, vested in the year ended December 31, 2015				25,001
Restricted Stock [Member] | Consultant [Member]
Share Based Compensation (Textual)
Grant of restricted shares to employess, former chief financial officer during the period				100,000
Restricted Stock [Member] | T R Winston Company LLC [Member]
Share Based Compensation (Textual)
Grant of restricted shares to employess, former chief financial officer during the period				50,000
Grant of restricted shares to employees, former chief financial office during the period, fair value				230,000
Restricted Stock [Member] | Consultant and T.R. Winston Company LLC [Member]
Share Based Compensation (Textual)
Grant of restricted shares to employees, former chief financial office during the period, fair value				$ 580,000

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Oil and Gas Properties (Details Textual) (USD $)	1 Months Ended								3 Months Ended					9 Months Ended		10 Months Ended	12 Months Ended
	Mar. 31, 2011 Well	Feb. 28, 2011	Dec. 31, 2010 Well acre	Nov. 30, 2010 acre	Aug. 31, 2010 acre Well	Apr. 30, 2010	Mar. 31, 2010	Jan. 31, 2010	Sep. 30, 2012	Mar. 31, 2012	Dec. 31, 2011 Well	Sep. 30, 2011	Dec. 31, 2009 Agreement	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2009	Dec. 31, 2011 acre Well	Dec. 31, 2010 Well	Dec. 31, 2009	May 31, 2010	May 28, 2010
Oil and Gas Properties (Textual)
Number of purchase and sale agreements with Edward Mike Davis, LLC and affiliates (“Davis”)													2
Number of common stock forfeited during period													1,450,000
Estimated fair value of common stock forfeited under the purchase and sale agreements						$ 1,875,000	$ 412,500						$ 5,075,000
Business purchase price	551,519		2,000,000			15,000,000	6,000,000	4,500,000										2,000,000
Cash portion of purchase price percentage						100.00%	100.00%	100.00%
Shares issued in connection with financing		653,449	1,500,000	6,666,667		3,250,000	550,000	1,000,000
Deferred financing costs related to shares issued	5,798,546		4,875,000	12,000,000		2,780,775	737,822	2,250,000										4,875,000		1,500,000
Common stock, shares issued			14,453,592			2,500,000	750,000		18,016,143		17,436,825			18,016,143			17,436,825	14,453,592
Description of royalty interest						One percent overriding royalty interest in connection with the financing from Hexagon.	One-half percent overriding royalty in the leases and wells in connection with the financing from Hexagon.
Warrants exercised			853,500			2,000,000												853,500			2,000,000
Excercise price of warrants per share						$ 2.50
Cash paid to acquisition business	6,469,552	1,253,780																		20,000,000
Area of land farmed					240
Percentage of working interest in well			40.00%		26.00%
Area of land farmed in the state of Nebraska					533
Percentage of working interest in well in the state of Nebraska.					33.00%
Number of Wells			2		1						2						2	2
Area of oil and gas interest purchased			2,000	33,800
Area of rights acquired in base				23,000
Drilling and completion cost of wells			7,000,000															7,000,000
Amount allocated to undeveloped leases			2,000,000															2,000,000
Number of well purchase			2
Wells in progress			1,219,397						3,986,919		6,425,509			3,986,919			6,425,509	1,219,397
Number of undeveloped oil and gas leases acquisitions	2
Proceed from sale of business										1,400,000	3,100,000						4,500,000
Area of undeveloped leases sold																	2,838
Evaluated oil and gas properties			26,307,975						40,460,933		32,113,143			40,460,933			32,113,143	26,307,975
Depreciation, depletion and amortization expenses																	4,274,215	5,036,000	0
Impairment of evaluated oil and gas properties														3,274,718			2,821,176
Inventory of unevaluated leasehold period																	3 years
Carrying value of undeveloped leases											$ 11,000,000						$ 11,000,000

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Share Based Compensation (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Share Based Compensation [Abstract]

Summary of restricted stock grant activity

	Shares
Balance outstanding at December 31, 2011		2,340,235
Granted		356,865
Vested		(385,749	)
Expired		(25,167	)
Balance outstanding at September 30, 2012		2,286,184

	Shares (1)
Outstanding at March 6,2009	$	-
Granted		371,050
Vested		-
Outstanding at December 31, 2009		371,050
Granted		1,864,747
Vested		-
Outstanding at December 31, 2010		2,235,797
Granted		932,500
Vested		(828,062	)
Outstanding at December 31, 2011	$	2,340,235

(1)   On October 17, 2011, the Company affected a 4:1 reverse stock split.  The values shown are reflecting the reverse stock split.

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Shareholders' Equity (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Stockholders Equity [Abstract]

Summary of warrant activity

			Weighted-Average
	Warrants		Exercise Price
Outstanding at December 31, 2011		5,638,900	$	7.04
Granted		600,000		5.00
Exercised, forfeited, or expired		-		-
Outstanding at September 30, 2012		6,238,900	$	6.84

	Warrants (1)			Weighted-Average  Exercise  Price (1)
Outstanding at December 31, 2009		187,500		$	14.00
Granted		6,430,233			6.68
Exercised, forfeited, or expired		(853,500	)		6.00
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 December 31, 2011		5,638,900		$	6.33

(1)   On October 17, 2011, the Company performed a 4:1 reverse stock split.  The values shown are reflecting the reverse stock split.

Estimating fair value of warrants issued

	For the years ended December 31,
	2011			2010
Weighted-average volatility		97	%		80	%
Expected dividends		0.00	%		0.00	%
Expected term (in years)		3 – 5			3 – 5
Risk-free rate		2.02	%		1.49	%

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Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of the Company’s effective tax rate to the expected federal tax rate
Effective federal tax rate	35.00%	35.00%
Effect of permanent differences	(7.54%)	(21.78%)
State tax rate	2.20%	2.20%
Change in rate	0.00%	(0.23%)
Other	0.00%	3.07%
Valuation allowance	(29.66%)	(18.26%)
Net	0.00%	0.00%

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Wells in Progress (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Net changes in capitalized additions to wells in progress
Beginning balance	$ 1,219,254
Additions to capital wells in progress costs	8,904,532	1,219,254
Reclassifications to proved properties	(3,698,563)
Ending balance	$ 6,425,509	$ 1,219,254

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Summary of future expense of the prepaid advisory fees

2012	$	405,289
2013		168,871
Total	$	574,160

Reconciliation of the value of asset retirement obligation

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

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Oil and Gas Properties (Tables)

12 Months Ended

Dec. 31, 2011

Oil and Gas Properties [Abstract]

Summary of the fair values of assets acquired and liabilities assumed for each acquisition

	Wilke Field			Albin Field			State Line Field
Consideration given:
Cash payment funded by debt	$	4,500,000		$	6,000,000		$	15,000,000
Stock		-			412,500			1,875,000
Total consideration attributable to allocation	$	4,500,000		$	6,412,500		$	16,875,000
Allocation of purchase price:
Proved oil and gas properties	$	4,418,267		$	4,675,099		$	15,529,268
Unproved oil and gas properties		83,200			1,791,619			1,070,975
Total fair value of oil and gas properties acquired		4,501,467			6,466,718			16,600,243
Oil and gas revenue receivable		195,594			-			-
Total assets		4,697,061			6,466,718			16,600,243
Accounts payable		-			-			(52,147	)
Asset retirement obligation		(197,061	)		(54,218	)		(149,151	)
Total liabilities acquired		(197,061	)		(54,218	)		(201,298	)
Net assets acquired	$	4,500,000		$	6,412,500		$	16,398,945
Supplemental information:
Value attributable to ORRI paid to lender	$	-		$	(175,322	)	$	(158,685	)
Value attributable to ORRI awarded to management	$	(125,220	)	$	(701,290	)	$	(317,370	)

Summary of pro forma results of operations

	For the Year Ended December 31,
	2010			2009
	(Unaudited)			(Unaudited)
Operating revenues	$	12,941,108		$	6,070,500
Operating loss	$	(10,599,304	)	$	(29,001,745	)
Net loss	$	(19,063,015	)	$	(33,489,536	)
Pro forma loss per common share:
Basic and diluted	$	(2.08	)	$	(12.92	)

Summary of oil and gas property costs

	As of  December 31, 2011
Leasehold acquisitions
2010		$	33,605,594
2011			12,091,887
Unevaluated properties			45,697,481
Wells in progress exploration  2011			6,425,509
Total		$	52,122,990

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Organization

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Organization [Abstract]

ORGANIZATION

NOTE 1 – ORGANIZATION

Recovery Energy, Inc. (“Recovery”, “ours”, “us” or the “Company”), a Nevada corporation, is an independent oil and gas company engaged in the exploration, development and production of crude oil and natural gas.  The Company has focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 126,000 net acres located in Wyoming, Colorado, and Nebraska.

NOTE 1 – ORGANIZATION

On September 21, 2009, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC (“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to Recovery Energy, Inc. (“Recovery”, “Recovery Energy”, “we”, “our”, and the “Company”). The Agreement was accounted for as a reverse acquisition with Coronado being treated as the acquirer for accounting purposes. Accordingly, the financial statements of Coronado have been adopted as the historical financial statements of Recovery.

The Company is an independent oil and gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 130,000 net acres.  Recovery drills for, operates and produces oil and natural gas wells through the Company’s land holdings located in Wyoming, Colorado, and Nebraska.

All common stock share information is retroactively adjusted for the effect of a 4:1 reverse stock split that was effective October 19, 2011.

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Wells in Progress (Tables)

12 Months Ended

Dec. 31, 2011

Wells In Progress [Abstract]

Net changes in capitalized additions to wells in progress

	For the Year Ended December 31,
	2011			2010
Beginning balance	$	1,219,254			-
Additions to capital wells in progress costs		8,904,532			1,219,254
Reclassifications to proved properties		(3,698,563	)		-
Ending balance	$	6,425,509		$	1,219,254

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Oil and Gas Properties (Details) (USD $)	3 Months Ended		9 Months Ended		10 Months Ended	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Mar. 31, 2011	Feb. 28, 2011	May 31, 2010	Apr. 30, 2010	Mar. 31, 2010	Jan. 31, 2010
Consideration given:
Cash payment funded by debt								$ 6,469,552	$ 1,253,780	$ 20,000,000
Total consideration attributable to allocation							2,000,000	551,519			15,000,000	6,000,000	4,500,000
Allocation of purchase price:
Oil and gas revenue receivable	168,897	161,029	397,298	446,386		547,190	68,075
Asset retirement obligation						592,150	540,707
Wilke Field [Member]
Consideration given:
Cash payment funded by debt						4,500,000
Stock
Total consideration attributable to allocation						4,500,000
Allocation of purchase price:
Proved oil and gas properties						4,418,267
Unproved oil and gas properties						83,200
Total fair value of oil and gas properties acquired						4,501,467
Oil and gas revenue receivable						195,594
Total assets						4,697,061
Accounts payable
Asset retirement obligation						(197,061)
Total liabilities acquired						(197,061)
Net assets acquired						4,500,000
Supplemental information:
Value attributable to ORRI paid to lender
Value attributable to ORRI awarded to management						(125,220)
Albin Field [Member]
Consideration given:
Cash payment funded by debt						6,000,000
Stock						412,500
Total consideration attributable to allocation						6,412,500
Allocation of purchase price:
Proved oil and gas properties						4,675,099
Unproved oil and gas properties						1,791,619
Total fair value of oil and gas properties acquired						6,466,718
Oil and gas revenue receivable
Total assets						6,466,718
Accounts payable
Asset retirement obligation						(54,218)
Total liabilities acquired						(54,218)
Net assets acquired						6,412,500
Supplemental information:
Value attributable to ORRI paid to lender						(175,322)
Value attributable to ORRI awarded to management						(701,290)
State Line Field [Member]
Consideration given:
Cash payment funded by debt						15,000,000
Stock						1,875,000
Total consideration attributable to allocation						16,875,000
Allocation of purchase price:
Proved oil and gas properties						15,529,268
Unproved oil and gas properties						1,070,975
Total fair value of oil and gas properties acquired						16,600,243
Oil and gas revenue receivable
Total assets						16,600,243
Accounts payable						(52,147)
Asset retirement obligation						(149,151)
Total liabilities acquired						(201,298)
Net assets acquired						16,398,945
Supplemental information:
Value attributable to ORRI paid to lender						(158,685)
Value attributable to ORRI awarded to management						$ (317,370)

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Commitments and Contingencies (Details) (USD $) Share data in Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2012 Well
Commitments and Contingencies (Textual)
Liquidated damages under registration rights agreements, no of shares			3.2
Liquidated damages under registration rights agreements, monthly charges			$ 230,000
Liquidated damages under registration rights agreements, maximum charges			1,370,000
Number of wells drill under the supplemental debenture agreements			4
Capital commitment to drill four additional wells			3,300,000
Term of operating lease	1 year
Operating leases, rent expense	82,068	54,500
Minimum lease payments	$ 72,000

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Consolidated Balance Sheets (USD $)	Sep. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash	$ 698,276	$ 2,707,722	$ 5,528,744
Restricted cash	949,618	932,165	1,150,541
Accounts receivable	1,217,181	2,227,466	857,554
Prepaid assets	96,671	75,376	27,772
Commodity price derivative receivable	370,000
Total current assets	3,331,746	5,942,729	7,564,611
Oil and gas properties (full cost method), at cost:
Unevaluated properties	43,541,930	45,697,481	33,605,594
Evaluated properties	40,460,933	32,113,143	26,307,975
Wells in progress	3,986,919	6,425,509	1,219,397
Total oil and gas properties, at cost	87,989,782	84,236,133	61,132,966
Less accumulated depreciation, depletion and amortization	(18,174,968)	(12,099,098)	(5,003,499)
Net oil and gas properties, at cost	69,814,814	72,137,035	56,129,467
Other assets:
Office equipment, net	95,980	106,286	51,129
Prepaid advisory fees	304,402	574,160	979,449
Deferred financing costs, net	1,026,192	2,341,595	3,211,566
Restricted cash and deposits	186,240	186,055	185,707
Total other assets	1,612,814	3,208,096	4,427,851
Total Assets	74,759,374	81,287,860	68,121,929
Current liabilities:
Accounts payable	1,183,415	2,050,768	968,295
Commodity price derivative liability		75,609	398,840
Related party payable		16,475	11,638
Accrued expenses	2,183,053	1,354,204	1,540,592
Short term loans payable	873,142	1,150,967	208,881
Total current liabilities	4,239,610	4,648,023	3,128,246
Long term liabilities
Asset retirement obligation	893,754	612,874	507,280
Term loans payable	19,419,197	20,129,670	20,229,801
Convertible debentures notes payable, net of discount	9,595,053	4,929,068
Convertible debentures conversion derivative liability	1,300,000	1,300,000
Total long-term liabilities	31,208,004	26,971,612	20,737,081
Total liabilities	35,447,614	31,619,635	23,865,327
Commitments and contingencies – Note 8
Shareholders’ equity
Preferred stock, 10,000,000 authorized, none issued and outstanding as of September 30, 2012 and December 31, 2011
ommon stock subject to redemption rights, $0.0001 par value; 0 and 10,625 shares issued and outstanding as of December 31, 2011 and December 31, 2010, respectively			86,257
Common stock, $0.0001 par value: 100,000,000 shares authorized; 18,016,143 and 17,436,825 shares issued and outstanding as of September 30, 2012 and December 31, 2011, respectively	1,801	1,744	1,445
Additional paid-in capital	120,566,897	118,146,119	93,819,314
Accumulated deficit	(81,256,938)	(68,479,638)	(49,650,414)
Total shareholders' equity	39,311,760	49,668,225	44,170,345
Total liabilities and shareholders' equity	$ 74,759,374	$ 81,287,860	$ 68,121,929

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Wells in Progress (Details Textual) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2012 acre	Dec. 31, 2011
Wells In Progress (Textual)
Description of drilled wells produce commercial quantities of hydrocarbons	As of September 30, 2012, the Company has one well in progress that has been drilled, completed and is pending further evaluation as to its potential to ultimately produce commercial quantities of hydrocarbons.
Carrying cost of the well	$ 3.82
Carrying costs would exceed the ceiling test	1.44
Area extending the primary terms of leases	6,919
Carrying cost of the well (extending the primary terms of leases)	$ 4.1
Capitalization period of wells in progress		Less than one year

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Consolidated Statements of Shareholders' Equity (USD $)	Total	Common Stock Subject to Redemption	Common Stock	Additional Paid-in Capital	Accumulated Deficit
Beginning Balance at Mar. 05, 2009
Beginning Balace, Shares at Mar. 05, 2009
Common stock issued in reverse merger	(33,905)		52	(33,957)
Common stock issued in reverse merger, Shares			524,750
Common stock issued in exchange of debt	3,249,843		53	3,249,790
Common stock issued in exchange of debt, Shares			525,000
Common stock issued in lock-up agreement		172,516
Common stock issued in lock-up agreement, Shares		21,250
Common stock issued in restructuring	17,499,625		125	17,499,500
Common stock issued in restructuring, Shares			1,250,000
Common stock issued in attempted acquisition	5,824,873		43	5,824,830
Common stock issued in attempted acquisition, Shares			425,000
Common stock issued for cash	499,991		3	499,988
Common stock issued for cash, Shares			31,250
Restricted stock and performance options issued to employees and directors	684,778			684,778
Warrants issued for financing commitment	3,329,106			3,329,106
Common stock reacquired in attempted acquisition	(749,981)		(6)	(749,975)
Common stock reacquired in attempted acquisition, Shares			(62,500)
1:4 Reverse stock split	808			808
Net loss	(29,911,381)				(29,911,381)
Balance at Dec. 31, 2009	393,756	172,516	269	30,304,868	(29,911,381)
Balance, Shares at Dec. 31, 2009		21,250	2,693,500
Common stock issued for property acquisitions	15,786,621		293	15,786,328
Common stock issued for property acquisitions, Shares			2,929,167
Common stock issued in connection with financing property acquisitions	5,249,625		125	5,249,500
Common stock issued in connection with financing property acquisitions, Shares			1,250,000
Common stock issued for cash	14,924,540		398	14,924,142
Common stock issued for cash, Shares			3,978,789
Common stock issued for services	2,256,088		50	2,256,038
Common stock issued for services, Shares			502,216
Restricted stock issued to employees and directors	8,375,550		223	8,375,327
Restricted stock issued to employees and directors, Shares			2,235,797
Warrants exercised for cash	5,120,743		85	5,120,658
Warrants exercised for cash, Shares			853,500
Warrants issued for cash, services and fees	11,712,671			11,712,671
Common stock no longer subject to redemption	86,258	(86,258)	1	86,258
Common stock no longer subject to redemption, Shares		(10,625)	10,625
1:4 Reverse stock split	3,525			3,525
Net loss	(19,739,033)				(19,739,033)
Balance at Dec. 31, 2010	44,170,345	86,258	1,444	93,819,315	(49,650,414)
Balance, Shares at Dec. 31, 2010		10,625	14,453,593
Common stock issued for property acquisitions	10,895,893		228	10,895,665
Common stock issued for property acquisitions, Shares			2,269,543
Common stock issued for services	81,997		1	81,996
Common stock issued for services, Shares			10,000
Restricted stock issued to employees and directors	6,161,065		24	6,161,041
Restricted stock issued to employees and directors, Shares			238,750
Warrants exercised for cash	2,129,804		38	2,129,801
Warrants exercised for cash, Shares			375,333
Common stock no longer subject to redemption	86,255	(86,258)	1	86,254
Common stock no longer subject to redemption, Shares		(10,625)	10,625
Common stock issued in connection with interest payment of the financing	559,872		8	559,863
Common stock issued in connection with interest payment of the financing, Shares			78,982
Warrants issued for debt extension	1,611,832			1,611,797
1:4 Reverse stock split	387			387
Debt conversion expense	2,800,000			2,800,000
Net loss	(18,829,224)				(18,829,224)
Balance at Dec. 31, 2011	$ 49,668,225		$ 1,744	$ 118,146,119	$ (68,479,638)
Balance, Shares at Dec. 31, 2011			17,436,825

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Shareholders' Equity (Details 1) (Warrant [Member])	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Estimating fair value of warrants issued
Weighted-average volatility	97.00%	80.00%
Expected dividends	0.00%	0.00%
Risk-free rate	2.02%	1.49%
Minimum [Member]
Estimating fair value of warrants issued
Expected term (in years)	3 years	3 years
Maximum [Member]
Estimating fair value of warrants issued
Expected term (in years)	5 years	5 years

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Quarterly Results (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Results [Abstract]

Summary of quarterly financial data

	Year Ended December 31, 2011
	Fourth				Third				Second				First
	Quarter				Quarter				Quarter				Quarter
Revenues		$	1,944,454			$	2,630,933			$	2,811,429			$	1,273,675
Income (loss) from operations			(6,297,854	)			(939,330	)			(4,069,541	)			(2,052,133	)
Net earnings (loss)			(7,295,537	)			(3,027,618	)			(4,762,881	)			(3,743,187	)
Net earnings per common share:
Basic and diluted		$	(0.47	)		$	(0.19	)		$	(0.30	)		$	(0.25	)
Weighted average shares outstanding
Basic and diluted			15,543,758				15,775,135				15,635,346				14,778,206

	Year Ended December 31, 2010
	Fourth				Third				Second				First
	Quarter				Quarter				Quarter				Quarter
Revenues		$	1,519,702			$	2,552,790			$	5,194,849			$	490,351
Income (loss) from operations			(4,191,728	)			(5,900,630	)			(792,880	)			(2,242,252	)
Net earnings (loss)			(6,230,293	)			(7,491,246	)			(3,196,779	)			(2,820,715	)
Net earnings per common share:
Basic and diluted		$	(1.47	)		$	(2.53	)		$	(1.99	)		$	(1.04	)
Weighted average shares outstanding
Basic and diluted			9,167,803				2,962,882				6,362,922				2,927,759

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Supplemental Oil and Gas Reserve Information (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2011 bbl	Dec. 31, 2010 bbl	Dec. 31, 2009 bbl
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve
Beginning Balance			0
Balance			0
Crude Oil [Member]
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve
Beginning Balance	692,388
Purchase of reserves		643,955
Revisions of previous estimates	(268,718)	123,679
Extensions and discoveries	266,000	58,463
Sale of reserves
Production	(81,433)	(133,709)
Balance	608,237	692,388
Proved Developed Reserves	215,693	277,669
Proved Undeveloped Reserves	392,545	414,719
Natural Gas [Member]
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve
Beginning Balance	308,579
Purchase of reserves
Revisions of previous estimates	(44,919)
Extensions and discoveries		323,493
Sale of reserves
Production	(115,583)	(14,914)
Balance	148,077	308,579
Proved Developed Reserves	148,077	308,579
Proved Undeveloped Reserves

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Supplemental Oil And Gas Reserve Information (Unaudited)

12 Months Ended

Dec. 31, 2011

Supplemental Oil and Gas Reserve Information [Abstract]

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

NOTE 15- SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The following table sets forth information for the years ended December 31, 2011, 2010 and 2009 with respect to changes in the Company's proved (i.e. proved developed and undeveloped) reserves:

	Crude Oil (Bbls)			Natural Gas  (Mcf)
December 31, 2009		-			-
Purchase of reserves		643,955			-
Revisions of previous estimates		123,679			-
Extensions and discoveries		58,463			323,493
Sale of reserves		-			-
Production		(133,709	)		(14,914	)
December 31, 2010		692,388			308,579
Purchase of reserves		-			-
Revisions of previous estimates		(268,718	)		(44,919	)
Extensions, discoveries		266,000			-
Sale of reserves
Production		(81,433	)		(115,583	)
December 31, 2011		608,237			148,077
Proved Developed Reserves, included above:
Balance, December 31, 2009		-			-
Balance, December 31, 2010		277,669			308,579
Balance, December 31, 2011		215,693			148,077
Proved Undeveloped Reserves, included above:
Balance, December 31, 2009		-			-
Balance, December 31, 2010		414,719			-
Balance, December 31, 2011		392,545			-

The Company did not have any reserves as of December 31, 2009.

As of December 31, 2011 and December 31, 2010, we had estimated proved reserves of 608,237 and 692,388 barrels of oil, respectively and 24,680 and 308,579 thousand cubic feet ("MCF") of natural gas, respectively.  Our reserves are comprised of 96% and 93% crude oil and 4% and 7% natural gas on an energy equivalent basis.

The following values for the December 31, 2011 and December 31, 2010 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31 natural gas price of $3.96 and $4.39 per MMBtu (NYMEX price) and crude oil price of $88.16 and $77.78 per barrel (West Texas Intermediate price). All prices are then further adjusted for transportation, quality and basis differentials.

During the years ended December 31, 2010, the Company completed multiple acquisitions which included proved reserves associated with producing properties. Included in the Company's December 31, 2010 proved reserves classified as 'Purchase of reserves' in the table above, are $3,760,000 and 643,955 barrels of crude oil attributable to the acquisitions.

The following summary sets forth the Company's future net cash flows relating to proved oil and gas:

	For the Year Ended December 31, (in thousands)
	2011			2010			2009 (1)
Future oil and gas sales	$	55,295		$	51,816		$	-
Future production costs		(16,579	)		(11,614	)		-
Future development costs		(8,481	)		(8,063	)		-
Future income tax expense (2)		-			-			-
Future net cash flows		30,235			32,139			-
10% annual discount		(10,221	)		(8,544	)		-
Standardized measure of discounted future net cash flows	$	20,014		$	23,595		$	-

(1) Prior to January 2010, the Company did not own any oil and gas assets.

(2) Our calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all years reported. We expect that all of our Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company's operations, and resulting NOLs, are attributable to our oil and gas assets. There were no taxes in any year as the tax basis and NOL's exceeded the future net revenue.

The principle sources of change in the standardized measure of discounted future net cash flows are:

	2011			2010			2009 (1)
Balance at beginning of period	$	23,595		$	-		$	-
Sales of oil and gas, net		(5,342	)		(7,655	)		-
Net change in prices and production costs		8,006			3,084			-
Net change in future development costs		-			(4,563	)		-
Extensions and discoveries		5,883			5,067			-
Acquisition of reserves					18,967			-
Sale of reserves					-			-
Revisions of previous quantity estimates		(14,804	)		5,245			-
Previously estimated development costs incurred					-			-
Net change in income taxes					-			-
Accretion of discount		2,360			2,043			-
Other		316			1,407			-
Balance at end of period	$	20,014		$	23,595		$	-

Revisions in 2011 of previous quantity estimates relate principally to the exclusion of certain proven undeveloped well locations that were included in the reserve estimates dated December 31, 2010.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

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Organization (Details)	1 Months Ended	9 Months Ended	12 Months Ended
	Oct. 31, 2011	Sep. 30, 2012 acre	Dec. 31, 2011 acre
Organization (Textual)
Land for crude oil and natural gas		126,000	130,000
Reverse stock split	4:1	four-for-one	four-for-one

XML

Summary of Significant Accounting Policies (Policies)

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The accompanying unaudited interim consolidated financial statements were prepared by Recovery 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/A filed with the Securities and Exchange Commission (the "SEC") for the year ended December 31, 2011.  The current interim period reported herein should be read in conjunction with the financial statements and summary of significant accounting policies and notes included in the Company's Annual Report on Form 10-K/A.

All common stock share information is retroactively adjusted for the effect of a 4:1 reverse stock split that was effective October 19, 2011.

Basis of Presentation and Principles of Consolidation

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

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

Reclassification

Reclassification

Certain amounts in the December 31, 2011 consolidated financial statements have been reclassified to conform to the September 30, 2012 consolidated financial statement presentation.  Such reclassifications had no effect on net income.

Principles of Consolidation

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.  Both subsidiaries were inactive and were dissolved in the fourth quarter of 2011. 

Principle 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.  Both subsidiaries were inactive and were dissolved in the 4th quarter of 2011.

Use of Estimates

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 ongoing 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 debentures payable. 

Use of Estimates in the Preparation of Financial Statements

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

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

Liquidity

Liquidity
 

Cash used in operating activities during the nine months ended September 30, 2012 was $2.75 million; this use of cash, coupled with the cash used in investing activities, exceeded cash provided by financing activities by $2.0 million, and resulted in a corresponding decrease in cash.  This net use of cash also substantially contributed to a $2.20 million decrease in working capital as of September 30, 2012 as compared to working capital as of December 31, 2011.

In the immediate term, the Company expects that additional capital will be required to fund its remaining capital budget for 2012, partially to fund some of its ongoing overhead, and to provide additional capital to generally improve its working capital position.  In March 2012, the Company secured commitments to fund up to $5.0 million of additional convertible debentures, all of which had been funded as of September 30, 2012.  (See Note 7—Loan Agreements.)

Pursuant to our credit agreements with Hexagon, LLC (“Hexagon”), a substantial portion of our monthly net revenues from our producing properties is required to be used for debt and interest payments.  In addition, our debt instruments contain provisions that, absent consent of the lenders, may restrict our ability to raise additional capital.  Also, the Hexagon debt is currently due on December 31, 2013, and will need to be extended or retired prior to that date.

The Company will continue to pursue alternatives to address its working capital position and capital structure and to provide funding for the balance of its planned 2012 expenditures.

Liquidity

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

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

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

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

Oil and Gas Producing Activities

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.

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 unevaluated 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 full cost pool which is 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.

The Company recognized impairment charges of $3.27 million during the nine months ended September 30, 2012.

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.

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

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

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

Wells in Progress

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 the full cost pool and become subject to both depletion and the ceiling test calculations.  During the nine months ended September 30, 2012, the Company transferred $4.98 million of costs from wells in progress in to the full cost pool.

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 December 31, 2011, the Company had two wells in progress, both of which have been drilled and completed and are pending evaluation as to their potential to produce commercial quantities of oil and gas reserves.

Loss per Common Share

Loss per Common Share

Earnings (losses) per share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earnings (losses)  per share are computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares.  Potentially dilutive securities, such as conversion derivatives and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive.  As of September 30, 2012, a total of 6,238,900 and 3,152,941, respectively of outstanding warrants and derivative shares related to convertible debentures 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.

Loss per Common Share

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

Recent Accounting Pronouncements

Recent Accounting Pronouncements

The Company evaluates the pronouncements of various authoritative accounting organizations to determine the impact of new GAAP pronouncements and the impact on the Company.

In December 2011, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Balance Sheet (Topic 210):  Disclosures about Offsetting Assets and Liabilities.  This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset, if any, and the related arrangements. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company is required to implement this guidance effective for the first quarter of fiscal 2014 and does not expect the adoption of ASU 2011-11 to have a material impact on its financial statements.

Various other accounting standards updates recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, are not expected to a have a material impact on the Company's financial position, results of operations or cash flows.

Recently Issued Accounting Pronouncements 

The Company did not adopt any new authoritative guidance for the year ended December 31, 2011 that had a material impact on its financial statements.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks and highly liquid debt securities which have original maturities of 90 days or less at the purchase date.

Restricted Cash

Restricted Cash

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

Accounts Receivable

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. The Company did not record any allowance for uncollectible receivables for years ended December 31, 2011or December 31, 2010.  Receivables which derive from sales of certain oil and gas production are collateral for our Loan Agreements (see Note 7).

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

Assets Held For Sale

Assets Held For Sale

Assets held for sale are recorded at the lower of cost or estimated net realizable value. As of December 31, 2011 and 2010, the Company did not have any assets held for sale.

Concentration of Credit Risk

Concentration of Credit Risk

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

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

Significant Customers

Significant Customers

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

Unproved Properties

Unproved Properties

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

Deferred Financing Costs

Deferred Financing Costs

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

Prepaid Advisory Fees

Prepaid Advisory Fees

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

The following schedule details the future expense of the prepaid advisory fees.

2012	$	405,289
2013		168,871
Total	$	574,160

Property and Equipment

Property and Equipment

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

Impairment of Long-lived Assets

Impairment of Long-lived Assets

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

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

Fair Value of Financial Instruments

Fair Value of Financial Instruments

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

Commodity Derivative Instrument

Commodity Derivative Instrument

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

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

Revenue Recognition

Revenue Recognition

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

Asset Retirement Obligation

Asset Retirement Obligation

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

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

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

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

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

Share Based Compensation

Share Based Compensation

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

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

Warrant Modification Expense

Warrant Modification Expense

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

Income Taxes

Income Taxes

For tax reporting, the Company continues to file its tax returns on an April 30 year end, which is the legal tax year end of its predecessor.  

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

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

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

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Supplemental Oil and Gas Reserve Information (Unaudited) (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2011 USD_mmbtu USD_barrels	Dec. 31, 2010 USD_mmbtu bbl	Dec. 31, 2009 bbl
Supplemental Oil and Gas Reserve Information (Unaudited) (Textual)
Proved Developed and Undeveloped Reserves			0
Description of oil and gas reserves price	Based on the 12 month arithmetic average first of month price January through December 31
Natural gas price (per MMBtu)	3.96	4.39
Crude oil price (per barrel)	88.16	77.78
Crude Oil [Member]
Supplemental Oil and Gas Reserve Information (Unaudited) (Textual)
Estimated proved reserves of oil and natural gas	215,693	277,669
Percentage of reserves comprised on energy eqivalent basis	96.00%	93.00%
Purchase of reserves		643,955
Cost of crude oil		3,760,000
Proved Developed and Undeveloped Reserves	608,237	692,388
Natural Gas [Member]
Supplemental Oil and Gas Reserve Information (Unaudited) (Textual)
Estimated proved reserves of oil and natural gas	148,077	308,579
Percentage of reserves comprised on energy eqivalent basis	4.00%	7.00%
Purchase of reserves
Proved Developed and Undeveloped Reserves	148,077	308,579

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Consolidated Statements of Cash Flows (USD $)	9 Months Ended		10 Months Ended	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010
Cash flows provided by (used in) operating activities:
Net loss	$ (12,777,299)	$ (11,533,686)	$ (29,911,381)	$ (18,829,224)	$ (19,739,033)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Amortization of stock issued for services	707,504	373,234
Share based compensation	1,066,154	5,592,638	884,778	6,566,152	8,701,263
Impairment of evaluated properties	3,274,718			2,821,176
Change in fair value of commodity price derivatives	(445,609)	(398,840)		(549,434)	398,840
Change in fair value of convertible debentures conversion derivative	(700,000)	(1,587,699)		(3,821,792)
Amortization of deferred financing costs, issuance of stock for convertible debentures interest, and accretion of debt discount	3,843,457	3,701,373		4,446,911	3,989,649
Depreciation, depletion, amortization and accretion	2,897,156	3,194,301		4,347,117	5,036,648
Impairment of equipment			2,750,000
Debt inducement and warrant modification expense				2,800,000	2,953,450
Common stock issued for convertible note interest				559,873
Bad debt expense					400,000
Fair value of warrants issued			3,329,106
Non-cash restructuring costs			17,500,000
Loss on aborted property acquisitions			5,075,000
Compensation expense recognized for assignment of overrides					1,578,080
Changes in operating assets and liabilities:
Accounts receivable	(433,567)	(891,076)	(100,000)	73,940	(757,554)
Other assets	(21,294)	(19,674)	15,627	39,451	(34,066)
Accounts payable and other accruals	(867,353)	2,428,101	96,507	757,207	2,361,082
Restricted cash	(17,453)	144,001	(20,876)	218,376	(1,129,665)
Related party payable	(16,475)	15,067
Accrued expenses	742,982	297,330
Net cash provided by (used in) operating activities	(2,747,079)	1,315,070	(381,239)	(570,247)	3,758,694
Cash flows used in investing activities:
Acquisition of undeveloped properties	(436,023)	(9,033,007)		(9,433,073)	(18,560,412)
Sale of unevaluated properties	1,443,852		1,500,000	3,000,000	2,000,000
Investment in operating bonds	(184)	(160)	(109,891)	(348)	(75,675)
Drilling capital expenditures	(4,278,785)	(6,876,232)		(7,017,523)	(4,637,111)
Additions of office equipment	(2,928)	(40,648)	(750,470)	(83,727)	(55,767)
Additions of evaluated properties and equipment (net of purchase price adjustment)					(25,580,793)
Sale of drilling rigs					100,000
Proceeds from hedge settlement				226,203
Net cash used in investing activities	(3,274,068)	(15,950,047)	639,639	(13,308,468)	(46,809,758)
Cash flows provided by (used in) financing activities:
Proceeds from sale of common stock, units and exercise of warrants		2,129,801	500,000	2,129,870	28,132,727
Net change in debts	(988,299)	(377,498)		(483,774)	(8,061,319)
Proceeds from debt	5,000,000	8,000,000		9,411,597	28,500,000
Common stock reacquired in attempted Church acquisition			(750,000)
Common stock issuable			100,000		(100,000)
Net cash provided by (used in) financing activities	4,011,701	9,752,303	(150,000)	11,057,693	48,471,408
Change in cash and cash equivalents	(2,009,446)	(4,882,674)	108,400	(2,821,023)	5,420,344
Cash and cash equivalents, beginning of period	2,707,722	5,528,744		5,528,744	108,400
Cash and cash equivalents, end of period	698,276	646,070	108,400	2,707,722	5,528,744
Supplemental disclosure of non-cash investing and financing activities:
Cash paid for interest				3,201,312	2,655,131
Cash paid for income taxes
Non-cash transactions:
Purchase of rigs for note payable			3,250,000
Sale of property for receivable				1,443,852
Debt issuance cost				400,000
Purchase of properties for common stock			8,025,000	10,895,893	15,787,500
Stock and warrants issued for deferred financing costs				1,611,832	6,867,735
Stock and warrants issued for prepaid financial advisory fees					1,234,510
Stock and warrants issued for prepaid financial office rent				81,997
Default on note in property acquisition			(2,200,000)
Property additions for asset retirement obligation				61,469	479,238
Stock issued for payment on long-term debt				$ 559,872

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Consolidated Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheets [Abstract]
Preferred Stock, shares authorized	10,000,000	10,000,000	10,000,000
Preferred Stock, shares issued
Preferred Stock, shares outstanding
Common Stock Subject to Redemption Rights, par value (In dollars per share)		$ 0.0001	$ 0.0001
Common Stock Subject to Redemption Rights, shares issued		0	10,625
Common Stock Subject to Redemption Rights, shares outstanding		0	10,625
Common stock, par value (In dollars per share)	$ 0.0001	$ 0.0001	$ 0.0001
Common stock, shares authorized	100,000,000	100,000,000	100,000,000
Common stock, shares issued	18,016,143	17,436,825	14,453,592
Common stock, shares outstanding	18,016,143	17,436,825	14,453,592

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Share Based Compensation

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Share Based Compensation [Abstract]

SHARE BASED COMPENSATION

NOTE 10 - SHARE BASED COMPENSATION

In September 2012, the Company adopted the 2012 Equity Incentive Plan (the “Plan”).  Each member of the board of directors and the management team has been periodically awarded restricted stock grants, and in the future will be awarded such grants under the terms of the Plan.

The costs of employee services received in exchange for an award of equity instruments are 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.

During the nine months ended September 30, 2012, the Company granted 256,866 shares of restricted common stock to employees and directors of which 52,698, 81,250, 81,250, and 25,001 shares vest during the years ended December 31, 2012, 2013, 2014, and 2015, respectively. The fair value of these share grants was calculated to be approximately $0.78 million.  The Company also granted 100,000 shares to a consultant and 50,000 shares to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures, valued at $0.58 million

The Company recognized stock compensation expense of approximately $0.80 million and $0.37 million, respectively for the nine and three months ended September 30, 2012, and $5.59 million, and $0.92 million, respectively for the nine and three months ended September 30, 2011.

A summary of restricted stock grant activity for the nine months ended September 30, 2012 is presented below:

	Shares
Balance outstanding at December 31, 2011		2,340,235
Granted		356,865
Vested		(385,749	)
Expired		(25,167	)
Balance outstanding at September 30, 2012		2,286,184

Total unrecognized compensation cost related to unvested stock grants was approximately $2.187 million as of September 30, 2012.  The cost at September 30, 2012 is expected to be recognized over a weighted-average remaining service period of 3 years.

NOTE 12 - SHARE BASED COMPENSATION

The costs of employee services received in exchange for an award of equity instruments are 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.

During the year ended December 31, 2011, the Company granted 238,750 shares of restricted common stock to employees of which 207,016, vest during the year ended December 31, 2011. The Company will vest restricted stock of 192,000, 120,000, and 2,500 for the years ending December 31, 2012, 2013, and 2014, respectively. The fair value of these share grants was calculated to be approximately $4,370,808.

The Company recognized stock compensation expense of approximately $6,161,000, $917,000 and $2,714,000 for the years ended December 31, 2011, 2010 and 2009, respectively. During the year ended December 31, 2011, the Company had a one-time charge of $3,551,000 for stock compensation expense with the grant of 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 year ended December 31, 2011 is presented below

	Shares (1)
Outstanding at March 6,2009	$	-
Granted		371,050
Vested		-
Outstanding at December 31, 2009		371,050
Granted		1,864,747
Vested		-
Outstanding at December 31, 2010		2,235,797
Granted		932,500
Vested		(828,062	)
Outstanding at December 31, 2011	$	2,340,235

(1)   On October 17, 2011, the Company affected a 4:1 reverse stock split.  The values shown are reflecting the reverse stock split.

The Company will recognize $1,066,000, $366,615 and $12,478 for the years ending December 31, 2012, 2013, and 2014, respectively.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2012	Nov. 09, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	RECOVERY ENERGY, INC.
Entity Central Index Key	0001437557
Document Type	S-1
Document Period End Date	Sep. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		18,016,143

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Subsequent Events

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

NOTE 11—SUBSEQUENT EVENTS

On November 5, 2012, the Company liquidated all of its price derivatives for proceeds of $0.60 million.

NOTE 14: SUBSEQUENT EVENTS

On March 19, 2012, the Company entered into agreements with its existing convertible debenture holders to extend the amount of its debenture debt by up to an additional $5.0 million. Proceeds resulting from the increase in the debentures will be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other working capital purposes. Any new producing properties that are developed from the proceeds of this offering will be pledged as collateral to secure the expanded debt.

The initial closing related to these agreements will be in the amount of $1.5 million and is expected to occur prior to March 23, 2012. On or before September 15, 2012, convertible debenture holders may elect to purchase up to an additional $3.5 million in additional debentures. All terms of the expansion convertible debentures are substantively identical to the existing convertible debentures (see Note 7).

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Consolidated Statements of Operations (USD $)	3 Months Ended		9 Months Ended		10 Months Ended	12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010
Revenue
Oil sales	$ 1,775,383	$ 1,650,702	$ 4,685,713	$ 5,534,325		$ 7,148,110	$ 9,504,737
Gas sales	168,897	161,029	397,298	446,386		547,190	68,075
Operating fees	42,853	85,372	132,362	110,282		117,360	13,487
Realized gain on commodity price derivatives	37,341	733,830	49,729	402,256		625,043	570,233
Unrealized gains (losses) on commodity price derivatives	(130,000)		445,609	222,788		(75,609)	(398,840)
Total revenues	1,894,474	2,630,933	5,710,711	6,716,037		8,362,094	9,757,692
Costs and expenses
Production costs	397,793	344,927	1,033,635	1,114,220		1,514,784	862,042
Production taxes	198,781	191,364	561,278	630,718		838,714	1,056,244
General and administrative	1,515,868	1,981,026	5,099,932	8,837,802	1,057,306	10,544,347	15,530,248
Depreciation, depletion and amortization	1,069,068	1,052,946	2,897,156	3,194,301		4,347,117	5,036,648
Impairment of equipment					2,750,000
Impairment of evaluated properties			3,274,718			2,821,176
Bad debt expense							400,000
Fair value of common stock and warrants issued in aborted property acquisitions					8,404,106
Restructuring and related consulting costs					17,700,000
Total costs and expenses	3,181,510	3,570,263	12,866,719	13,777,041	29,911,412	20,066,138	22,885,182
Loss from operations	(1,287,036)	(939,330)	(7,156,008)	(7,061,004)	(29,911,412)	(11,704,044)	(13,127,490)
Other income (expense)	333	62,000	(372)	63,115		71,253
Convertible debentures conversion derivative gain (losses)	600,000	(13,338)	700,000	1,587,699		3,821,792
Interest expense	(2,149,931)	(2,136,950)	(6,320,919)	(6,123,496)	31	(8,218,225)	(6,640,209)
Unrealized gain on lock-up							28,666
Debt inducement expense						(2,800,000)
Net loss	$ (2,836,634)	$ (3,027,618)	$ (12,777,299)	$ (11,533,686)	$ (29,911,381)	$ (18,829,224)	$ (19,739,033)
Earnings per common share
Basic and diluted	$ (0.16)	$ (0.19)	$ (0.72)	$ (0.75)	$ (12.19)	$ (1.21)	$ (2.15)
Weighted average shares outstanding:
Basic and diluted	17,833,466	15,775,135	17,732,304	15,388,772	2,453,921	15,543,758	9,167,803

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Financial Instruments and Derivatives

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Financial Instruments and Derivatives [Abstract]

FINANCIAL INSTRUMENTS AND DERIVATIVES

NOTE 5 - FINANCIAL INSTRUMENTS AND DERIVATIVES

The Company periodically enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices.   As of September 30, 2012, the Company maintained an active commodity swap for 100 barrels per day through December 31, 2012 at a price of $96.25 per barrel, a swap for 100 barrels per day for the period of January 1, 2013 through June 30, 2013 at a price of $106.25 per barrel, and a swap for 100 barrels per day for the period of January 1, 2013 through December 31, 2013 at a price of $96.90.

The amounts of gains and losses recognized as a result of our derivative financial instruments were as follows:

	Three months ended September 30,					Nine months ended September 30,
	2012			2011		2012		2011
Realized gain on commodity price derivatives	$	37,341		$	733,830	$	49,729	$	402,256
Unrealized gains (losses) on commodity price derivatives	$	(130,000	)	$	-	$	445,609	$	222,788

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 6 — “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. On November 5, 2012, the company liquidated all of its price derivatives for proceeds of $0.60 million.

NOTE 5 - FINANCIAL INSTRUMENTS AND DERIVATIVES

Periodically, the Company enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. During the year ended December 31, 2011, the Company terminated and settled certain future commodity swaps resulting in a realized gain of approximately $625,000.

As of December 31, 2011, the Company maintained an active commodity swap for 100 barrels per day through December 31, 2012, at a price of $96.25 per barrel.

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

	For the Year Ended December 31,
	2011			2010			2009(1)
Realized gain on oil price hedges	$	625,043		$	570,233		$	-
Unrealized loss oil price hedges	$	(75,609	)	$	(398,840	)	$	-

(1)   Prior to January 1, 2010, the Company did not enter any derivative financial instruments. 

Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are recognized in the unrealized gain (loss) on hedge contracts line on the consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the realized gain (loss)  line on the consolidated statement of income. As of December 31, 2011, the Company recorded an unrealized loss on its only active swap of $75,609.

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Wells in Progress

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Wells In Progress [Abstract]

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

NOTE 4 – WELLS IN PROGRESS
 

As of September 30, 2012, the Company has one well in progress that has been drilled, completed and is pending further evaluation as to its potential to ultimately produce commercial quantities of hydrocarbons.  This well is currently carried at a cost of $3.82 million.  The Company believes that this well should be ultimately capable of commercial production, but will need to invest additional capital to obtain this status.  However, should this well be ultimately plugged and abandoned, all capitalized costs would be transferred to the full cost pool.  Given the current status of the ceiling tests as of September 30, 2012, the current carrying costs would exceed the ceiling by the amount of $1.44 million, which would flow through the income statement as an expense if the well were assumed to be non-productive as of September 30, 2012.

Likewise, operations that are being conducted on this well are extending the primary terms of leases that comprise approximately 6,919 net acres and that are currently being carried at a cost of approximately $4.1 million.  Absent a successful completion of this well, the lease terms of some or all of these acres may expire, and the carrying costs of these leases would also be subject to the ceiling test.

NOTE 4 – WELLS IN PROGRESS

The following table reflects the net changes in capitalized additions to wells in progress during 2010 and 2009:

	For the Year Ended December 31,
	2011			2010
Beginning balance	$	1,219,254			-
Additions to capital wells in progress costs		8,904,532			1,219,254
Reclassifications to proved properties		(3,698,563	)		-
Ending balance	$	6,425,509		$	1,219,254

All wells in progress have been capitalized for less than one year.

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Quarterly Results (Unaudited)

12 Months Ended

Dec. 31, 2011

Quarterly Results [Abstract]

QUARTERLY RESULTS

NOTE 16- QUARTERLY RESULTS (UNAUDITED)

The following tables contain selected unaudited statement of operations information for each quarter of 2011 and 2010. The Company believes that the following information reflects all normal recurring adjustments necessary for a fair presentation of the information for the periods presented. The operating results for any quarter are not necessarily indicative of results for any future period.

	Year Ended December 31, 2011
	Fourth				Third				Second				First
	Quarter				Quarter				Quarter				Quarter
Revenues		$	1,944,454			$	2,630,933			$	2,811,429			$	1,273,675
Income (loss) from operations			(6,297,854	)			(939,330	)			(4,069,541	)			(2,052,133	)
Net earnings (loss)			(7,295,537	)			(3,027,618	)			(4,762,881	)			(3,743,187	)
Net earnings per common share:
Basic and diluted		$	(0.47	)		$	(0.19	)		$	(0.30	)		$	(0.25	)
Weighted average shares outstanding
Basic and diluted			15,543,758				15,775,135				15,635,346				14,778,206

	Year Ended December 31, 2010
	Fourth				Third				Second				First
	Quarter				Quarter				Quarter				Quarter
Revenues		$	1,519,702			$	2,552,790			$	5,194,849			$	490,351
Income (loss) from operations			(4,191,728	)			(5,900,630	)			(792,880	)			(2,242,252	)
Net earnings (loss)			(6,230,293	)			(7,491,246	)			(3,196,779	)			(2,820,715	)
Net earnings per common share:
Basic and diluted		$	(1.47	)		$	(2.53	)		$	(1.99	)		$	(1.04	)
Weighted average shares outstanding
Basic and diluted			9,167,803				2,962,882				6,362,922				2,927,759

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Related Party Transactions

12 Months Ended

Dec. 31, 2011

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

NOTE 9 - RELATED PARTY TRANSACTIONS

Since its inception, five property acquisitions the Company completed have been with the same seller, Davis.  As of December 31, 2011, Davis owned approximately 19.1 % of the common stock of the Company. The cash portion of the purchase price for the first three acquisitions was financed with loans from Hexagon, which owned approximately 15.7% of the stock issued and outstanding at December 31, 2011.  Hexagon received overriding royalty interests in both the Albin Field assets and the State Line Field assets. Hexagon also received warrants to purchase 500,000 shares of the Company’s common stock at $10.00 per share in connection with the financing of an acquisition and warrants to purchase 250,000 shares the Company’s common stock for $6.00 per share in connection with amendments to the loan agreements. A representative of Hexagon also served on the Company’s Board of Directors, until his resignation on January 31, 2012.

The Company entered into an exploration and development agreement with TRW to drill two wells.  The joint venture partners of TRW are also shareholders of the Company.

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Commitments and Contingencies

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 8 - COMMITMENTS AND CONTINGENCIES

Environmental and Governmental Regulation

At September 30, 2012, 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, 2012, 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 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.

Other Contingencies

We could be liable for liquidated damages under registration rights agreements covering approximately 3.2 million shares of our common stock if we fail to maintain the effectiveness of a prior registration statement as required in the agreements.  In such case, we would be required to pay monthly liquidated damages of up to $0.23 million. The maximum aggregate liquidated damages are capped at $1.37 million.  

Under the terms of the Supplemental Debenture agreements, the Company has a commitment to drill four additional wells.  Such agreements do not specify the location, timing, target zones, or other conditions related to these wells.  However, the Company anticipates that the capital provision required to satisfy this provision will be approximately $3.3 million.

NOTE 8 - COMMITMENTS and CONTINGENCIES

Environmental and Governmental Regulation

At December 31, 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 December 31, 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.

Operating Leases

The Company leases an office space under a one year operating lease in Denver, Colorado.  Rent expense for the years ended December 31, 2011 and December 31, 2010, was $82,068 and $54,500, respectively. The Company will have minimum lease payments of $72,000 for the year ending December 31, 2012.

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Shareholders' Equity (Details Textual) (USD $)	1 Months Ended			3 Months Ended		9 Months Ended		10 Months Ended	12 Months Ended							12 Months Ended		9 Months Ended	10 Months Ended	12 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Oct. 31, 2011	May 31, 2010	May 31, 2009	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Feb. 28, 2011	May 28, 2010	Apr. 30, 2010	Mar. 31, 2010	Dec. 31, 2011 Maximum [Member]	Dec. 31, 2011 Minimum [Member]	Sep. 30, 2012 Restricted Stock [Member]	Dec. 31, 2009 Restricted Stock [Member]	Dec. 31, 2011 Restricted Stock [Member]	Dec. 31, 2010 Restricted Stock [Member]	Sep. 30, 2012 Restricted Stock [Member] Employees, Board Members and Consultants [Member]	Sep. 30, 2012 Restricted Stock [Member] T R Winston Company LLC [Member]	Sep. 30, 2012 Warrant [Member]	Sep. 30, 2012 Warrant [Member]	Dec. 31, 2011 Warrant [Member]	Dec. 31, 2010 Warrant [Member]	Dec. 31, 2011 Common Stock [Member]	Dec. 31, 2010 Common Stock [Member]	Dec. 31, 2011 Convertible Notes Payable [Member]	Dec. 31, 2011 Temporary Equity [Member]	Sep. 21, 2010 Temporary Equity [Member]
Shareholder's Equity (Textual)
Shares issued for payment of quarterly interest expense on the convertible debentures																							197,619
Shares issued for payment of quarterly interest expense on the convertible debentures, value																							$ 690,000
Common stock closing price																								$ 4.40	$ 4.40	$ 3.01
Grant of restricted shares to employess, former chief financial officer during the period																		356,865	371,050	932,500	1,864,747	356,865	50,000
Grant of restricted shares to employees, board members, consultants and T.R. Winston & Company LLC during the period, fair value																						1,490,000	230,000
Warrants issued to financial advisory group																								600,000	600,000
Warrants vested and expected to vest, outstanding, number																								100,000	100,000
Strik price per share										$ 1.50														$ 5.00	$ 5.00		$ 1.50
Warrant, vesting period																									3 years
Description of installment of vesting period																									Warrants vest monthly in six equal amounts over the six month term of the agreement
Recognized stock compensation expense for warrants				370,000	920,000	800,000	5,590,000	2,714,000	6,161,000	917,000	2,714,000													80,000
Consulting fee																									10,000
Final consulting payment during the last month of the contract																									90,000
Aggregate intrinsic value of warrants																								0	0	0
Lock up shares outstanding																				0
Shares reserved for possible conversion																1,926,471	893,617
Debentures, convertible, conversion price (per share)				$ 4.25		$ 4.25			$ 4.25			$ 9.40				$ 4.25	$ 9.40
Stock issued during period, shares																												2,983,233	11,749,467
Common stock issued for acquisitions, shares																												2,983,233	2,929,167
Common stock issued for acquisitions, value									10,895,893	15,786,621																		10,896,071	15,787,500
Common stock issued for services, Shares																												10,000	502,216
Common stock issued for services									81,997	2,256,088																		82,000	2,256,239
Share issued for loan agreements, value										5,250,000
Share issued for loan agreements, shares										1,250,000
Shares issued for restricted stock grants to employees, shares									238,824																				2,235,797
Shares issued for restricted stock grants to employees, value									6,161,111																				10,283,622
Stock issued during period shares for interest expense																														78,972
Stock issued during period shares for interest expense, value																														559,860
Share issued for cash, shares										3,978,788																375,333
Sahres issued for cash, value										20,046,733																2,903,794
Conversion of stock in shares			2,100,000																									1,976,471
Common stock, shares issued				18,016,143		18,016,143			17,436,825	14,453,592				2,500,000	750,000																5,313	2,658
Common stock, shares outstanding				18,016,143		18,016,143			17,436,825	14,453,592																					5,313
Common stock value				1,801		1,801			1,744	1,445																					172,516
Stock issued during period shares for private placement										3,975,300																	15,901,200
Warrants exercised										853,500			2,000,000	2,000,000													250,000
Share price per unit										$ 1.50														$ 5.00	$ 5.00		$ 1.50
Warrants exercise price, per share		$ 6.00								$ 6.00																	$ 2.20
Warrant exercised value										1,600,000																	5,121,000
Value for new warrants										2,953,450																	2,953,450
Aggregate intrinsic value																										0	6,687,000
Closing price of stock																										$ 5.20	$ 8.20
Weighted average remaining contractual life (in years)																									2 years 9 months 21 days	3 years 2 months 5 days	4 years 1 month 24 days
Conversion price				$ 4.25		$ 4.25			$ 4.25			$ 9.40				$ 4.25	$ 9.40
Additional Stockholders Equity (Textual)
Preferred Stock, shares authorized				10,000,000		10,000,000			10,000,000	10,000,000
Common stock, shares authorized				100,000,000		100,000,000			100,000,000	100,000,000
Preferred Stock, shares issued
Preferred Stock, shares outstanding
Convertible debenture percentage									8.00%			8.00%
Inducement expense									2,800,000
Increased additional paid-in capital									2,800,000
Dilutive shares outstanding									1,082,854
Description of refusal to purchase of debentures									Up to 15% of any common stock, preferred stock or convertible debt offering by Recovery through December 31, 2012
Convertible notes payable face value									$ 8,400,000
Exercised price of new warrant per share										$ 8.80
Warrant expire date										Sep. 29, 2015
Reverse stock split	4:1					four-for-one			four-for-one

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Fair Value of Financial Instruments

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Fair Value Of Financial Instruments [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs, used in the valuation methodologies in measuring fair value:

●          Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

●          Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

●          Level 3 – Unobservable inputs which are supported by little or no market activity.

The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

The Company measures its cash equivalents and investments at fair value.  The Company’s cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits are primarily classified within Level 1.  Cash equivalents and short-term investments are valued primarily using quoted market prices utilizing market observable inputs.

Derivative Instruments

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

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

At September 30, 2012, the types of derivative instruments utilized by the Company included commodity swaps.  The oil derivative markets are highly active.  Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange.  As such, the Company has classified these instruments as Level 2.

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

Asset Retirement Obligation

The income valuation technique is utilized to determine the fair value of its asset retirement obligation liability at the point of inception by taking into account: 1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which are based on estimates from reserve engineers; 3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money.  Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.

Convertible Debentures Payable Conversion Feature

In February 2011, the Company issued in a private placement $8.40 million aggregate principal amount of three year 8% Senior Secured Convertible Debentures (“Debentures”) with a group of accredited investors.  During the nine months ended September 30, 2012, the Company issued an additional $5.00 million of Debentures, resulting in a total of $13.40 million of Debentures outstanding as of September 30, 2012.  As of September 30, 2012, the Debentures are convertible at any time at the holders’ option into shares of our common stock at $4.25 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 Company engaged a third party to complete a valuation of this conversion feature as of September 30, 2012 (see Note 7—Loan Agreements). The valuation was completed using Level 3 inputs.

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

September 30, 2012

	Level 1		Level 2		Level 3			Total
Assets
Commodity derivative instruments	$	-	$	370,000	$	-		$	370,000
Total assets, at fair value	$	-	$	370,000	$	-		$	370,000
Liability
Convertible debentures conversion derivative liability	$	-	$	-	$	(1,300,000	)	$	(1,300,000	)
Total liability, at fair value	$	-	$	-	$	(1,300,000	)	$	(1,300,000	)

December 31, 2011

	Level 1		Level 2			Level 3			Total
Liability
Commodity derivative instruments	$	-	$	(75,609	)		-		$	(75,609	)
Convertible debentures conversion derivative liability		-		-			(1,300,000	)		(1,300,000	)
Total liability at fair value	$	-	$	(75,609	)	$	(1,300,000	)	$	(1,375,609	)

The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of September 30, 2012: 

Beginning balance, December 31, 2011	$	(1,300,000	)
Convertible debentures conversion derivative gain		700,000
Additions to derivative liability from Supplemental Debenture		(700,000	)
Ending balance, September 30, 2012	$	(1,300,000	)

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 nine and three months ended September 30, 2012. 

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs used in the valuation methodologies in measuring fair value:

● Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

● Level 2 – Include other inputs that are directly or indirectly observable in the marketplace.

● Level 3 – Unobservable inputs which are supported by little or no market activity.

The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

The Company measures its cash equivalents and investments at fair value. The Company’s cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits are primarily classified within Level 1. Cash equivalents and short-term investments are valued primarily using quoted market prices utilizing market observable inputs.

Derivative Instruments

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

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

At December 31, 2011, the types of derivative instruments utilized by the Company included commodity swaps (see Note 5). The oil derivative markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange.  As such, the Company has classified these instruments as Level 2.

Asset Retirement Obligation

The income valuation technique is utilized determine the fair value of its asset retirement obligation liability at the point of inception by taking into account 1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which is based on estimates from reserve engineers; 3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.

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 (“Debentures”) with a group of accredited investors. As of December 31, 2011, the Debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $4.25 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 Company engaged a third party to complete a valuation of this conversion feature as of December 31, 2011 (see Note 7). The valuation was completed using Level 3 inputs.

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

December 31, 2011

	Level 1		Level 2			Level 3			Total
Liability
Derivative instruments	$	-	$	(75,609	)	$	-		$	(75,609	)
Convertible notes payable  Conversion feature		-		-			(1,300,000	)		(1,300,000	)
Total liability at fair value	$	-	$	(75,609	)	$	(1,300,000	)	$	(1,375,609	)

December 31, 2010

	Level 1		Level 2			Level 3		Total
Liability
Derivative instruments	$	-	$	(398,840	)	$	-	$	(398,840	)
Total liability at fair value	$	-	$	(398,840	)	$	-	$	(398,840	)

The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of December 31, 2011:

	Convertible debt feature (1)
Beginning balances, December 31, 2010		-
Additions of convertible debt feature		(1,300,000	)
Ending balance as of December 31, 2011		(1,300,000	)

(1)   The Company entered into the convertible debt during the year ended December 31, 2011.

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 twelve months ended December 31, 2011 and December 31, 2010.

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Loan Agreements

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Loan Agreements [Abstract]

LOAN AGREEMENTS

NOTE 7 – LOAN AGREEMENTS

Term Loans

The Company entered into three separate loan agreements with Hexagon during 2010.  All three loans bear annual interest of 15% and mature on December 31, 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 $6.00 million loan agreement, with an original maturity date of December 1, 2010.  Effective April 14, 2010, the Company entered into a $15 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 loans 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.

We 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 $1.60 million.  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 date of the loans to September 1, 2011.  During the last six months of 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2.00 million as payment on the loans. In November 2011, Hexagon extended the maturity to January 1, 2013.  In November 2011, Hexagon also temporarily advanced the Company an additional amount of $0.31 million, which was repaid in full in February 2012.  In March 2012, Hexagon extended the maturity of the loans to June 30, 2013, and in connection there with, the Company agreed to make minimum monthly note payments of $0.33 million, effective immediately.  In July 2012, Hexagon extended the maturity date to September 30, 2013. In November 2012, Hexagon extended the maturity date of the loans to December 31, 2013.

As of September 30, 2012, the total debt outstanding under these facilities is $20.29 million, of which $0.87 million is the current portion of long term debt.

The Company is subject to certain non-financial covenants with respect to the Hexagon loan agreements.  As of September 30, 2012, 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 Debentures Payable

In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of Debentures.  Initially, the Debentures were convertible at any time at the holders' option into shares of our 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 $0.40 million of Debentures equal to 5% of the gross proceeds from the sale.  The Company is amortizing the $0.40 million over the life of the loan as deferred financing costs.  The Company amortized $0.13 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.18 million of deferred financing costs to be amortized through February 2014. 

In December, 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share. This amendment was an inducement consideration to the Debenture holders for their agreement to release a mortgage on certain properties so the properties could be sold. The sale of these properties was effective December 31, 2011, and a final closing occurred during the three months ended March 31, 2012.

On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to increase the amount of its Debentures by up to an additional $5.0 million (the “Supplemental Debentures”).  Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of Supplemental Debentures are to be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other general corporate purposes. Any new producing properties that are developed from the proceeds of Supplemental Debentures are to be pledged as collateral under a mortgage to secure future payment of the Debentures and Supplemental Debentures. All terms of the Supplemental Debentures are substantively identical to the Debentures.  The Agreements also provided for the payment of additional consideration to the purchasers of Supplemental Debentures in the form of a proportionately reduced, 5% carried working interest in any properties developed with the proceeds of the Supplemental Debenture offering.

Through July 2012, we received $3.04 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development of six new wells, resulting in a total investment of $3.69 million.  Five of these wells resulted in commercial production, and one well was plugged and abandoned.

In August 2012, the Company and certain holders of the Supplemental Debentures agreed to renegotiate the terms of the Supplemental Debenture offering.  These negotiations concluded with the issuance of an additional $1.96 million of Supplemental Debentures.  The August 2012 modifications to the Supplemental Debenture agreements increased the carried working interest from 5% to 10% and also provided for a one-year, proportionately reduced net profits interest of 15% in the properties developed with the proceeds of the Supplemental Debenture offering, as well as the next four properties to be drilled and developed by the Company.

The Company has estimated the total value of consideration paid to Supplemental Debenture holders in the form of the modified net profits interest and carried working interest to be approximately $1.16 million, and recorded this amount as a debt discount to be amortized over the remaining life of the Supplemental Debentures. 

We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect to September 30, 2012, the Supplemental Debentures.  This valuation resulted in an estimated derivative liability as of September 30, 2012 and December 31, 2011 of $1.3 million and $1.3 million, respectively.  The portion of the derivative liability that is associated with the Supplemental Debentures, in the approximate amount of $0.70 million, has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.

During the nine and three months ended September 30, 2012, the Company amortized $1.65 million and $0.71 million, respectively of debt discounts.

On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures.  The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs.  The Company amortized $0.01 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.22 million of deferred financing costs to be amortized through February 2014. 

As of September 30, 2012 and December 31, 2011, the convertible debt is recorded as follows:

	As of				As of
		September 30,  2012				December 31, 2011
Convertible debentures		$	13,400,000			$	8,400,000
Debt discount			(3,804,947	)			(3,470,932	)
Total convertible debentures, net		$	9,595,053			$	4,929,068

Annual debt maturities as of September 30, 2012 are as follows:

Year 1	$	873,142
Year 2		32,819,197
Thereafter		-
Total	$	33,692,339

Interest Expense

For the three months ended September 30, 2012 and 2011, the Company incurred interest expense of approximately $2.15 million and $2.14 million, respectively, of which approximately $1.29 million and $1.50 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures payable interest paid in stock.

For the nine months ended September 30, 2012 and 2011, the Company incurred interest expense of approximately $6.32 million and $6.12 million, respectively, of which approximately $3.8 million and $3.70 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures payable interest paid in stock.

NOTE 7 - 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 June 30, 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, 2011. During the last half of 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2 million as payment on the notes. In November 2011, Hexagon extended the maturity to January 1, 2013.  In March 2012, Hexagon agreed to extend the maturity of the notes to June 30, 2013, and in connection there with, the Company agreed to make minimum monthly note payments of $325,000, effective immediately.  In November 2011, Hexagon also temporarily advanced the Company an additional amount of $309,000, which was repaid in full in February 2012.

The Company is subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements. As of December 31, 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 completed a private placement of $8,400,000 aggregate principal amount of three year 8% Senior Secured Convertible Debentures (the "Debentures") with a group of accredited investors. Initially, the Debentures were 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.  The Company is amortizing the $400,000 over the life of the loan as deferred financing costs.  The Company amortized $88,888 of deferred financing costs into interest expense during the year ended December 31, 2011 and has $311,112 of deferred financing costs to be amortized over a straight-line basis until January 2014.

In December, 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share. Therefore, the Debenture are currently convertible into shares of common stock. This amendment was consideration to the Debenture holders in exchange for their agreement to release a mortgage on certain properties so the properties could be sold. The sale of these properties was completed effective December 31, 2011.

The Company engaged a third party valuation firm to complete a valuation of both the conversion feature and the inducement. This valuation resulted in an estimate of the inducement expense of $2.8 million and estimate of the derivative liability as of December 31, 2011 of $1.3 million. A previous independent valuation of the derivative liability estimated the derivative liability as of March 31, 2011 at approximately $5.1 million. The reduction in the derivative value from $5.1 million as of March 31, 2011 to $1.3 million as of December 31, 2011 resulted in a derivative gain of $3.8 million during the year ended December 31, 2011. As of December 31, 2011, the convertible debt is recorded as follows:

	As of  December 31, 2011
Convertible debt		8,400,000
Debt discount		(3,470,932	)
Total convertible debt, net		4,929,068

Annual debt maturities for our debt under our term notes and convertible notes payable obligations as of December 31, 2011 are as follows:

2012	1,150,966
2013	20,129,670
2014	8,400,000
Thereafter	--
Total	29,680,636

Interest Expense

For the years ending December 31, 2011 and December 31, 2010, the Company incurred interest expense of approximately $8,218,000 and $6,600,000, respectively, of which approximately $5.0 million and $4.0 million, respectively, were 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.

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Shareholders' Equity

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Shareholders' Equity [Abstract]

SHAREHOLDERS’ EQUITY

NOTE 9 - SHAREHOLDERS’ EQUITY

Common Stock

Effective October 19, 2011, the Company completed a four-for-one reverse stock split of 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, 2012, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 18,016,143 shares of common stock were issued and outstanding.  No preferred shares were issued or outstanding.  

During the nine months ended September 30, 2012, the Company granted 356,865 shares of common stock as restricted stock grants to employees, board members, and consultants valued at $1.49 million.  The Company also issued 197,619 shares for payment of quarterly interest expense on the convertible debentures valued at $0.69 million, and 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as placement agent of the Supplemental Debentures.

Warrants

During September 2012, the Company entered into an agreement to issue 600,000 warrants to a financial advisory group. The 600,000 warrants vest monthly in six equal amounts over the six month term of the agreement, have a term of 3 years, and a strike price of $5.00 per share.  The Company records an expense for the value of the warrants on each vesting date.  During the three months ended September 30, 2012, the Company recorded an expense of $0.08 million for the 100,000 warrants that were vested as of September 30, 2012.  Additionally, the agreement provides that the Company will pay a monthly consulting fee of $10,000, with a final payment of $90,000 during the last month of the contract.  The Company may cancel the agreement at any time to avoid any future cash payments or vesting of remaining unvested warrants.

A summary of warrant activity for the nine months ended September 30, 2012 is presented below:

			Weighted-Average
	Warrants		Exercise Price
Outstanding at December 31, 2011		5,638,900	$	7.04
Granted		600,000		5.00
Exercised, forfeited, or expired		-		-
Outstanding at September 30, 2012		6,238,900	$	6.84

The aggregate intrinsic value of the warrants was approximately $0 as of both September 30, 2012 and December 31, 2011, based on the Company’s closing common stock price of $4.40 and $3.01, respectively; and the weighted average remaining contract life was 2.81 years and 3.18 years, respectively.

NOTE 11 - SHAREHOLDERS’ EQUITY

As of December 31, 2011, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 17,436,825 shares of common stock were issued and outstanding. No preferred shares were issued or outstanding. Preferred shares may be issued in such series as Preferred as determined by the Board of Directors. No lock-up or restricted shares were outstanding as of December 31, 2011.

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

In December 2011, the Company provided the 8% convertible debenture holders an inducement to convert their conversion price from $9.40 to $4.25.  An inducement expense of $2.8 million was recognized in 2011. This transaction also increased additional paid-in capital by $2.8 million.  This reduction in conversion price also increased potential dilutive shares outstanding as of December 31, 2011 by 1,082,854 shares from 893,617 to 1,926,471 shares reserved for possible conversion.

In connection with this inducement, the Company entered into an amendment to our 8% senior secured convertible debentures whereby, in addition to the inducement, the mortgage on certain of the Company's oil and gas leases was released and in substitution, we granted a lien on certain replacement oil and gas leases in Nebraska and Wyoming. As partial consideration for the substitution of this collateral, the amendment also provides the holders of the debentures with the first right of refusal to purchase up to 15% of any common stock, preferred stock or convertible debt offering by Recovery through December 31, 2012 at the offering price.

During the year ending December 31, 2011, the Company issued 2,983,233 shares of common stock. The stock issuances were comprised of 2,983,233 shares issued for acquisitions valued at $10,896,071, 10,000 shares issued for services valued at $82,000, 238,824 shares issued as restricted stock grants to employees valued at $6,161,111, 78,972 shares is for interest expense on the convertible notes payable valued at $559,860, 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 current conversion price of $4.25 per share, these notes would convert into 1,976,471 shares of common stock. The conversion price is subject to other adjustments (See Note 7).

During the year ended December 31, 2010, the Company issued 11,749,467 shares of common stock.  The stock issuances were comprised of 2,929,167 shares issued for acquisitions valued at $15,787,500, 502,216 shares issued for services valued at $2,256,239, 1,250,000 shares issued in connection with the loan agreements valued at $5,250,000, 2,235,797 shares issued as restricted stock grants to employees valued at $10,283,622, and 3,978,788 shares issued for $20,046,733 of cash.

During the year ended December 31, 2010, the Company issued common shares for cash. Included in these shares was a private placement of 3,975,300 units at $1.50 per unit, which included one share of common stock and one common stock purchase warrant. The warrants are exercisable at $1.50 per share through May 23, 2015. Warrants of 853,500 were subsequently exercised during 2010 for $5,121,000 of cash. In connection with the exercise, the Company granted a new warrant for each warrant exercised. The new warrants have an exercise price of $8.80 per share, which was slightly greater than the concurrent market price of the Company's common stock, and expire on September 29, 2015. The value of the new warrants, calculated at $2,953,450 using the Black Scholes method, was expensed as a warrant modification and included in general and administrative expenses.

Temporary Equity

As part of the reverse merger in 2009, 5,313 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 5,313 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 2,658 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 2,658 shares covered under the lock-up agreement were moved to permanent on equity. 

Warrants

During 2010, the Company issued common shares for cash. Included in these shares was a private placement of 15,901,200 units at $1.50 per unit, which included one share of common stock and one common stock purchase warrant. The warrants are exercisable at $1.50 per share through May 23, 2015. 3,414,000 of these warrants were subsequently exercised during 2010 for $5,121,000 of cash. In connection with the exercise, the Company granted a new warrant for each warrant exercised. The new warrants have an exercise price of $2.20 per share, which was slightly greater than the concurrent market price of the Company's common stock, and expire on September 29, 2015. The value of the new warrants, calculated at $2,953,450 using the Black Scholes method, was expensed as a warrant modification and included in general and administrative expenses

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 Note7).

A summary of warrant activity for the years ended December 31, 2011 and December 31, 2010 is presented below:

	Warrants (1)			Weighted-Average  Exercise  Price (1)
Outstanding at December 31, 2009		187,500		$	14.00
Granted		6,430,233			6.68
Exercised, forfeited, or expired		(853,500	)		6.00
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 December 31, 2011		5,638,900		$	6.33

(1)   On October 17, 2011, the Company performed a 4:1 reverse stock split.  The values shown are reflecting the reverse stock split.

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 December 31, 2011 and December 31, 2010, respectively, and the weighted average remaining contract life was 3.68 years and 4.15 years.  

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

	For the years ended December 31,
	2011			2010
Weighted-average volatility		97	%		80	%
Expected dividends		0.00	%		0.00	%
Expected term (in years)		3 – 5			3 – 5
Risk-free rate		2.02	%		1.49	%

The Company has not adopted a stock incentive plan for its management team.  Members of the board of directors and the management team are periodically awarded restricted stock grants. 

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Subsequent Events (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Nov. 30, 2012	Sep. 15, 2012	Mar. 23, 2012	Mar. 19, 2012
Subsequent Events (Textual)
Proceed from liquidation of price derivative	$ 0.60
Maximum additional extended amount of debenture debt agreements with convertible debenture holders				5.0
Initial closing amount of debenture debt			1.5
Additional debenture purchased by convertible debenture holders		$ 3.5

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Supplemental Oil and Gas Reserve Information (Unaudited) (Details 1) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary of future net cash flows relating to proved oil and gas
Future oil and gas sales	$ 55,295	$ 51,816
Future production costs	(16,579)	(11,614)
Future development costs	(8,481)	(8,063)
Future income tax expense (2)
Future net cash flows	30,235	32,139
10% annual discount	(10,221)	(8,544)
Standardized measure of discounted future net cash flows	$ 20,014	$ 23,595

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Drilling Rigs (Details) (USD $)	1 Months Ended		10 Months Ended	12 Months Ended
	May 31, 2010	May 31, 2009 DrillingRig	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Drilling Rings (Textual)
Number of drilling rigs		2
Purchase of rigs for note payable		$ 3,250,000	$ 3,250,000
Shares of common stock due to conversion of convertible note		2,100,000
Estimated net realizable value of future drilling operation						500,000
Impairment on project						2,750,000
Sale of rigs	700,000
Cash recieved on rigs sold	100,000
period for notes issued against remaining balance of ring sold	5 years
Notes receivables reserved against any future uncertainity					$ 400,000

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Supplemental Oil And Gas Reserve Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Oil and Gas Reserve Information [Abstract]

Schedule of proved developed and undeveloped oil and gas reserve

	Crude Oil (Bbls)			Natural Gas  (Mcf)
December 31, 2009		-			-
Purchase of reserves		643,955			-
Revisions of previous estimates		123,679			-
Extensions and discoveries		58,463			323,493
Sale of reserves		-			-
Production		(133,709	)		(14,914	)
December 31, 2010		692,388			308,579
Purchase of reserves		-			-
Revisions of previous estimates		(268,718	)		(44,919	)
Extensions, discoveries		266,000			-
Sale of reserves
Production		(81,433	)		(115,583	)
December 31, 2011		608,237			148,077
Proved Developed Reserves, included above:
Balance, December 31, 2009		-			-
Balance, December 31, 2010		277,669			308,579
Balance, December 31, 2011		215,693			148,077
Proved Undeveloped Reserves, included above:
Balance, December 31, 2009		-			-
Balance, December 31, 2010		414,719			-
Balance, December 31, 2011		392,545			-

Summary of future net cash flows relating to proved oil and gas

	For the Year Ended December 31, (in thousands)
	2011			2010			2009 (1)
Future oil and gas sales	$	55,295		$	51,816		$	-
Future production costs		(16,579	)		(11,614	)		-
Future development costs		(8,481	)		(8,063	)		-
Future income tax expense (2)		-			-			-
Future net cash flows		30,235			32,139			-
10% annual discount		(10,221	)		(8,544	)		-
Standardized measure of discounted future net cash flows	$	20,014		$	23,595		$	-

(1) Prior to January 2010, the Company did not own any oil and gas assets.

(2) Our calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all years reported. We expect that all of our Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company's operations, and resulting NOLs, are attributable to our oil and gas assets. There were no taxes in any year as the tax basis and NOL's exceeded the future net revenue.

Summary of change in the standardized measure of discontinued future net cash flows

	2011			2010			2009 (1)
Balance at beginning of period	$	23,595		$	-		$	-
Sales of oil and gas, net		(5,342	)		(7,655	)		-
Net change in prices and production costs		8,006			3,084			-
Net change in future development costs		-			(4,563	)		-
Extensions and discoveries		5,883			5,067			-
Acquisition of reserves					18,967			-
Sale of reserves					-			-
Revisions of previous quantity estimates		(14,804	)		5,245			-
Previously estimated development costs incurred					-			-
Net change in income taxes					-			-
Accretion of discount		2,360			2,043			-
Other		316			1,407			-
Balance at end of period	$	20,014		$	23,595		$	-

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Loan Agreements (Details) (USD $)	Sep. 30, 2012	Aug. 31, 2012	Dec. 31, 2011
Convertible debt
Convertible debt	$ 13,400,000		$ 8,400,000
Debt discount	(3,804,947)	(1,160,000)	(3,470,932)
Total convertible debt, net	9,595,053		4,929,068
Annual debt maturities
2012	873,142		1,150,966
2013	32,819,197		20,129,670
2014			8,400,000
Thereafter
Total	$ 33,692,339		$ 29,680,636

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Drilling Rigs

12 Months Ended

Dec. 31, 2011

Drilling Rigs [Abstract]

DRILLING RIGS

NOTE 13 – DRILLING RIGS

In May 2009, two drilling rigs were contributed to the Company for a note of $3,250,000.  These rigs were recorded at estimated fair value as this was lower than their predecessor cost basis. The note holder subsequently converted the note for 2,100,000 shares of common stock (Note 3).  These rigs required certain capital improvements prior to their ability to be functional in operations.

In 2009, management determined that future drilling operations were not part of their strategic plans.  Management estimated the net realizable value to be $500,000; therefore, an impairment of $2,750,000 was recorded for the period ending December 31, 2009. 

In May 2010, the Company entered into a purchase and sale agreement for the rigs.  The Company sold the rigs for $700,000 under which the Company received $100,000 in cash and the balance in a five-year secured note. The acquirer defaulted on the note and the Company is now pursuing the remedies afforded to it under the note and security agreement.  The Company believes it is in a first lien position on the underlying collateral, however, in 2010 the Company elected to fully reserve the $400,000 note receivable as the ability to recover the amount and the value of the underlying collateral was uncertain.

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Fair Value of Financial Instruments (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Fair Value Of Financial Instruments [Abstract]

Summary of fair value of assets and liabilities measured at fair value

September 30, 2012

	Level 1		Level 2		Level 3			Total
Assets
Commodity derivative instruments	$	-	$	370,000	$	-		$	370,000
Total assets, at fair value	$	-	$	370,000	$	-		$	370,000
Liability
Convertible debentures conversion derivative liability	$	-	$	-	$	(1,300,000	)	$	(1,300,000	)
Total liability, at fair value	$	-	$	-	$	(1,300,000	)	$	(1,300,000	)

December 31, 2011

	Level 1		Level 2			Level 3			Total
Liability
Commodity derivative instruments	$	-	$	(75,609	)		-		$	(75,609	)
Convertible debentures conversion derivative liability		-		-			(1,300,000	)		(1,300,000	)
Total liability at fair value	$	-	$	(75,609	)	$	(1,300,000	)	$	(1,375,609	)

December 31, 2011

	Level 1		Level 2			Level 3			Total
Liability
Derivative instruments	$	-	$	(75,609	)	$	-		$	(75,609	)
Convertible notes payable  Conversion feature		-		-			(1,300,000	)		(1,300,000	)
Total liability at fair value	$	-	$	(75,609	)	$	(1,300,000	)	$	(1,375,609	)

December 31, 2010

	Level 1		Level 2			Level 3		Total
Liability
Derivative instruments	$	-	$	(398,840	)	$	-	$	(398,840	)
Total liability at fair value	$	-	$	(398,840	)	$	-	$	(398,840	)

Summary of changes in fair value of Level 3 financial assets and liabilities

Beginning balance, December 31, 2011	$	(1,300,000	)
Convertible debentures conversion derivative gain		700,000
Additions to derivative liability from Supplemental Debenture		(700,000	)
Ending balance, September 30, 2012	$	(1,300,000	)

	Convertible debt feature (1)
Beginning balances, December 31, 2010		-
Additions of convertible debt feature		(1,300,000	)
Ending balance as of December 31, 2011		(1,300,000	)

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Fair Value of Financial Instruments (Details 1) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2011
Summary of changes in fair value of Level 3 financial assets and liabilities
Beginning balances, December 31, 2011	$ (1,300,000)
Additions of convertible debt feature	(700,000)	(1,300,000)
Ending balance as of September 30, 2012	$ (1,300,000)	$ (1,300,000)

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Oil and Gas Properties (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
Summary of pro forma results of operations
Operating revenues	$ 12,941,108	$ 6,070,500
Operating loss	(10,599,304)	(29,001,745)
Net loss	$ (19,063,015)	$ (33,489,536)
Pro forma loss per common share:
Basic and diluted	$ (2.08)	$ (12.92)

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Consolidated Statements of Operations (Parenthetical) (USD $)	10 Months Ended	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010
Consolidated Statements Of Operations [Abstract]
Non-cash consideration as part of general and administrative expenses	$ 684,778	$ 6,656,152	$ 13,097,346
Non-cash interest expense	$ 0	$ 4,993,997	$ 3,989,649

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Oil and Gas Properties

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Oil and Gas Properties [Abstract]

OIL AND GAS PROPERTIES

NOTE 3 – OIL AND GAS PROPERTIES

The Company did not complete any major purchases of undeveloped or producing oil and gas properties during the nine and three months ended September 30, 2012.

Effective December 31, 2011, the Company sold 2,838 net acres of undeveloped leases for consideration of approximately $4.5 million.  An initial closing occurred on December 31, 2011, resulting in the Company receiving a cash payment on that date of $3.1 million.  The final closing of this transaction occurred during the three months ended March 31, 2012, at which time the Company received additional net proceeds, after deductions of all closing expenses, of $1.4 million. 

NOTE 3 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS AND DIVESTITURES

DJ Basin Properties Acquisitions – Accounted for as a Business Combination

During the fourth quarter of 2009, the Company pursued a number of acquisition opportunities.  The Company entered into two purchase and sale agreements with Edward Mike Davis, LLC and affiliates (“Davis”) for the purchase of multiple oil and gas properties.  The Company was not successful in fulfilling the requirements under the purchase and sale agreements and forfeited 1,450,000 shares of our common stock with an estimated fair value of $5,075,000.

In January 2010, the Company acquired the Wilke Field from Davis for $4,500,000.   The Company simultaneously entered into a credit agreement with Hexagon to finance 100% of the purchase of the Wilke Field properties.  Hexagon received 1,000,000 shares of the Company's common stock in connection with the financing.  The Company recorded $2.25 million in deferred financing costs related to the shares issued in conjunction with the loan (see Note 7).  

In March 2010, the Company acquired the Albin Field properties from Davis for $6,000,000 and 550,000 shares of common stock with an estimated fair value of $412,500. The Company simultaneously entered into a loan agreement with Hexagon to finance 100% of the cash portion of the purchase price.  The Company recorded approximately $737,822 in deferred financing costs related to 750,000 shares of the Company’s common stock and a one-half percent overriding royalty in the leases and wells in connection with the financing from Hexagon (see Note 7).    

In April 2010, the Company acquired the State Line Field properties from Davis for $15,000,000 and 2,500,000 shares of common stock with an approximate fair value of $1,875,000. The Company simultaneously entered into a loan agreement with Hexagon to finance 100% of the cash portion of the purchase price. The Company recorded approximately $2,780,775 in deferred financing costs related to 3,250,000 shares of the Company’s common stock, 2,000,000 warrants to acquire the Company’s common stock at $2.50 per share and a one percent overriding royalty interest in connection with the financing from Hexagon (see Note 7).

All three of the acquisitions above were recorded at their fair values as of the acquisition date. The following table summarizes the fair values of assets acquired and liabilities assumed for each acquisition as of the related acquisition date:

	Wilke Field			Albin Field			State Line Field
Consideration given:
Cash payment funded by debt	$	4,500,000		$	6,000,000		$	15,000,000
Stock		-			412,500			1,875,000
Total consideration attributable to allocation	$	4,500,000		$	6,412,500		$	16,875,000
Allocation of purchase price:
Proved oil and gas properties	$	4,418,267		$	4,675,099		$	15,529,268
Unproved oil and gas properties		83,200			1,791,619			1,070,975
Total fair value of oil and gas properties acquired		4,501,467			6,466,718			16,600,243
Oil and gas revenue receivable		195,594			-			-
Total assets		4,697,061			6,466,718			16,600,243
Accounts payable		-			-			(52,147	)
Asset retirement obligation		(197,061	)		(54,218	)		(149,151	)
Total liabilities acquired		(197,061	)		(54,218	)		(201,298	)
Net assets acquired	$	4,500,000		$	6,412,500		$	16,398,945
Supplemental information:
Value attributable to ORRI paid to lender	$	-		$	(175,322	)	$	(158,685	)
Value attributable to ORRI awarded to management	$	(125,220	)	$	(701,290	)	$	(317,370	)

The following unaudited supplemental pro forma information presents the results of operations for the years ended December 31, 2010 and 2009, as if the Wilke, Albin, and State Line acquisitions had occurred as of the earliest period presented, January 1, 2009. These unaudited pro forma results of operations are based on the historical financial statements and related notes of the Company, and the related historical audited statements of revenue and direct expenses for the Wilke, Albin and State Line acquisitions included in the related filings on Form 8-K. These pro forma results of operations contain adjustments to depreciation, depletion and amortization for the effects of purchase price allocation, and to interest expense and amortization of deferred financing costs related to financing the acquisitions. The pro forma results are presented for informational purposes only and are not necessarily indicative of what actually would have occurred if the acquisitions had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	For the Year Ended December 31,
	2010			2009
	(Unaudited)			(Unaudited)
Operating revenues	$	12,941,108		$	6,070,500
Operating loss	$	(10,599,304	)	$	(29,001,745	)
Net loss	$	(19,063,015	)	$	(33,489,536	)
Pro forma loss per common share:
Basic and diluted	$	(2.08	)	$	(12.92	)

Also in May 2010, the Company acquired additional undeveloped leasehold acreage and certain overriding royalty interests on existing Company owned acreage and wells in the DJ Basin from Davis for 2,000,000 shares of common stock valued at $1,500,000 and a cash payment of $20 million.

In August 2010, the Company farmed into approximately 240 net acres in exchange for carrying Davis, the lease owner, for a 26% working interest in one well, which has been drilled. The Company also farmed into approximately 533 net acres in the state of Nebraska in exchange for carrying Davis, the lease owner, for a 33% working interest in one well which has been drilled.

In November 2010, the Company purchased certain oil and gas interests of approximately 33,800 net acres located in Laramie County and Goshen County, Wyoming, and Banner County, Kimball County, and Scotts Bluff County, Nebraska from Davis. Additionally, the Company acquired rights below the base of the Greenhorn on approximately 23,000 net acres in Laramie County and Goshen County, Wyoming, and Banner County and Kimball County, Nebraska.  The Company issued 6,666,667 shares of our common stock to acquire the property with an estimated fair value of approximately $12,000,000.

In December 2010, the Company entered into an acquisition and development agreement with TRW Exploration, LLC (a related party, see note 9) whereby TRW paid $2,000,000 for the purchases of an interest in approximately 2,000 net undeveloped acres and also agreed to carry the Company’s 40% interest in two horizontal wells to be drilled on lands defined by the agreement. TRW subsequently funded the drilling and completion costs of two horizontal wells on the lands covered by the leases, at a total cost of approximately $7 million. This agreement was terminated in December, 2011 and TRW sold back its interest in the wells along with all of its rights to the undeveloped acreage, in consideration for the issuance by the Company of 1,500,000 shares of unregistered common stock valued at $4,875,000. Additional amounts were incurred in drilling the wells and were paid by the Company. The Company allocated $2 million of this purchase price to the undeveloped leases, and the remainder to the purchase of the two wells.

The two wells are in progress and currently being evaluated as to their potential to establish commercial production of oil and gas. These wells are carried as wells in progress as of December 31, 2011 at a total cost of $6.4 million.

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 shares of common stock valued at $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.

DJ Basin Properties Divestitures

Effective December 31, 2011 the Company sold 2,838 net acres of undeveloped leases for consideration of approximately $4.5 million.  A gain of $1.8 million related to the sale of this acreage was applied as a credit to the carrying costs of evaluated oil and gas properties.

Depreciation, depletion and amortization (“DD&A”) expenses related to the proved properties were  approximately $4,274,215 and $5,036,000 for the years ended December 31, 2011 and December 31, 2010, respectively. During the year ended December 31, 2011, the company impaired the carrying costs of its evaluated oil and gas properties by $2.8 million as a result of an excess of carrying costs above the applicable ceiling threshold. Prior to January 1, 2010, the Company did not own any oil and gas properties therefore we did not incur DD&A expense in 2009.

The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized as of December 31, 2011:

	As of  December 31, 2011
Leasehold acquisitions
2010		$	33,605,594
2011			12,091,887
Unevaluated properties			45,697,481
Wells in progress exploration  2011			6,425,509
Total		$	52,122,990

The Company plans to evaluate exploration costs (wells-in progress) in 2012 and will likely develop, sell or reclassify to evaluated properties its inventory of unevaluated leasehold over the next three years.   Included in its inventory of unevaluated leases are certain undeveloped leases with an approximate carrying value of $11 million that are being held and extended by the conducting of continuous operations on the two wells in progress. If commercial production is not eventually established in one or both of the two wells in progress, some or all of these leases may expire, and require such cases to be reclassified to evaluated property and subject to the Company’s full cost lid calculation.

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Shareholders' Equity (Details) (Warrant [Member], USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Dec. 31, 2010
Warrant [Member]
Summary of warrant activity
Warrants, Outstanding Beginning	5,638,900	5,764,233	187,500
Granted	600,000	250,000	6,430,233
Exercised, forfeited, or expired		(375,333)	(853,500)
Warrants, Outstanding Ending	6,238,900	5,638,900	5,764,233
Weighted Average Exercise Price, Outstanding Beginning	$ 7.04	$ 7.04	$ 14.00
Weighted Average Exercise Price, Granted	$ 5.00	$ 6.00	$ 6.68
Weighted Average Exercise Price, Exercised, forfeited, or expired		$ 6.16	$ 6.00
Weighted Average Exercise Price, Outstanding Ending	$ 6.84	$ 7.04	$ 7.04

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Quarterly Results (Unaudited) (Details) (USD $)	3 Months Ended									9 Months Ended		10 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010
Summary of quartly results
Revenues		$ 1,944,454	$ 2,630,933	$ 2,811,429	$ 1,273,675	$ 1,519,702	$ 2,552,790	$ 5,194,849	$ 490,351
Income (loss) from operations	(1,287,036)	(6,297,854)	(939,330)	(4,069,541)	(2,052,133)	(4,191,728)	(5,900,630)	(792,880)	(2,242,252)	(7,156,008)	(7,061,004)	(29,911,412)	(11,704,044)	(13,127,490)
Net earnings (loss)		$ (7,295,537)	$ (3,027,618)	$ (4,762,881)	$ (3,743,187)	$ (6,230,293)	$ (7,491,246)	$ (3,196,779)	$ (2,820,715)
Earnings per common share
Basic and diluted		$ (0.47)	$ (0.19)	$ (0.30)	$ (0.25)	$ (1.47)	$ (2.53)	$ (1.99)	$ (1.04)
Basic and diluted	17,833,466	15,543,758	15,775,135	15,635,346	14,778,206	9,167,803	2,962,882	6,362,922	2,927,759	17,732,304	15,388,772	2,453,921	15,543,758	9,167,803

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Loan Agreements (Tables)

9 Months Ended

12 Months Ended

Sep. 30, 2012

Dec. 31, 2011

Loan Agreements [Abstract]

Summary of convertible debt

	As of				As of
		September 30,  2012				December 31, 2011
Convertible debentures		$	13,400,000			$	8,400,000
Debt discount			(3,804,947	)			(3,470,932	)
Total convertible debentures, net		$	9,595,053			$	4,929,068

	As of  December 31, 2011
Convertible debt		8,400,000
Debt discount		(3,470,932	)
Total convertible debt, net		4,929,068

Summary of annual debt maturities

Year 1	$	873,142
Year 2		32,819,197
Thereafter		-
Total	$	33,692,339

2012	1,150,966
2013	20,129,670
2014	8,400,000
Thereafter	--
Total	29,680,636

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Summary of Significant Accounting Policies (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of the value of asset retirement obligation
Beginning Balance	$ 507,280
Liabilities incurred	61,469	478,208
Accretion expense	44,125	28,042
Change in estimate		1,030
Balance	$ 612,874	$ 507,280

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

INCOME TAXES

NOTE 10 - INCOME TAXES

The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2011 and 2010 were:

	2011			2010
Deferred tax assets:
Oil and gas properties and equipment	$	(515,123	)	$	(1,335,490	)
Net operating loss carry-forward		11,291,513			7,285,426
Share based compensation		4,675,241			3,902,007
Abandonment obligation		205,145			188,728
Derivative instruments		176,514			148,384
Other		(91,304	)		(30,896	)
Total deferred tax asset		15,741,986			10,158,159
Valuation allowance		(15,741,986	)		(10,158,159	)
Net deferred tax asset	$	-		$	-

Reconciliation of the Company’s effective tax rate to the expected federal tax rate is:

	2011			2009
Effective federal tax rate		35.00	%		35.00	%
Effect of permanent differences		-7.54	%		-21.78	%
State tax rate		2.20	%		2.20	%
Change in rate		0.00	%		-0.23	%
Other		0.00	%		3.07	%
Valuation allowance		-29.66	%		-18.26	%
Net		0	%		0	%

At December 31, 2011 and 2010, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $25,957,000 and $19,582,000, respectively,that may be offset against future taxable income. The Company has established a valuation allowance for the full amount of the deferred tax assets as management does not currently believe that it is more likely than not that these assets will be recovered in the foreseeable future. To the extent not utilized, the net operating loss carry-forwards as of December 31, 2011 will expire in 2031.