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EX-5.1 - LEGAL OPINION - LILIS ENERGY, INC.fs1a2ex5i_recoveryenergy.htm
EX-23.2 - ACCOUNTANTS CONSENT - LILIS ENERGY, INC.fs1a2ex23ii_recoveryenergy.htm
EX-23.3 - CONSENT OF RE DAVIS. - LILIS ENERGY, INC.fs1a2ex23iii_recoveryenergy.htm


 
As filed with the Securities and Exchange Commission on June 2 , 2011
Registration No. 333-169070
 
United States
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
______________________
 
AMENDMENT NO. 2
TO
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.)
 
Roger Parker
Chief Executive Officer
Recovery Energy, Inc.
1515 Wynkoop St., Suite 200
Denver, CO 80202
(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:
Jeffrey M. Knetsch
Brownstein Hyatt Farber Schreck, LLP
410 Seventeenth Street, Suite 2200
Denver, Colorado 80202
(303) 223-1100
Fax: (303) 223-1111
 
______________________

 
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 (1)
   
Proposed maximum offering price per share (2)
   
Proposed maximum aggregate offering price (2)
   
Amount of
registration fee (2)
 
                         
Common Stock(1)
   
21,465,335
   
$
2.72
   
$
58,278,384.53
   
$
6,766.12 (3)
 
Common Stock
   
6,857,634
    $
2.80
    $
19,201,375.20
    $
2,229.28
 

 
(1)
Represents (i) an aggregate of 23,890,629 shares of common stock being registered for resale on behalf of the selling stockholder s of such securities (ii) an aggregate of 4,432,340 shares of common stock being registered for issuance to holders of the Registrant's outstanding 8% senior secured debentures in payment of interest on such debentures and upon conversion of such debentures and (iii) 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 the shares of the selling stockholder.
(2)
Estimated solely for the purpose of determining the registration fee pursuant to Rule 457 promulgated under the Securities Act of 1933, as amended.
(3)
$6,766.12 previously paid.
 
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 without notice. The selling stockholders 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 Recovery Energy, Inc. and the selling stockholders are not soliciting offers to buy these securities, in any state where the offer or sale of these securities is not permitted.
 
Pursuant to Rule 429 under the Securities Act of 1933 the prospectus contained in this Registration Statement also relates to the securities registered in the Registrant's registration statement on Form S-1 (File No. 333-164291).
 
 
Subject to completion, dated
June 2 , 2011

 
53,645,969  shares of Common Stock

 
RECOVERY ENERGY, INC.
 
This prospectus relates to 49,213,629 shares of common stock of Recovery Energy, Inc. which may be offered by the selling stockholders identified on page 38 of this prospectus for their own account and 4,432,340 shares which may be offered by us to the holders of our $8,400,000 aggregate principal amount of 8% senior secured debentures. 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 shareholders 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 OTC Bulletin Board under the symbol “RECV.OB”. On June 1, 2011, the last reported sale price of our common stock was $2.85 per share.
 
Investing in our common stock involves a high degree of risk. Please carefully consider the “Risk Factors” beginning on page 4 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 _________, 2011.
 
 
 
TABLE OF CONTENTS

 

 
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.
 
 
 
1

 
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 facts, included in this prospectus that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth herein, including the following:
 
 
 
Our ability to maintain adequate liquidity in connection with low oil and natural gas prices;
       
 
 
The changing political environment in which we operate;
       
 
 
Our ability to obtain, or a decline in, oil or natural gas production;
       
 
 
A decline in oil or natural gas prices;
       
 
 
Our ability to increase our oil and natural gas reserves;
       
 
 
Incorrect estimates of required capital expenditures;
       
 
 
The amount and timing of capital deployment in new investment opportunities;
       
 
 
The volumes of production from our oil and natural gas development properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment;
       
 
 
Our future capital requirements and availability of capital resources to fund capital expenditures;
       
 
 
Our ability to successfully integrate and profitably operate any future acquisitions;
       
 
 
Increases in the cost of drilling, completion and natural gas collection or other costs of production and operations;
       
 
 
The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;
       
 
 
Numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and actual future production rates and associated costs;
       
 
 
Our ability to remedy any deficiencies that may be identified in the review of our internal controls;
       
 
 
The credit worthiness of third-parties which we enter into business agreements with;
       
 
 
General economic conditions, tax rates or policies, interest rates and inflation rates;
       
 
 
Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;
       
 
 
Weather, climate change and other natural phenomena;
       
 
 
Industry and market changes, including the impact of consolidations and changes in competition;
       
 
 
The effect of accounting policies issued periodically by accounting standard-setting bodies;
       
 
 
The actions of third party co-owners of interests in properties in which we also own an interest;
       
 
 
The cost and effects on our business, including insurance, resulting from terrorist actions or natural disasters and responses to such actions or events;
       
 
 
The volatility of our stock price; and
       
 
 
The outcome of any future litigation or similar disputes and the impact on any such outcome or related settlements.
 
 
SUMMARY
 
Overview of Our Business
 
Recovery Energy, Inc. (OTC BB: RECV), sometimes referred to in this prospectus as “we,” “us,” “our”, or “Recovery Energy,” is a Denver based independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the DJ Basin. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team along with that of our operating partners.
 
We target low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Colorado, Nebraska, and Wyoming. Since January 1, 2010 we have acquired 19 working wells. We currently own interests in approximately 156,500 gross (134,500 net) leasehold acres, of which 153,500 gross (132,500 net) acres are classified as undeveloped acreage.
 
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 1515 Wynkoop St., Suite 200, Denver, CO 80202. Our telephone number is 1-888-887-4449. Our website is www.recoveryenergyco.com. The information on our websites 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:
 
4,432,340 shares offered by us to be issued upon conversion of our 8% senior secured debentures and as interest on such debentures
12,692,000 shares underlying warrants held by investors in private placements
1,148,486 shares held by investors in private placements
13,658,961 shares issued by us to the sellers of oil and gas properties we have purchased
6,500,000 shares and 4,000,000 shares underlying warrants issued to our lender and its affiliates
7,243,187 shares held by our directors, officers and other employees
90,000 shares issued to our landlord pursuant to the lease of our executive offices
30,995 shares issued by us as compensation to our financial advisor
2,100,000 shares held by a former officer and director
750,000 shares issued by us as compensation to our management consultant
1,000,000 shares underlying warrants issued by us to our management consultant
 
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.
 
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. As of March 31, 2011, we had a cumulative deficit of approximately $50 million. While we have developed some of our properties, 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. We cannot assure you that we will successfully implement our business plan or that we will achieve commercial profitability in the future. 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 annual report.
  
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  or cash generated from oil and gas operations.
 
 
Currently, the majority of our revenue after field level operating expenses is required to be paid to our lender as debt service. As of March 31, 2011, we had working capital of $2,297,607, including $4,110,161 of cash and cash equivalents of which $1,998,821 is restricted cash. We will seek to obtain additional capital through the sale of our 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 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. Accordingly, there is little operating history upon which to judge our business strategy, our management team or our current operations.
 
We have a history of losses and cannot assure you that we will be profitable in the foreseeable future. At March 31, 2011, we have incurred a net loss from inception of approximately $50 million. If we fail to generate profits from our operations, we may not be able to sustain our business. We may never report profitable operations or generate sufficient revenue to maintain our company as a going concern.
 
We have limited management and staff and will be dependent upon partnering arrangements. We have eight employees. We intend to use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We will 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.
 
The loss of our chief executive officer could adversely affect us, and the recent resignation of our president and chief financial officer could adversely affect us. We are dependent on the extensive experience of our chief executive officer to implement our acquisition and growth strategy. The loss of the services of this individual could have a negative impact on our operations and our ability to implement our strategy. We are in the process of hiring a new chief financial officer, and the transition to a new chief financial officer could have a negative impact on our operations and our ability to implement our strategy.
 
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.
 
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.
 
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 could 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.
 
 
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 annual report contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves. The December 31, 2010, reserve estimate was prepared by our Senior Reserve Engineer 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 annual report 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 leaseholder oil and natural gas reserves. If we choose to pursue an acquisition, we will perform a review of the target properties that we believe is consistent with industry practices. 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.
 
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, 2010, approximately 56% 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.

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.
 
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. If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties, negatively impacting the trading value of our securities. There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. We follow the full cost method of accounting for oil and gas operations whereby all costs related to exploration and development of oil and gas properties are initially capitalized into a single cost center , known as a full cost pool. We record all capitalized costs into a single cost center as all operations are conducted within the United States. Such costs include land acquisition costs, geological and geophysical expenses , carry charges on non-producing properties, and costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.
 
Additional write downs could occur if oil and gas prices decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results.
 
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, 2010, and our 2010 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.
 
Part of our strategy involves drilling in existing or emerging 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.   Operations in the Niobrara shale 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 unevaluated 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.
 
Our credit agreements mature on September 1, 2012, and our lender can foreclose on several of our properties if we do not pay off or refinance our approximately $20 million of loans. A significant portion of our oil and gas 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.
 
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 39,196,666 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).
 
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 that we believe to be generally consistent with industry practices. 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.
 
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 have declined significantly since mid 2008, and lower prices will negatively affect our financial condition, planned capital expenditures and results of operations. 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.
 
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 slow down 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 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.
 
 
 
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 “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;
 
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.
 
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—Government Regulations” for a more detailed description of our environmental risks.
 
 
 
Risks Relating to our Common Stock
 
There is no active public market for our shares and we cannot assure you that all active trading market or a specific share price will be established or maintained.
 
Our common stock trades on the OTC BB trading system. The OTC BB tends to be highly illiquid, in part because there is no national quotation system by which potential investors can track the market price of shares except through information received or generated by a limited number of broker-dealers that make markets in particular stocks. There is a greater chance of market volatility for securities that trade on the OTC BB as opposed to a national exchange or quotation system. This volatility may be caused by a variety of factors including:
 
 
the lack of readily available price quotations;
 
the absence of consistent administrative supervision of “bid” and “ask” quotations;
 
lower trading volume; and
 
market conditions.
 
In addition, 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;
 
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 securities and may prevent you from obtaining a market price equal to your purchase price when you attempt to sell our securities in the open market. In these situations, you may be required either to sell our securities at a market price which is lower than your purchase price, or to hold our securities 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.
 
 
 
MARKET FOR OUR COMMON STOCK

 
On September 25, 2009 our common stock began trading on the OTC MARKET UNDER THE SYMBOL “RECV.OB.”
 
The following table shows the high and low reported sales prices of our common stock for the periods indicated. Because our stock trades infrequently, we do not believe that these prices are an accurate reflection of the value of our stock.
 
 
 
High
   
Low
 
2011
           
April 1 , 2011 through  June 1 , 2011
 
$
3.25
   
$
2.50
 
First Quarter
  $
4.00
    $
1.95
 
2010
           
Fourth Quarter
 
$
2.50
   
$
1.81
 
Third Quarter
 
$
2.50
   
$
1.50
 
Second Quarter
 
$
4.00
   
$
0.25
 
First Quarter
 
$
5.50
   
$
2.05
 
2009
           
Fourth Quarter
 
$
5.75
   
$
3.00
 
September 25, 2009 through September 30, 2009
 
$
6.00
   
$
4.25
 
 
On May 9, 2010, there were approximately 115 owners of record of our common stock.
 
We have not paid any cash dividends since our inception and do not contemplate paying dividends in the foreseeable future. It is anticipated that earnings, if any, will be retained for the operation of our business.
 
USE OF PROCEEDS
 
We will not receive any proceeds from the sale or issuance of the shares of common stock offered by this prospectus.
 
 
UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS
 
In January 2010, Recovery acquired the Wilke Field oil and gas properties for approximately $4,500,000 from Edward Mike Davis, L.L.C. In March, Recovery acquired the Albin Field oil and gas properties for approximately $6,000,000 and 550,000 shares of our common stock, valued at $412,500, from Davis. In April 2010, Recovery acquired the State Line Field oil and gas properties for approximately $15,000,000 and 2,500,000 shares of our common stock, valued at $1,875,000, from Davis.
 
In connection with the acquisitions described above, Recovery simultaneously entered into three credit agreements with Hexagon Investments, LLC to finance the cash portions of the purchase prices. The agreements require substantially all of the net revenue less operations costs from the acquired properties to be applied to principal and interest and contain customary terms such as representations and warranties and indemnification. The agreements bear annual interest of 15%, mature on December 1, 2011, and are secured by mortgages on the respective properties. We issued Hexagon 1,000,000 shares of our common stock, valued at $2,250,000, in connection with the Wilke Field financing, 750,000 shares of our common stock, valued at $562,500, in connection with the Albin Field financing, and 3,250,000 shares of our common stock and a warrant to purchase 2,000,000 shares of our common stock at $2.50 per share, valued at $2,437,500 and $184,589, respectively, in connection with the State Line Field financing.
 
The following unaudited pro forma condensed financial statements and related notes give effect to the acquisitions by Recovery of the Wilke Field properties, the Albin Field properties, and the State Line Field properties for the year s ended December 31, 2009 and 2010, as if the acquisitions had occurred on January 1, 2009. A pro forma balance sheet has not been presented as the acquisitions were reflected in the December 31, 2010 balance sheet of Recovery contained in the financial statements in this prospectus.
 
The unaudited pro forma condensed statement of operations for the year ended December 31, 2009 is based on the audited statement of operations of Recovery for the period from our inception (March 6, 2009) through December 31, 2009, the audited statement of operations of the Wilke Field properties for the year ended December 31, 2009, and the audited statement of revenues and direct operating expenses of the Albin Field properties for the year ended December 31, 2009. The State Line Field properties did not commence operations until 2010, and as a result, have not been included.
 
The unaudited pro forma condensed statement of operations for the year ended December 31, 2010 is based on the audited statement of operations of Recovery for the year ended December 31, 2010, the unaudited statement of revenues and direct operating expenses of the Albin Field properties for the three months ended March 31, 2010, and the audited statement of revenues and direct operating expenses for the three months ended March 31, 2010. The Wilke Field properties were excluded as they were acquired in January 2010 and their operations are included in Recovery’s statement of operations for substantially the full period.
 
Pro forma data is based on assumptions and include adjustments as explained in the notes to the unaudited pro forma condensed combined financial statements. As adjustments are based on currently available information, actual adjustments may differ from the pro forma adjustments; therefore, the pro forma data is not necessarily indicative of the financial results that would have been attained had the acquisitions occurred on the date referenced above, and should not be viewed as indicative of operations in future periods. The unaudited pro forma condensed financial statements should be read in conjunction with the notes thereto, Recovery’s financial statements as of and for the period ended December 31, 2009, and as of and for the year ended December 31, 2010, the Wilke Field Acquisition Properties and the Albin Field Acquisition Properties statements of revenues and direct operating expenses for the years ended December 31, 2008 and 2009 and the three months ended March 31, 2010 and 2009, and the State Line Field Acquisition Properties statement of revenues and direct operating expenses for the three months ended March 31, 2010, all included herein.
 

 
UNAUDITED PRO FORMA CONDENSED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2009
 
   
RECOVERY ENERGY, INC. PERIOD ENDED DECEMBER 31, 2009
   
WILKE FIELD PROPERTIES YEAR ENDED DECEMBER 31, 2009
   
ALBIN FIELD PROPERTIES YEAR ENDED DECEMBER 31, 2009
   
PRO FORMA ADJUSTMENTS (SEE NOTE 2)
   
PRO FORMA COMBINED
 
REVENUES
                             
Oil and gas sales
 
$
-
   
$
4,671,274
   
$
1,399,226
   
$
-
   
$
6,070,500
 
     
-
     
4,671,274
     
1,399,226
     
-
     
6,070,500
 
                                         
EXPENSES
                                       
Production costs
   
-
     
453,176
     
104,343
     
-
     
557,519
 
Production taxes
   
-
     
267,818
     
79,756
     
-
     
347,574
 
Depreciation, depletion, and amortization
   
-
     
2,705,953
     
-
     
723,277
(a,b)
   
3,429,230
 
Impairment of equipment
   
2,750,000
     
-
     
-
     
-
     
2,750,000
 
General and administrative
   
1,057,306
     
251,000
     
-
     
600,510
(c,h)
   
1,908,816
 
Fair value of common stock and warrants issued in attempted property acquisitions
   
8,404,106
     
-
     
-
     
-
     
8,404,106
 
Reorganization and merger costs
   
17,700,000
     
-
     
-
     
-
     
17,700,000
 
     
29,911,412
     
3,677,947
     
184,099
     
1,323,787
     
35,097,245
 
                                         
Income (loss) from operations
   
(29,911,412
)
   
993,327
     
1,215,127
     
(1,323,787)
     
(29,026,745
)
                                         
Unrealized gain on lock-up
   
-
     
-
     
-
     
-
     
-
 
Interest income (expense)
   
31
     
-
     
-
     
(4,487,822)
(d,e)
   
(4,487,791
)
                                         
Net income (loss)
 
$
(29,911,381
)
   
993,327
     
1,215,127
   
$
(5,811,609)
   
$
(33,514,536
)
                                         
Basic net income (loss) per share
 
$
(3.05
)
                         
$
(2.77
)
Diluted net income (loss) per share
 
$
(3.05
)
                         
$
(2.77
)
                                         
Weighted average number of shares of common stock outstanding (basic and diluted)
   
9,815,683
                     
2,300,000
(f)
   
12,115,683
 
 
 
 
UNAUDITED PRO FORMA CONDENSED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2010
 
   
RECOVERY ENERGY, INC. YEAR ENDED DECEMBER 31, 2010
   
ALBIN FIELD PROPERTIES THREE MONTHS ENDED MARCH 31, 2010
   
STATE LINE FIELD PROPERTIES THREE MONTHS ENDED MARCH 31, 2010
   
PRO FORMA ADJUSTMENTS (SEE NOTE 2)
   
PRO FORMA COMBINED
 
REVENUES
                             
Oil and gas sales
  $ 9,572,812     $ 740,501     $ 2,442,915     $ -     $ 12,756,228  
Operating fees
    13,487       -       -       -       13,487  
Realized gain on hedges
    570,233       -       -       -       570,233  
Price risk management activities
    (398,840 )     -       -       -       (398,840 )
      9,757,692       740,501       2,442,915       -       12,941,108  
                                         
EXPENSES
                                       
Production costs
    862,042       104,605       166,408       -       1,133,055  
Production taxes
    1,056,244       42,209       342,008       -       1,440,461  
General and administrative
    12,576,798       -       -       (826,510)
(g)
    11,750,288  
Depreciation, depletion, and amortization
    5,036,648       -       -       2,551,120 (a,b)     7,587,768  
Bad debt expense
    400,000       -       -       -       400,000  
      19,931,732       146,814       508,416       1,724,610       22,311,572  
                                         
Income (loss) from operations
    (10,174,040 )     593,687       1,934,499       (1,724,610)       (9,370,464 )
                                         
Unrealized gain on lock-up
    28,666       -       -       -       28,666  
Interest income (expense)
    (6,640,209 )     -       -       (1,852,168) (d,e)     (8,492,377 )
                                         
Net income (loss)
  $ (16,785,583 )   $ 593,687     $ 1,934,499     $ (3,576,778)     $ (17,834,175 )
                                         
                                         
Basic net income (loss) per share
  $ (0.46 )                           $ (0.45 )
Diluted net income (loss) per share
  $ (0.46 )                           $ (0.45 )
                                         
Weighted average number of shares of common stock outstanding (basic and diluted)     36,671,213                       3,050,000
(f)
    39,721,213  
 
 
NOTES TO THE UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS
 
1. Adjustments to Pro Forma Statement of Operations:
 
The unaudited pro forma statements of operations gives effect to the following pro forma adjustments necessary to reflect the acquisitions and additional debt and equity associated with the acquisitions:
 
a.
Reverse historical Wilke Field depreciation, depletion, and amortization expense of $2,690,188 for the year ended December 31, 2009, and record incremental pro forma depreciation, depletion, and amortization expense based on the new cost basis of $3,409,128 for the year ended December 31, 2009 and $2,546,966 for the three months ended March 31, 2010, recorded in accordance with the full cost method of accounting for oil and gas activities based on the purchase price allocation to depreciable and depletable assets.
 
b.
Reverse historical Wilke Field accretion expense of $15,765 for the year ended December 31, 2009, and record pro forma accretion expense of $20,102 for the year ended December 31, 2009 and $4,154 for the three months ended March 31, 2010, on the asset retirement obligation in accordance with ASC 410.20.
 
c.
Record expense associated with the overriding royalty interests of $826,510 for the year ended December 31, 2009 , awarded to two members of management. This expense was a one-time charge to recognize the assignment of the overriding royalty interests and was comprised of $125,220 in connection with the Wilke Field acquisition and $701,290 in connection with the Albin Field acquisition. See Note g.
 
d.
Record interest expense of $1.5 million for the year ended December 31, 2009 and $768,750 for the three months ended March 31, 2010, on the credit agreements incurred in conjunction with the acquisitions at an annual interest rate of 15%, using a weighted average balance outstanding. A one tenth of one percent change in interest rate would have an approximately $24,500 annual impact on the interest expense.
 
e.
Record amortization expense of $2,987,822 for the year ended December 31, 2009 and $1,083,418 for the three months ended March 31, 2010, for the deferred financing costs associated with the new credit agreements.
 
f.
Represents the weighted average shares outstanding on the 1,000,000 shares issued in connection with the Wilke Field financing, the 550,000 shares issued as part of the Albin Field acquisition price and the 750,000 shares issued in connection with the Albin Field financing assuming they were issued on January 1, 2009; and the 2,500,000 shares issued as part of the State Line Field acquisition price and the 3,250,000 shares issued in connection with the State Line Field financing assuming they were issued on January 1, 2010, as State Line had no operations during 2009.
 
g.
Reverse $826,510 of expense associated with the overriding royalty interest awarded to two members of management . This expense was a one-time charge and is comprised of $125,220 in connection with the Wilke Field acquisition and $701,290 in connection with the Albin Field acquisition. This amount is included in the Recovery Energy Statement of Operations for the year ended December 31, 2010. As the pro forma statements of operations assume that the acquisitions occurred on January 1, 2010, this amount has been included as a pro forma adjustment to the Pro Forma Statement of Operations for the year ended December 31, 2009. As the amount was included in the 2009 results and the Recovery Energy 2010 results, it was reversed out of the 2010 Pro Forma Statement of Operations for the year ended December 31, 2010, in order to avoid the amount being double expensed.
   
h.
Reverse historical Wilke Field general and administrative expenses of $226,000 for the year ended December 31, 2009, related to Wilke Field employees and office space which will not be retained by Recovery.
 
For the Pro Forma Year Ended December 31, 2009
 
For the year ended December 31, 2009, total production was 125,190 net barrels of oil for total oil sale revenue of $6,070,500, for an average price per barrel of $48.49. Average daily production for the year ended December 31, 2009 was 343 BOPD. Production costs were $557,519, or $4.45 per barrel and production taxes were $347,574, or $2.78 per barrel. Depreciation, depletion and amortization expense for the year ended December 31, 2009 was $3,429,230, or $27.39 per barrel, and was comprised of $3,409,128 of depletion expense on the oil and gas properties and $20,102 of accretion expense on the asset retirement obligation. Total operating costs per barrel were $34.62, for a gross margin per barrel of $13.87, or 28.6%
 
Interest expense for the year ended December 31, 2009 was $4,487,822, and was comprised of cash interest expense of $1.5 million and amortization of deferred financing costs of $2,987,822.
 
For the Pro Forma Year Ended December 31, 2010
For the year ended December 31, 2010, total production was 179,384 net barrels of oil equivalent for total oil and gas sales revenue of $12,756,228, for an average price per barrel of $71.11. Average daily production for the year ended December 31, 2010 was 491 BOPD. Production costs were $1,133,055, or $6.32 per barrel and production taxes were $1,440,461, or $8.03 per barrel. Depletion, depreciation and amortization expense for the year ended December 31, 2010 was $7,587,768, or $42.30 per barrel, and was comprised of $7,555,572 of depletion expense on the oil and gas properties and $32,196 of accretion expense on the asset retirement obligation. Total operating costs per barrel were $56.65, for a gross margin of $14.46, or 20.3%.
 
Interest expense for the year ended December 31, 2010 was $8,492,377, and was comprised of cash interest expense of $3,423,881 and amortization of deferred financing costs of $5,073,067, net of $4,571 in interest income.
 
 
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.
 
Overview
 
Recovery Energy Inc. is a Denver based independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the DJ Basin. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team along with that of our operating partners.
 
We have developed and acquired an  oil and natural gas base of proved reserves, as well as a portfolio of development drilling and exploratory drilling opportunities of high-impact conventional and non-conventional prospects with an emphasis on multiple producing horizons and the Niobrara shale resource play. We believe these prospects offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Colorado, Nebraska, and Wyoming. Since January 1, 2010 we have acquired or developed 20 producing wells. We currently own interests in approximately 156,500 gross (134,500 net) leasehold acres, of which 153,500 gross (132,500 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska in the DJ Basin. We intend to continue to evaluate and invest in acquisitions and internally generated prospects. It is our long-term goal to maximize our DJ Basin acreage position through development drilling of our conventional horizons as well as development of our Niobrara shale potential.
 
Our Oil and Gas Operations
 
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.  
 
 
Principal Oil and Gas Interests
 
Currently we own 20  producing wells, 1 shut-in well, 1 injection well, and 3 wells in progress, as well as approximately 156,500 gross (134,500 net) acres, of which 153,500 gross (134,500 net) acres are classified as undeveloped acreage, all of which is located in Colorado, Wyoming and Nebraska in the DJ Basin. 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 Codell, Greenhorn and Pierre Shale. Our current production and our recent drilling efforts have focused on the conventional Dakota and Muddy ‘J’ target horizons, and the unconventional Niobrara shale play. As of March 31, 2011 we had 3 gross (2.4 net) wells in progress.

As of December 31, 2010 we had net proved reserves of 744 Mboe. We produced 136 Mboe for the year ended December 31, 2010, and 25 Mboe for the quarter ended March 31, 2011.
  
Results of Operations
 
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. We intend to continue to 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.
 
For the Three Months Ended March 31, 2011 compared to the Three Months Ended March 31, 2010

The Company reported a net loss for the three months ended March 31, 2011 of approximately $3,743,000 compared to a net loss of approximately $2,821,000 for the same period in 2010. Oil and gas revenues increased from approximately $623,000 in the first quarter of 2010 to approximately $1,911,000 in the first quarter of 2011. Our production volume on a BOE basis increased 285% from 8,897 BOE during the first quarter of 2010 to 25,328 BOE during the first quarter of 2011. This increase is primarily attributable to the Palm and State Line acquisitions that the Company completed subsequent to March 31, 2010. In addition, we realized increased prices during the first quarter of 2011 versus the first quarter of 2010. Oil price realization increased by 24% to $86.49 per barrel for the first quarter of 2011, compared to $69.98 per barrel for the same period in 2010. This increase in price realization during the first quarter of 2011 was partially offset by a realized loss on hedges of approximately $167,000 and a non-cash charge of approximately $478,000 for the change in value of commodity derivatives that we use to mitigate our exposure to oil price volatility.  There was no realized gain or loss for such risk management activities during the first quarter of 2010, but the Company did experience a non-cash charge of approximately $133,000 for the change in value of commodity derivatives during the same period.
 
Oil and Gas Revenue and Production

During the three months ended March 31, 2011, as compared to the same period in 2010, oil production volumes increased from 8,897 barrels of oil to 20,833 barrels of oil, or 134%, primarily due to the Palm and State Line acquisitions which the Company completed subsequent to March 31, 2010. Natural gas production increased from zero during to the three months ended March 31, 2010 to 26,969 Mcf during the same period in 2011. Oil and natural gas revenues increased by approximately $1,288,000, or 207%, compared to the first quarter of 2010, primarily due to the Palm and Sate Line acquisitions and, to a lesser extent, increased realized prices in 2011 compared to 2010. The increase in oil and gas revenue was 89% attributable to the increase in production volumes and 11% attributable to the increase in realized commodity prices.

   
Three Months Ended
 
   
March 31, 2011
 
   
Volume
   
Average Price
 
Product:
           
Oil (Bbls)
   
20,833
   
$
86.49
 
Natural Gas (Mcf)
   
26,969
   
$
4.04
 
 
Average daily net production was 281 BOPD for the quarter ended March 31, 2011.

Price Risk Management Activities
 
We recorded a net loss on our derivative contracts that do not qualify for cash flow hedge accounting of $(477,912) for the three month period ended March 31, 2011, compared to a net loss of $(133,369) for the three month period ended March 31, 2010. These amounts represent an unrealized non-cash loss which represents a change in the fair value of our mark-to-market derivative instruments.  We realized a loss on our derivative contracts that do not qualify for cash flow hedge accounting of $292,805 for the quarter ended March 31, 2011. We did not realize any hedge gain or loss for the three month period ended March 31, 2010. 
 
 
Oil and gas production expenses, depreciation, depletion and amortization
   
Three Months Ended March 31,
   
2011
   
(per BOE)
Average price
 
$
75.44
 
         
Production costs
   
17.65
 
Production taxes
   
7.99
 
Depletion and amortization
   
        42.20
 
       
Total operating costs
   
 67.84
 
       
         
Gross margin
 
$
7.60
 
       
Gross margin percentage
   
10.10
%
 
General and administrative expenses
 
General and administrative expenses were $1,600,594 for the quarter ended March 31, 2011.  Our general and administrative expenses for the quarter included approximately $418,000 in professional fees, and approximately $546,000 in non-cash compensation expense.  

2010 compared to 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.
 
For the Year Ending December 31, 2010

For the three and twelve month periods ended December 31, 2010, we had $2,082,977 and $9,504,737 in oil sale revenues and $56,644 ad $68,075 in natural gas sales, respectively.

 
Quarter Ended
 
 
December 31, 2010
 
 
Volume
 
Average Price
 
Product:
           
Oil (Bbls)
   
26,984
   
$
77.19
 
Natural Gas (Mcf)
   
14,914
   
$
4.56
 
 
Average daily net production for the three and twelve month periods ended December 31, 2010 were 319 BOEPD and 373 BOEPD.

Miscellaneous Income and Operating Fees

The Company earned net operating fees of $8,987 and $13,487 during the three and twelve month periods ended December 31, 2010. The Company realized a mark-to-market gain of $3,389 and $28,666 during the three and twelve month periods 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 $(633,494) and $(398,840) for the three and twelve month periods 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 of $4,598 and $570,233 for the three and twelve month periods 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”.   
 
Oil and Gas Production Expenses, Depreciation, Depletion and Amortization
 
   
For the Year Ended December 31,
 
   
2010
   
2009 (1)
   
2008 (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 $3,635,060 and $12,502,568 for the three and twelve month periods ended December 31, 2010. Our general and administrative expenses for the three and twelve month periods ended December 31, 2010 included $397,136 and $1,464,990 in professional fees (financial advisors, attorneys, accountants, and reserve engineers) of which $135,982 and $372,393 were noncash, and $2,864,873 and $9,958,300 in non-cash compensation expense. We also incurred a non-cash expense of $23,357 and $54,500 in rental expense for our office lease for the three and twelve months ending December 31, 2010. Total non-cash general and administrative expenditures for the three and twelve months ended December 31, 2010 was approximately $143,000 and $10,400,000, respectively. 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 $1,141,038 and $5,036,648 for the three and twelve month periods ended December 31, 2010.

Interest Expense

Total interest expense was $2,041,954 and $6,640,209 for the three and twelve month periods ended December 31, 2010. The interest expense was comprised of $1,237,273 and $3,989,649 in non-cash amortization of expenses for the three and twelve month periods ending 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 $804,751 and $2,655,131 in cash interest expense for the three and twelve month periods ended December 31, 2010. We did not incur interest expense from inception through December 31, 2009.
 
 
We incurred a net loss to common shareholders of $16,785,583 for the year ended December 31, 2010.
  
From inception through December 31, 2009
 
General and administrative expense for the period ended December 31, 2009 totaled $1,057,306, including non-cash expense $684,778 in compensation expense for outstanding restricted common stock grants issued to executive officers and board members.
 
Our expense for impairment of equipment held for sale was $2,750,000 for the period ended December 31, 2009.
 
Non-cash expenses related to the fair value of common stock issued in an attempted property transaction for the period ended December 31, 2009 totaled $5,075,000.   Additional non-cash expenses for the period ended December 31, 2009 included $3,329,106 in fair value for warrants issued to third parties for a commitment to finance a property transaction which did not close, $200,000 related to 85,000 shares issued in conjunction with the merger and $17,500,000 related to 5 million shares acquired by our controlling shareholder group subsequent to the reverse merger.
 
Income for the period ended December 31, 2009 totaled $31 and was comprised of interest income.
 
We incurred a net loss to common shareholders of $29,911,381 for the period ended December 31, 2009.
 
Plan of Operations
 
Our plan of operations is to acquire and develop oil and natural gas prospects, concentrating on those with the lowest development and lifting costs. Consistent with that is our gradual structuring and staffing of our company as we become the operator of an increasing number of acquired properties . By acting as the operator, we have greater control over drilling and developmental decisions and we have a broad spectrum of exploration prospects we can consider for participation. As an operator we should reduce overall finding costs as we start to generate exploration prospects.
 
The acquisition and development of properties and prospects and the pursuit of fresh 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 and to the maximum benefit of our shareholders. 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 increasing 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 interest 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” below, based on our present working capital and current rate of cash flow from operations, we may need to raise additional capital to fund our exploration and development budget through, at least, December 31, 2011. We will seek additional capital through the sale of our securities and we will endeavor to obtain additional capital through bank lines of credit and project financing. However, as described further below, under the terms of our $20 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 the $20 million credit facilities.
 
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.   
 
Financial Condition and Liquidity
 
We are maintaining our previously announced 2011 capital expenditure budget of approximately $20 million, which is allocated to oil and gas activities and acquisitions in the DJ Basin in Wyoming, Nebraska and Colorado targeting the conventional Dakota ‘D’ sand and Muddy ‘J’ sand targets as well as the unconventional Niobrara shale. We have spent approximately $8.5 million for acquisitions during the first quarter of 2011.  In addition to acquisitions, we have spent approximately $2.8 million in drilling capital expenditures on 2 gross (2 net) conventional wells and completion activities on 3 gross (3 net) conventional wells during the first quarter for 2011.  We anticipate resuming the drilling of conventional targets after we have assessed the results from the current drilling program.  Additionally, we have allocated $7 million to $9 million to the drilling and completion of 2 gross (0.8 net) Recovery-operated Niobrara carried wells in a joint venture with TRW Exploration. We expect to have a non-operating working interest ranging from 25% to 50% in several wells drilled by the operator in the Grover Field area in 2011.  We estimate the completed cost for each well to be between $1,000,000 and $4,000,000 and we would be required to fund our prorate portion of each well or be subject to a non-consent penalty. We cannot predict how many well proposals we will receive.

Our 2011 capital expenditure budget is subject to various factors, including market conditions, oilfield services and equipment availability, commodity prices and drilling results. While we continue to explore opportunities to expand our acreage position, our current budget is allocated to drilling and completing wells. Any leasehold acquisitions that we choose to pursue would require us to adjust our budget.  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.

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.

Our 2011 drilling program is designed to provide flexibility in identifying suitable well locations and in the timing and size of capital investment. We anticipate funding this 2011 capital program through a combination of existing working capital, operating cash flows, cash contributions from our joint venture participants, and by issuing additional equity or debt securities.
 
 
We anticipate that our operating cash flows will continue to increase as additional wells are drilled and placed on production. The addition of successfully completed Niobrara wells developed under our Joint Venture could provide significant operating cash flows.  If we are able to drill and complete our wells as anticipated and they produce at rates similar to those generated by our existing wells, we would expect our production rates and operating cash flows to grow as we move through 2011.
 
We cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings will be sufficient to fund our anticipated capital expenditures. If our existing and potential sources of liquidity through operating cash flows and cash contributions from joint venture participants are not sufficient to undertake our planned capital expenditures, we may be required to alter our drilling program, pursue additional joint ventures with third parties, sell interests in one or more of our properties or sell common shares or debt securities. If we are not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our expenditures or restructure our operations, and we would be unable to implement our planned exploration and drilling program.
 
During the three month periods ended March 31, 2011 and 2010, net cash used in operating activities was $2,440,205 and $195,332, respectively. The primary changes in operating cash during the three months ended March 31, 2011 was $3,743,186 of net loss, adjusted for non-cash charges of $1,075,930 of depreciation, depletion and amortization expenses (“DD&A”) and accretion expense, $546,529 of stock-based compensation, and $837,376 of amortization of deferred financing costs , offset by increases in accounts receivable of $788,431 and restricted cash of $848,280.
 
During the three month periods ended March 31, 2011 and 2010, net cash used by investing activities was $10,711,902 and $10,362,271. The primary changes in investing cash during the three months ended March 31, 2011 was $8,416,874 related to our acquisitions of unproved acreage and $2,281,487 in drilling capital expenditures.
 
During the three month periods ended March 31, 2011 and 2010, net cash provided by financing activities was $9,734,703 and $10,621,250. The primary changes in financing cash during the three months ended March 31, 2011 was net proceeds from the exercise of warrants for $2,129,801 and the issuance of convertible notes payable for $8,400,000, offset by debt repayments of $395,098.
 
We believe we have sufficient liquidity and capital resources to conduct our current operations for the next 12 months. However, to fund our planned capital projects, we will seek to obtain additional working capital through the sale of our securities, the successful deployment of our cash on hand, bank lines of credit, and project financing. Other than our three credit agreements for an aggregate of approximately $20 million, and our recent issuance of $8 .4 million of convertible debentures (as described under "Business - Recent Developments ”), 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 may be subject to the repayment of the approximately $20 million credit agreements which mature s on September 1, 2012. 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.
 
Off-Balance Sheet Arrangements
 
We do not have any off-balance sheet financing arrangements.
 
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 our records in accordance with generally accepted accounting principles in the United States, known as 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.
 
 
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 December 31, 2010, using the average, first-day-of-the-month price during the 12-month period ending December 31, 2009.
 
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 required by ASC Topic 932, Extractive Activities—Oil and Gas, 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 unevaluated properties are assessed quarterly to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations.
 
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 an impairment.
 
 
Business Combinations
 
In November 2007, the ASC 805 guidance for business combinations was updated to provide new guidance for recognizing and measuring the assets and goodwill acquired and liabilities assumed in an acquisition. The updated guidance also broadened the definition of a business combination and requires an entity to recognize transaction costs separately from the acquisition. We adopted the updated guidance effective March 6, 2009, and applied it to its three DJ Basin   Acquisitions completed during 2010 (See Note 3 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS).
 
Impairment of Long-lived Assets
 
We record our property and equipment at cost. The cost of our unproved properties is withheld from the depletion base as described above, until such a time as the properties are either developed or abandoned. We review these properties quarterly for possible impairment . We provide an impairment allowance on unproved property when we determine that the property will not be developed or the carrying value will not be realized. We evaluate the reliability of our proved properties and other long-lived assets whenever events or changes in circumstances indicate that the recording of impairment may be appropriate. Our impairment test compares the expected undiscounted future net revenue from a property, using escalated pricing, with the related net capitalized costs of the property at the end of the applicable period. When the net capitalized costs exceed the undiscounted future net revenue of a property, the cost of the property is added to the full cost pool.
 
Derivative Instruments
 
During 2010, we 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.
 
Revenue Recognition
 
We derive revenue primarily from the sale of produced natural gas and crude oil. We report 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 our 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, we estimate the amount of production delivered to the purchaser and the price the Company will receive. We use our knowledge of our properties, their historical performance, NYMEX and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates.
 
Asset Retirement Obligations
 
We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties including without limitation the costs of reclamation of our drilling sites, storage and transmission facilities and access roads.We base our estimate of the liability on the industry experience of our management and on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates and determine the credit- adjusted risk-free rate to use. Our estimated asset retirement obligations are reflected in our depreciation, depletion and amortization calculations over the remaining life of our oil and gas properties.
 
Share Based Compensation
 
We account for share-based compensation in accordance with the provisions of ASC 718— Stock Compensation which requires companies to estimate the fair value of share-based payment awards made to employees and directors, including restricted stock grants, on the date of grant using an pricing model.    The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods.    We estimate the fair value of each share-based award using a pricing model in accordance to ASC 718 – Stock Compensation.
 
 
Loss per Common Share
 
Basic earnings (loss) per share is computed based on the weighted average number of common shares outstanding during the period presented. In addition to common shares outstanding, and in accordance with ASC 260 – Earnings per share. Diluted loss per share is computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares had been issued. Potentially dilutive securities, such as stock grants and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive. For the period ending December 31, 2010, outstanding warrants of 23,056,933 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.
 
Income Taxes
 
For tax reporting, we will continue to file its tax returns on an April 30 year end, which is the tax year end of Universal Holdings, Inc., the legal acquirer.
 
We use 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 carryforwards. 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.
 
On March 6, 2009, we adopted the provisions of ASC 740 –Income taxes. ASC 740 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under ASC 740, 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, 2010, we have determined that no liability is required to be recognized due to adoption of ASC 740.
 
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, 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. In our major tax jurisdiction, the earliest years remaining subject to examination are April 30, 2009 and April 30, 2010.
 
 
Industry terms used in this report are defined in the Glossary of Oil and Natural Gas Term located at the end of this prospectus.
 
Overview
 
Recovery Energy Inc. is a Denver based independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the DJ Basin. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team along with that of our operating partners.
 
We have developed and acquired an oil and natural gas base of proved reserves, as well as a portfolio of development drilling and exploratory drilling opportunities of high-impact conventional and non-conventional prospects with an emphasis on multiple producing horizons and the Niobrara shale resource play. We believe these prospects offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Colorado, Nebraska, and Wyoming. Since January 1, 2010 we have acquired or developed 20 producing wells. We currently own interests in approximately 156,500 gross (134,500 net) leasehold acres, of which 153,500 gross (132,500 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska in the DJ Basin.  We intend to continue to evaluate and invest in acquisitions and internally generated prospects.  It is our long-term goal to maximize our DJ Basin acreage position through development drilling of our conventional horizons as well as development of our Niobrara shale potential.
 
We have invested, and intend to continue to invest, primarily in oil and natural gas interests, including producing properties, prospects, leases, wells, mineral rights, working interests, royalty interests, overriding royalty interests, net profits interests, production payments, farm-ins, drill to earn arrangements, partnerships, easements, rights of way, licenses and permits, in the DJ Basin in Colorado, Nebraska, and Wyoming.
 
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, and 25 Mboe of production for the quarter ended March 31, 2011.
 
Our executive offices are located at 1515 Wynkoop Street, Suite 200, Denver, Colorado 80202, and our telephone number is (888) 887-4449. Our web site is www.recoveryenergyco.com. Additional information which may be obtained through our web site does not constitute part of this prospectus. A copy of this prospectus is located at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information on the operation of the SEC’s Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings at www.sec.gov.
Recent Developments and Related Transactions
 
In February 2011, the Company issued in a private placement $8,400,000 aggregate principal amount of three year 8% Senior Secured Convertible Debentures with a group of accredited investors, who are existing shareholders of the Company. Of the proceeds from the sale, $3,000,000 is restricted to acquisition of and drilling activities on specified properties, which were pledged as collateral for the Debentures. The balance of the proceeds are to be used by the Company for working capital. The Debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $2.35 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. Interest on the Debentures is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or at the Company's option in shares of common stock, valued at 95% of the volume weighted average price of the common stock for the 10 trading days prior to an interest payment date. The Company can redeem some or all of the Debentures at any time. The redemption price is 115% of principal plus accrued interest. If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price will include a make-whole premium equal to the remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable in common stock. T.R. Winston & Company LLC acted as placement agent for the private placement and received $400,000 of Debentures equal to 5% of the gross proceeds from the sale.
 
In February 2011, we closed on the acquisition of oil and gas leases from various private individuals on approximately 1,700 leasehold acres in the Grover Field and surrounding area in Weld County, Colorado, and approximately 6,600 net acres in Goshen County, Wyoming. The purchase price was $1,253,780 in cash and $653,449 in common stock.
 
In March 2011, we closed on a purchase agreement with Wapiti Oil & Gas, L.L.C. for the purchase of certain oil and gas interests of approximately 8,060 net acres located in Laramie County, Wyoming. The purchase price was $6,469,552 cash and $5,798,546 in common stock.
 
In March 2011, we entered into a modification of its swap agreement whereby Shell extended the company $1,000,000 of unsecured credit. Additionally, we entered into an additional commodity swap for 100 barrels per day from November 2011 through October 2012 at a price of $100.20 per barrel.
 
In March 2011, we closed on the acquisition of oil and gas leases from various private individuals for $390,000 in cash on approximately 651 net acres in Goshen County, Wyoming.
 
In March 2011, we closed on the acquisition of oil and gas leases from various private individuals for $161,519 in cash on approximately 640 net acres in Goshen County, Wyoming.
 
Transactions with Related Persons
 
During fiscal year 2010 through the date of this report, 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 13,166,667 shares of our common stock. As of May 31, 2011 the Davis entities own 12,461,667 shares of our common stock (representing 19.9% of our outstanding shares). 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, which transaction did not close. The agreement provided for a purchase price of $2,200,000 and 1,550,000 shares of common stock . 1,450,000 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 550,000 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 2,500,000 shares of our common stock which we valued at approximately $1,875,000. In cluded in the acquisition we re 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 2,000,000 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.  The purchase price was $8,000,000 in cash which was due to the sellers on or before December 20, 2010.  We issued 6,666,667 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 6,666,667 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 Investments, LLC .  We financed the majority of our acquisitions with loans from Hexagon Investments, LLC.  We issued an aggregate of 5,000,000 shares of our common stock (representing 8.0% of our outstanding shares) and 4,000,000 warrants to purchase common stock in connection with these financings.  As of May 31, 2011 Hexagon Investments held all of these shares and warrants.  Hexagon Investments also has the right to designate one member of our board of directors pursuant to a stockholders agreement, currently Conway Schatz.  Hexagon Investments was not a related party prior to these loans.  The specific transactions with Hexagon Investments 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 September 1, 2012 and is secured by mortgages on the Wilke Field properties. Hexagon Investments received 1,000,000 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 September 1, 2012 and is secured by mortgages on the Albin Field properties. In connection with the financing Hexagon Investments received 750,000 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 September 1, 2012 and is secured by a mortgage on the acquired property. In connection with the financing Hexagon Investments received 3,250,000 shares of our common stock which we valued at approximately $2,437,500 , a warrant to purchase 2,000,000 shares of our common stock exercisable at $2.50 per share which we valued at approximately $184,589 and one percent overriding royalty in the leases and wells acquired which we valued at $184,589.
 
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 1,000,000 shares of our common stock at $1.50 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 1,000,000 shares of our common stock at $1.50 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 Investments.  
·
In December 2010, the maturity date of the Hexagon Investments loans was extended to September 1, 2012.  We did not pay any consideration for the extension.

Matthew Jennings .  In May 2010, we sold our two medium depth drilling rigs to Resource Energy, Inc., an entity controlled by Mathew Jennings, for $100,000 in cash and a $600,000 note.
 
The note bears interest at an annual rate of prime plus 1%. Interest is payable quarterly, commencing June 30, 2010. Principal payments are due quarterly in eight equal payments commencing on June 30, 2011 and ending on June 30, 2013. Resource Energy has not made any of the scheduled payments on the note and, for financial reporting purposes, we have fully written off this note to bad debt expense, even though we continue to pursue collection. As of May 31, 2011, Mr. Jennings and entities control by Mr. Jennings owned approximately 2,958,334 or 4.7% of our outstanding common stock.
 
TRW Exploration .  In December 2010, we entered into an acquisition and development agreement with TRW Exploration, LLC whereby TRW Exploration paid us $2,000,000 and a 40% carried interest in two horizontal wells for approximately 2,200 net acres in Laramie County, Wyoming. TRW Exploration is required to fund the drilling and completion costs of two horizontal wells on the lands covered by the leases, up to $3,500,000 per well. Costs above $3,500,000 per well shall be shared in accordance with the parties respective interests in the leased lands. We are required to use commercially reasonable efforts to commence the first of these wells on the lands covered by the leases by March 31, 2011 and to use commercially reasonable efforts to commence the second well within 180 days of completion of the first well. TRW Exploration is owned by several of our shareholders, none of whom owns more than 5% of our outstanding shares. 
 
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 us 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.
 
 
Our Strategy
 
It is our belief that the exploration and production industry’s most significant value creation occurs through the drilling of successful development wells and the enhancement of oil recovery in mature fields given appropriate economic conditions. Our goal is to create significant value while maintaining a low cost structure. To this end, our business strategy includes the following elements:
 
Participation in development prospects in known producing basins. We pursue prospects in known producing onshore basins where we can capitalize on our development and production expertise. We intend to operate the majority of our properties and evaluate each prospect based on its geological and geophysical merits.
 
Negotiated acquisitions of properties. We acquire producing properties based on our view of the pricing cycles of oil and natural gas and available exploration and development opportunities of proved, probable and possible reserves.
 
Retain Operational Control and Significant Working Interest. In our principal development targets, we typically seek to maintain operational control of our development and drilling activities. As operator, we retain more control over the timing, selection and process of drilling prospects and completion design, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of our capital expenditures. We have continued to maintain high working interest in our DJ Basin properties which maximizes our exposure to generated cash flows and increases in value as the properties are developed. With operational control, we can also schedule our drilling program to satisfy most of our lease stipulations and continue to put our acreage into “held by production” status, thus eliminating expirations. The majority of our acreage is contiguous which will permit efficiencies in drilling and production operations.

Leasing of prospective acreage. In the course of our business, we identify drilling opportunities on properties that have not yet been leased. At times, we take the initiative to lease prospective acreage and we may sell all or any portion of the leased acreage to other companies that want to participate in the drilling and development of the prospect acreage.
 
Controlling Costs. We maximize our returns on capital by minimizing our expenditures on general and administrative expenses. We also minimize initial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that have already invested capital in such. Historically, we also outsource d some of our geological, geophysical, reservoir engineering and land functions in order to help reduce capital requirements.
 
We recently brought many of these functions in-house to provide us with greater ability to maximize the value of our growing leasehold position.
 
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 have seven employees and are actively seeking a new chief financial officer. 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.
 
 
Competition
 
We compete with numerous other companies in virtually all facets of our business. Our competitors in the exploration, development, acquisition and production business include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater financial resources and in-house technical expertise than we do.
 
Marketing and Pricing
 
We will derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We will sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.
 
Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of natural gas and crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:
 
·
 
changes in global supply and demand for oil and natural gas;
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the actions of the Organization of Petroleum Exporting Countries, or OPEC;
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the price and quantity of imports of foreign oil and natural gas;
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acts of war or terrorism;
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political conditions and events, including embargoes, affecting oil-producing activity;
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the level of global oil and natural gas exploration and production activity;
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the level of global oil and natural gas inventories;
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weather conditions;
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technological advances affecting energy consumption; and
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the price and availability of alternative fuels.
 
From time to time, we will enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:
 
·
 
our production and/or sales of natural gas are less than expected;
·
 
payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
·
 
the counter party to the hedging contract defaults on its contract obligations.
 
In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.
 
Government Regulations
 
General. Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and local laws and regulations. The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impact our operations and can affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different than our competitors. Matters regulated include permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements for the operation of wells, and 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).
 
 
 
Environmental Matters. The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoining property, giving rise to additional liabilities.
 
A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing and may, in addition to other laws, impose liability in the event of discharges, whether or not accidental, failure to notify the proper authorities of a discharge, and other noncompliance with those laws. Compliance with such laws and regulations may increase the cost of oil and gas exploration, development and production, although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.
 
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that dispose or arrange for disposal of the hazardous substances found at the time. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and severable liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA because our jointly owned drilling and production activities generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA.
 
The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because 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.
 
The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by OPA. In addition, to the extent we acquire offshore leases and those operations affect state waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws. OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. We cannot predict whether the financial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or impose substantial additional annual costs to us or otherwise materially adversely affect us. The impact, however, should not be any more adverse to us than it will be to other similarly situated owners or operators.
 
The Federal Water Pollution Control Act Amendments of 1972 and 1977 (“Clean Water Act”) imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm 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 and/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.
 
There are numerous state laws and regulations in the states in which we operate which relate to the environmental aspects of our business. These state laws and regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality.
 
We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you that environmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks generally are not fully insurable.
 
In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.
 
Federal Leases. For those operations on federal oil and gas leases, such operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies. In addition, on federal lands in the United States, the Minerals Management Service (“MMS”) prescribes or severely limits the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, MMS prohibits deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the MMS has been engaged in a 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.
 
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.
 
 
 

 
Our officers and directors are listed below. Our directors are generally elected at our annual shareholders' meeting and hold office until the next annual stockholders' meeting or until their successors are elected and qualified.
 
Name
Age
Position
Roger A. Parker
49
Chief Executive Officer, President, Interim Principal Financial Officer, Director, Chairman of Board of Directors
Christopher R. Barber
32
Controller, Interim Principal Accounting Officer
James J. Miller
33
Director
Timothy N. Poster
42
Director
Conway J. Schatz
40
Director

 
The principal occupations of our officers and directors during the past several years are as follows:
 
Roger A. Parker: Chief Executive Officer, President, Interim Principal Financial Officer, Director and Chairman of Board of Directors. Mr. Parker joined our board of directors as chairman in November, 2009. He has been in the exploration and production sector of the oil and gas business his entire career. In addition to other private entities, he led Delta Petroleum Corporation from May 1987 through May 2009 where he served as President from May 1987 to June 2005 and as Chairman and CEO from July 2005 to May 2009. From May 2009 to November 2009, Mr. Parker invested privately in oil and gas ventures. He received a Bachelor of Science degree in Mineral Land Management from the University of Colorado in 1983. He is a former board member of the Independent Petroleum Association of the Mountain States (IPAMS). He also serves on other community related boards including Denver Art Museum Board of Trustees, Boy Scouts of America – Denver Area Council Board of Trustees, Alliance for Choice in Education (ACE) Board of Trustees.
 
Christopher R. Barber: Controller, Interim Principal Accounting Officer.Mr. Barber became our controller in June 2010 and our interim principal accounting officer in April 2011.  Prior to coming to Recovery Energy, he worked in the audit division of Hein & Associates for more than five years.  He has a Bachelors degree in accounting from the University of Denver.  He became a licensed CPA in 2002.
 
James J. Miller: Director. Mr. Miller joined our board of directors in November, 2009. He has been a Managing Director at FirstCity Crestone, leading the firm’s acquisition and business development initiatives, since May, 2007. FirstCity Crestone is a special situations investment company specializing in distressed debt acquisitions, high yield senior and junior loans, and small market buyouts. Prior to his time at FirstCity Crestone, Mr. Miller was a Director of Acquisitions for Summit Investment Management from April of 2005 through April of 2007 and Republic Financial from April of 2004 to April of 2005. He graduated from Colorado College with a BA in political science and history.
 
Timothy N. Poster: Director. Mr. Poster joined our board of directors in June, 2010. Mr. Poster has been a partner in Fertitta Entertainment, a worldwide investment venture fund focused mostly on gaming related opportunities, since November, 2010. He was senior vice president of strategy and development for Wynn Las Vegas, a subsidiary of Wynn Resorts, July, 2008 through November, 2010. In 2004, Mr. Poster acquired Golden Nugget Hotel & Casino in Las Vegas and Laughlin, Nevada which he sold in 2005. Between selling the Golden Nugget in 2005 and joining Wynn Las Vegas in June, 2010, Mr. Poster managed his investments. In 2000, Mr. Poster sold Travelscape.com, which he had founded and developed, to Expedia. Mr. Poster received his Bachelors degree in finance from the University of Southern California in 1995 .
 
Conway J. Schatz: Director. Mr. Schatz joined our board of directors in June, 2010. Mr. Schatz currently serves as Vice-President of Hexagon Investments, Inc., a Denver-based private equity firm, overseeing the energy and real estate investing. Mr. Schatz joined Hexagon in 1998. Prior to 1998, Mr. Schatz worked in the Business Advisory / Audit division of Arthur Andersen, LLP, with client industries such as oil and gas, light manufacturing, financial services, real estate, cable and technology. Mr. Schatz also serves as a director and advisory committee member to a Colorado based real estate operating company, and a European real estate fund. Mr. Schatz became a Certified Public Accountant in 1996, licensed in the state of Colorado. Mr. Schatz received dual Bachelor of Science degrees in Finance and Accounting from Minnesota State University in 1992, an Executive Masters of Business Administration from the Daniels College of Business at the University of Denver in 2001 and an Executive Masters of Science in Real Estate Development and Construction Management in 2010. Mr. Schatz's employer Hexagon is the lender on our three credit agreements with aggregate outstanding balances of approximately $23.3 million. Hexagon and its affiliates own 6,500,000 shares of our common stock and warrants to purchase 3,000,000 common shares (representing in the aggregate approximately 18% of our outstanding shares). Mr. Schatz is the designee of Hexagon under a stockholders' agreement among us, Hexagon and other stockholders pursuant to which the stockholders have agreed to vote in favor of Hexagon's designee for a seat on our board of directors.
 
 
Executive compensation
 
Executive compensation for fiscal 2010 and  2009
 
The compensation earned by our executive officer for fiscal 2009 and 2010  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 2010 and 2009 fiscal years. There were no non-equity incentive plan compensation, stock option awards, change in pension value or any non-qualifying deferred compensation earnings during fiscal 2010 or 2009. The amounts in the table are in dollars. In May 2010 Roger A. Parker became our chief executive officer and Jeffrey A. Beunier became our president and chief financial officer.  Mr. Beunier resigned in April, 2011.
 
Name and
principal position
 
Year
 
Salary
   
Bonus
   
Stock
Awards
   
Other
compensation
   
Total
 
                                   
Roger A. Parker (chief executive
 
2010
  $ 160,000       -0- (1)   $ 5,671,955 (5)   $ 851,040 (2)(3)   $ 6,712,995  
officer since May 1, 2010)  
2009
  $ -0-       -0-             $ -0-     $ -0-  
                                             
Jeffrey A. Beunier (chief executiveofficer
from September 1, 2009
to April 30, 2010; president
 
2010
  $ 216,666     $ 50,000 (1)   $ 1,181,396 (4)   $ 791,040 (3)   $ 2,239,102  
and chief financial officer
from May 1, 2010 to April 11, 2011)
 
2009
  $ 50,769       -0-     $ 82,068 (4)   $ 91,187     $ 132,837  
                                             
Lanny M. Roof (chief executive
 
2010
    -0-       -0-       -0-       -0-       -0-  
officer and chief financial officer
until September 20, 2009) (6)
 
2009
 
    -0-       -0-       -0-       -0-       -0-  
 
(1)
 
No yearend bonus has been determined for 2010; in connection with Mr. Beunier's resignation we agreed that he would receive the same 2010 bonus amount as awarded to Mr. Parker, if any.
 
(2)
 
Reflects payment to Mr. Parker of $60,000 of expense reimbursement included in his employment agreement since becoming our chief executive officer in May, 2010.
 
(3)
 
Reflects overriding royalty interests of $791,040 awarded to each of Mr. Parker and Mr. Beunier pursuant to their employment agreements, which have since been amended to eliminate future override royalty interest awards.
 
(4)   Mr. Beunier was granted 464,200 and 1,635,800 shares of our common stock in 2009 and 2010, respectively, pursuant to his employment agreement.  We recognized $82,068 and $1,181,396 of compensation expense in 2009 and 2010, respectively, for these shares.  
(5)   Mr. Parker was granted 5,500,000 shares of our common stock in 2009 pursuant to his employment agreement.  We recognized $5,671,955 of compensation expense for these shares in 2010 since becoming our chief executive officer.  
(6)   Mr. Roof resigned as our chief executive officer and chief financial officer on September 21, 2009.  Mr. Beunier became our chief executive officer and chief financial officer on that date.  
 
We have an employment agreement with Mr. Parker which is described below.
  
Roger A. Parker. Under his employment agreement Mr. Parker receives an annual base salary of $240,000 and is eligible for an annual cash bonus based on performance goals that may include 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 receives a monthly, non-accountable expense reimbursement of $7,500 for expenses related to company business. Mr. Parker has received grants totaling 5,500,000 shares of our common stock, 100,000 of which vested on January 1, 2011 with the remaining 5,400,000 vesting on July 1, 2011. The shares vest immediately upon a change of control or if Mr. Parker's services as chief executive officer and board chairman are terminated other than for cause or by Mr. Parker. Mr. Parker's agreement permits Mr. Parker to engage in other business activities in the energy industry as long as such activities do not unreasonably or materially interfere with the performance of Mr. Parker’s duties for the Company.
 
 
Compensation of Directors
 
The table below sets forth the compensation earned by our non-employee directors during the 2009 fiscal year. There was no non-equity incentive plan compensation, stock options, change in pension value or any non-qualifying deferred compensation earnings during the 2010 and 2009 fiscal years. All amounts are in dollars.
 
Name  
Year
 
Fees Earned or
Paid in Cash
Compensation
   
Stock
Awards
   
All Other
Compensation
   
Total
 
Roger A. Parker(1)
 
2010
  $ -0-     $ 773,305     $ 30,000 (2)   $ 803,305  
    2009   $ -0-     $ 386,653     $ 11,250 (2)    $ 397,903  
                                     
James J. Miller
 
2010
  $ 15,000     $ 275,570       -0-     $ 290,570  
    2009   $ 1,250     $ 6,938             $ 8,188  
                                     
Timothy N. Poster  
2010
  $ 5,000     $ 384,953             $ 389,953  
    2009   $ -0-     $ -0-             $ -0-  
                                     
Conway J. Schatz   2010   $ 10,000     $ 89,721       -0-     $ 99,721  
    2009   $ -0-     $ -0-       -0-     $ -0-  
 
(1)    Mr. Parker became our chief executive officer on May 1 , 2010.
(2)   Reflects payment to Mr. Parker of the expense reimbursement described above prior to becoming our chief executive officer in May, 2010.    
  
We have entered into independent director agreements with each of our non-employee directors.
 
James Miller. Mr. Miller receives an annual fee of $10,000, payable quarterly, for serving on our board of directors and an additional annual fee of $10,000, payable quarterly for serving as chair of our compensation committee. Mr. Miller will receive 200,000 shares of our common stock on January 1, 2011. 101,666 of the shares will be vested upon issuance, 15,000 shares will vest on each of April 1, July 1 and September 1, 2011, and 26,667 shares will vest on January 1, 2012 and January 1, 2013. The shares fully vest upon a change of control or termination of Mr. Miller's services as a director by Recovery Energy other than for cause. Mr. Miller's agreement permits Mr. Miller 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 Mr. Miller becomes aware of a business opportunity, he has no affirmative duty to present or make such opportunity available to us.
 
Timothy N. Poster. Mr. Poster receives an annual fee of $10,000, payable quarterly, for serving on our board of directors. Mr. Poster received a grant of 500,000 shares of our common stock, 50% of which vest on January 1, 2011 and the other 50% vest on January 1, 2013. The shares fully vest upon a change of control or termination of Mr. Poster's services as a director by Recovery Energy other than for cause. Mr. Poster's agreement permits Mr. Poster 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 Mr. Poster becomes aware of a business opportunity, he has no affirmative duty to present or make such opportunity available to us.
 
Conway J. Schatz. Mr. Schatz receives an annual fee of $10,000, payable quarterly, for serving on our board of directors and an additional annual fee of $10,000, payable quarterly for serving as chair of our audit committee. Mr. Schatz received a grant of 150,000 shares of our common stock, which vest equally on January 1, 2011, 2012 and 2013. The shares fully vest upon a change of control or termination of Mr. Schatz's services as a director by Recovery Energy other than for cause. Mr. Schatz's agreement permits Mr. Schatz 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 Mr. Schatz becomes aware of a business opportunity, he has no affirmative duty to present or make such opportunity available to us.
 
 
The Board of Directors and Committees Thereof
 
Our board of directors held six meetings in 2010 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 director follows the standards of independence established under the NASDAQ rules in determining if directors are independent and has determined that James Miller is an “independent director” under those rules. 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 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 a compensation committee. The membership and function of the compensation committee is described below.
 
Compensation committee
 
We established a compensation committee in November, 2009 consisting of Mr. Parker and Mr. Miller. Our compensation committee currently consists of Mr. Miller, Mr. Poster and Mr. Schatz. Mr. Miller is chair of the compensation committee. The compensation committee did not meet in 2009. The compensation committee will review, approve and modify our executive compensation programs, plans and awards provided to our directors, executive officers and key associates. The compensation committee will also review and approve short-term and long-term incentive plans and other stock or stock-based incentive plans. In addition, the committee will review 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” and “Corporate Governance.”
 
Compensation committee interlocks and insider participation
 
None of the members of the compensation committee is or has been a company officer or employee. 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
 
We did not have an audit committee until June, 2010 because we did not have enough independent directors to form a committee. We established an audit committee in June, 2010 consisting of Mr. Miller, Mr. Poster and Mr. Schatz, with Mr. Schatz serving as chair. In the absence of an audit committee, the entire board reviewed and discussed the 2009 audited financial statements with management. In 2009 Mr. Beunier was our only director who meets the Securities and Exchange Commission's definition of an audit committee financial expert, and he was not independent because of his role as our chief executive officer. We believe that Mr. Schatz, who joined our board in June, 2010 and is chair of our audit committee, meets the Securities and Exchange Commission's definition of an audit committee financial expert.
 
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., 1515 Wynkoop Street, Suite 200, Denver, CO 80202, 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. 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 our proxy statement to our corporate secretary, Recovery Energy, Inc., 1515 Wynkoop Street, Suite 200, Denver, CO 80202, 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 2010 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 “Code of Ethics” 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., 1515 Wynkoop Street, Suite 200, Denver, CO 80202, Attention: Corporate Secretary.
 
Board leadership structure
 
The board’s current leadership structure does not separate the positions of chairman and chief 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 Energy, 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 chief executive officer is the appropriate leadership structure at this time. The board, through the chairman and the chief executive officer, are currently responsible for the strategic direction of our company. The president and chief financial officer is currently responsible for the day to day operation and performance of our company. The board feels that this provides an appropriate balance of strategic direction, operational focus, flexibility and oversight.
 
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 Energy's risk policies and processes relating to the financial statements and financial reporting processes and the guidelines, policies and processes for mitigating those risks.
 
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 May 31, 2011 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. 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. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Recovery Energy, 1515 Wynkoop Street, Suite 200, Denver, Colorado 80202.
 
 
Name and Address of Beneficial Owner
 
Beneficially Owned
   
Percent of Class Beneficially Owned
 
Directors and Executive Officers
           
             
Roger A. Parker, Chief Executive Officer and Chairman of Board of Directors
   
5,500,000(1)
     
8.8
%
                 
James J. Miller, Director
   
200,000(2)
     
0.3
%
                 
Conway J. Schatz, Director
   
150,000(2)
     
0.2
%
                 
Timothy N. Poster, Director
   
500,000(2)
     
0.8
%
                 
Officers and directors as a group ( four persons)
   
6,350,000
     
10.1
%
                 
Hexagon Investments, LLC
   
10,500,000(3)
     
15.8
%
                 
Scott J. Reiman
   
10,500,000(3)
     
15.8
%
                 
Reiman Foundation (3)
   
10,500,000(3)
     
15.8
%
                 
Edward Mike Davis, L.L.C. (4)
   
12,461,667(4)
     
19.9
%
                 
Steven B. Dunn and Laura Dunn Revocable Trust (5)
   
6,173,332(5)
     
9.5
%
                 
Beau 8 LLC (5)
   
6,173,332(5)
     
9.5
%
                 
Winston 8 LLC (5)
   
6,173,332(5)
     
9.5
%
 
(1)
 
These shares are subject to vesting as described under "Management - Executive Compensation".
(2)
 
Pursuant to their director appointment agreements, Recovery Energy issued Mr. Miller 200,000 shares of our common stock, Mr. Schatz 150,000 shares of our common stock and Mr. Poster 500,000 shares of our common stock. These shares are subject to vesting as described under "Management - Executive Compensation".
(3)
 
Includes (i) 5,000,000 shares owned by Hexagon Investments, LLC, (ii) 2,000,000 shares underlying warrants held by Hexagon Investments for $2.50 per share exercisable at any time through April 14, 2015, (iii) 1,000,000 shares underlying warrants held by Hexagon Investments for $1.50 per share exercisable at any time through May 24, 2015, (iv) 1,000,000 shares underlying warrants held by Hexagon Investments for $1.50 per share exercisable at any time through January 1, 2016; (v) 516,032 shares owned by Scott J. Reiman and (vi) 983,968 shares owned by Reiman Foundation, which is controlled by Scott J. Reiman. Mr. Reiman is President of Hexagon Investments.
(4)
 
Edward Mike Davis has sole voting control over Edward Mike Davis, L.L.C.
(5)
 
Includes (i) 3,147,000 shares owned by Steven B Dunn and Laura Dunn Revocable Trust, (ii) 1,666,667 shares underlying warrants held by Steven B Dunn for $1.50 per share exercisable at any time through May 23, 2015, (iii) 346,666 shares owned by Beau 8, LLC, (iv) 333,333 shares underlying warrants held by Beau 8, LLC for $1.50 per share exercisable at any time through May 23, 2015, (v) 346,333 shares owned by Winston 8, LLC, and (vi) 333,333 shares underlying warrants held by Winston 8, LLC for $1.50 per share exercisable at any time through May 23, 2015.
     
 
 
 
DESCRIPTION OF SECURITIES
 
The following description of our capital 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.
 
Description of Common Stock
 
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.
 
Description of Preferred Stock
 
We have not issued any preferred stock. Our certificate of incorporation must be amended in order for us to issue preferred stock in one or more series in order to fix for each such series such voting powers, full or limited, and such designations, preferences and relative, participating, optional or other special rights and such qualifications, limitations or restrictions thereof, or to authorize our board of directors to fix such terms for future issuances of preferred stock
 
 
 
 
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 Issuable upon Exercise of Warrants
Shares to be Sold in This Offering
Share Ownership After Offering
Apex Investment Holdings Limited (1)
190,100
93,334
93,334
190,100
Bristol Capital Advisors Profit Sharing Plan (2)
166,666
83,333
83,333
166,666
Bristol Investment Fund, Ltd. (2)
585,950
240,000
240,000
585,950
James F. Heekin, Jr. TTEE Canyons Trust UAD 12/18/06
192,566
83,333
83,333
192,566
Keith F. Carney
159,999
106,667
106,667
159,999
Castle Bison, Inc. (3)
34,434
16,667
16,667
34,434
John B. Davies
48,100
32,000
32,000
48,100
Steven B. Dunn and Laura Dunn Revocable Trust
3,147,000
1,666,667
1,666,667
3,147,000
Beau 8 LLC (4)
346,666
333,333
333,333
346,666
Winston 8 LLC (4)
346,333
333,333
333,333
346,333
Edward Mike Davis, L.L.C.
12,461,667
0
12,461,667
0
Elevado Investment Company (5)
176,767
106,666
106,666
176,767
J. Steven Emerson Roth IRA Pershing LLC as Custodian
1,920,000
1,280,000
1,280,000
1,920,000
J. Steven Emerson IRA RO II Pershing  LLC as Custodian
740,100
280,000
280,000
740,100
Emerson Partners
420,000
280,000
280,000
420,000
J. Steven Emerson
300,000
200,000
270,000
230,000
Emerson Family Foundation
240,000
160,000
160,000
240,000
Bryan Ezralow 1994 Trust U/T/D 12/22/1994
540,100
320,000
320,000
540,100
Marc Ezralow Irrevocable Trust U/T/D 06/01/04
160,100
106,666
106,666
106,100
Marc Ezralow 1997 Trust U/T/D 11/26/1997
300,100
186,666
186,666
300,100
Marshall S. Ezralow Roth IRA Pershing LLC as Custodian
320,100
213,334
213,334
320,100
FORT Properties, Inc. (6)
263,333
30,000
30,000
263,333
 
 
 
Jonathan M. Glaser and Nancy Ellen Glaser, TTEES of the Jonathan & Nancy Glaser Family Trust DTD 12-16-98
369,489
266,667
266,667
369,489
Hexagon Investments, LLC (7)
5,000,000
4,000,000
9,000,000
0
Reiman Foundation (7)
516,032
0
516,032
0
Scott J. Reiman (7)
983,968
0
983,968
0
JMB Capital Partners Master Fund, L.P. (8)
0
3,333,333
3,333,333
0
Paul L. Kessler IRA Rollover Pershing LLC as Custodian
40,000
26,666
26,666
40,000
Donald W. Killian III
16,767
16,667
16,667
16,767
David Leff Family Trust U/T/D 02/03/1988
22,000
13,334
13,334
22,000
C&R Leff Irrevocable Trust U/T/D 11/05/2007
22,000
13,334
13,334
22,000
Market Development Consulting Group, Inc. (9)
750,000
1,000,000
1,750,000
0
The Muhl Family Trust DTD 10/11/95, Phillip E. Muhl and Kristin A. Muhl TTEES
200,100
80,000
100,000
180,100
Ralph Olson
26,334
16,667
16,667
26,334
SPA Trust U/T/D 09/13/2004 (10)
160,100
106,666
106,666
160,100
Wallington Investment Holdings, Ltd. (11)
3,000,000
1,333,334
1,333,334
3,000,000
Western Regional Insurance Company, Inc. (12)
2,666,766
1,333,333
1,333,333
2,666,766
C.K. Cooper and Company, Inc. (13)
30,995
0
30,995
0
Jonathan Jaggers
333,333
0
333,333
0
David Knight Hazlett
66,666
0
66,666
0
Alan Gabbard
25,000
0
25,000
0
Eugene McColley
50,000
0
50,000
0
Carlos Gooding
18,000
0
18,000
0
Mark Leyer
7,000
0
7,000
0
Bernd Niederau
40,000
0
40,000
0
Thomas Arnhold
10,000
0
10,000
0
Ulrike Thanner Irmengard
40,000
0
40,000
0
Nina Beteiligungs
10,000
0
10,000
0
 
 
 
Joerg Schorradt
10,000
0
10,000
0
Harry Lindner
16,000
0
16,000
0
Andreas Sperber
23,000
0
23,000
0
Jochen Reff-Kugler
15,000
0
15,000
0
Michael Tendl
7,000
0
7,000
0
Thomas Hoeder
10,000
0
10,000
0
Gerd Volker-Voigt
50,000
0
50,000
0
Christoph Brosig
20,000
0
20,000
0
Mathias Thanner
8,000
0
8,000
0
Christian Brey
10,000
0
10,000
0
Ruediger Arnhold
10,000
0
10,000
0
Mathias Voigt
53,000
0
53,000
0
Dr. Dieter Ropertz
9,000
0
9,000
0
Claus Udo Stein
7,000
0
7,000
0
Dr. Angelika Ursula Schueller-Voitl
70,000
0
70,000
0
Katrin Stoll
45,000
0
45,000
0
Oratio Pronesti
10,000
0
10,000
0
Lena Beteiligungs
18,000
0
18,000
0
Dennis Meurer
7,000
0
7,000
0
Markus Resch
7,000
0
7,000
0
Staehler Christian
11,711
0
11,711
0
Ingo Mertens
7,000
0
7,000
0
Peter Wieser
7,000
0
7,000
0
Mathias Voigt
27,776
0
27,776
0
Van Gilder Insurance Corporation (14)
55,000
0
55,000
0
Michael C. Van Gilder (14)
35,000
0
35,000
0
Roger A. Parker (15)
5,500,000
0
5,500,000
0
Ruth L. Elder(16)
82,000
0
82,000
0
Christopher Barber (16)
142,000
0
142,000
0
Kent Lina (16)
244,187
0
244,187
0
Peter Scott (16)
250,000
0
250,000
0
Thomas Strawser (16)
175,000
0
175,000
0
James Miller (17)
200,000
0
200,000
0
Timothy Poster (17)
500,000
0
500,000
0
Conway J. Schatz (17)
150,000
0
150,000
0
Jeffrey A. Beunier (18)
2,100,100
0
2,100,000
100
Wapiti Oil & Gas, LLC (19)
1,197,294
0
1,197,294
0
 
(1)
Apex Investment Holdings Limited invested in a private placement and is controlled by Susan E. Fairhurst.
(2)
Bristol Capital Advisors Profit Sharing Plan and Bristol Investment Fund, Ltd. invested in a private placement and are controlled by Paul Kessler.
(3)
Castle Bison, Inc. invested in a private placement and is controlled by Raul Silvestre.
(4)
Beau 8 LLC and Winston 8 LLC invested in a private placement and are controlled by Steven B. Dunn.
(5)
Elevado Investment Company invested in a private placement and is controlled by Bryan Ezralow.
(6)
FORT Properties, Inc. invested in a private placement and is controlled by Charles B. Runnels, III.
(7)
Hexagon Investments is our lender, and it and the Reiman Foundation are controlled by Scott J. Reiman.
(8)
JMB Capital Partners Master Fund, L.P. invested in a private placement and is controlled by Cyrus Hadidi.
(9)
Market Development Consulting Group, Inc. provides investor services to us and is controlled by David Castaneda.
(10)
SPA Trust U/T/D 09/13/2004 invested in a private placement and is controlled by Marc Ezralow.
(11)
Wallington Investment Holdings, Ltd. invested in a private placement and is controlled by Michael Khoury.
(12)
Western Regional Insurance Company, Inc. invested in a private placement and is controlled by Richard Merkin.
(13)
CK Cooper provided financial advisory services to us, its ceo is Alexander Montano.
(14)
Van Gilder Insurance is the landlord for our principal executive offices. Michael Van Gilder is the ceo of Van Gilder Insurance, Inc. and controls Van Gilder Insurance.
(15)
Mr. Parker is our chief executive officer and chairman of our board of directors.
(16)
Ms. Elder, Mr. Lina, Mr. Strawser and Mr. Barber are employees of Recovery.
(17)
Mr. Miller, Mr. Poster and Mr. Schatz are directors of Recovery.
(18)
Mr. Beunier was our president and chief financial officer until April 2011.
(19)
Wapiti Oil & Gas, LLC sold oil and gas properties to us and is a publicly-traded company.
 
 
The shares offered hereby consist of:
 
·
4,432,340 shares offered by us to be issued upon conversion of our 8% senior secured debentures and as interest on such debentures
·
12,692,000 shares underlying warrants held by investors in private placements
·
1,148,486 shares held by investors in private placements
·
13,658,961 shares issued by us to the sellers of oil and gas properties we have purchased
·
6,500,000 shares and 4,000,000 shares underlying warrants issued to our lender and its affiliates
·
7,243,187 shares held by our directors, officers and other employees
·
90,000 shares issued to our landlord pursuant to the lease of our executive offices
·
30,995 shares issued by us as compensation to our financial advisor
·
2,100,000 shares held by a former officer and director
·
750,000 shares issued by us as compensation to our management consultant
·
1,000,000 shares underlying warrants issued by us to our management consultant
 
PLAN OF DISTRIBUTION
 
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 OTC 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.
 
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).
 
4,432,340 shares are being offered by us to the holders of our $8,400,000 aggregate principal amount of 8% senior secured debentures as interest payments and in the event of conversion of the debentures. These shares are not being offered to the public.
 
 

The financial statements of Recovery Energy, Inc. and subsidiaries as of December 31, 2010 and 2009 , and for the year ended December 31, 2010 and for the period from March 6, 2009 (inception) to December 31, 2009 are included herein in reliance on the report of Hein & Associates LLP, independent registered public accounting firm, as experts in accounting and auditing.
 
The financial statements of the Wilke Field Acquisition Properties for the year ended December 31, 2009 is included herein in reliance on the report of Hein & Associates LLP, independent registered public accounting firm, as experts in accounting and auditing.
 
The financial statement of the Albin Field Acquisition Properties for the year ended December 31, 2009 are included herein in reliance on the report of Hein & Associates LLP, independent registered public accounting firm, as experts in accounting and auditing.
 
The financial statements of the State Line Field Acquisition Properties for the three months ended March 31, 2010 are included herein in reliance on the report of Hein & Associates LLP, independent registered public accounting firm, as experts in accounting and auditing.
 
WHERE YOU CAN FIND MORE INFORMATION
 
We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the shares of common stock offered by this prospectus. We have not included in this prospectus all the information contained in the registration statement and you should refer to the registration statement and its exhibits for further information.
 
We are subject to the informational requirements of the Exchange Act and are required to file annual and quarterly reports, proxy statements and other information with the SEC. You can inspect and copy reports and other information filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. You may also obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0300. The SEC also maintains an Internet site at http:\\www.sec.gov that contains reports, proxy and information statements regarding issuers, including us, that file electronically with the SEC.
 
You should only rely on the information incorporated by reference or provided in this prospectus or any supplement. We have not authorized anyone else to provide you with information. The common stock is not being offered in any state where the offer is not permitted. You should not assume that the information in this prospectus or any supplement is accurate as of any date other than the date on the front of this prospectus or the supplement.
 
We will provide to each person, including any beneficial owner, to whom a prospectus is delivered, a copy of any or all of the information that has been incorporated by reference in this prospectus but not delivered with the prospectus. You may request a copy of such information and our filings with the SEC, at no cost, by writing or calling us at the following address or telephone number:
 
Recovery Energy, Inc.
1515 Wynkoop St., Suite 200
Denver, CO 80202
1-888-887-4449
 
Exhibits to the filings will not be sent, however, unless those exhibits have specifically been incorporated by reference in this prospectus.
 
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.
 
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 report.
 
bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
 
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.
 
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 lessor 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.
 
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.
 
 
RECOVERY ENERGY, INC.
Index to Financial Statements
 
Annual Financial Statements
   
Report of Independent Registered Public Accounting Firm
 
F-2
Consolidated Balance Sheets – December 31, 2010 and 2009
 
F-3
Consolidated Statement of Operations – For the year ended December 31, 2010, and the period from March 6, 2009 (Inception) through December 31, 2009
 
F-5
Statement of Shareholders’ Equity – For the year ended December 31, 2010, and the period from March 6, 2009 (Inception) through December 31, 2009
 
F-6
Statement of Cash Flows – For the year ended December 31, 2010, and the period from March 6, 2009 (Inception) through December 31, 2009
 
F-7
Notes to Financial Statements
 
F-9
     
Interim Financial Statements
   
Consolidated Balance Sheets – March 31, 2011 and December 31, 2010
 
F-33
Consolidated Statement of Operations – For the three months ended March 31, 2011 and 2010
 
F-35
Consolidated Statement of Cash Flows – For the three months ended March 31, 2011 and 2010
 
F-36
Notes to Financial Statements
 
F-37
     
Wilke Field Acquisition Properties
   
Report of Independent Registered Public Accounting Firm
 
F-52
Statement of Operations – For the year ended December 31, 2009
 
F-53
Statement of Member’s Capital – For the year ended December 31, 2009
 
F-54
Statement of Cash Flows – For the year ended December 31, 2009
 
F-55
Notes to Financial Statements
 
F-56
     
Albin Field Acquisition Properties
   
Report of Independent Registered Public Accounting Firm
 
F-64
Statement of Revenues and Direct Operating Expenses – For the year ended December 31, 2009
 
F-65
Unaudited Statements of Revenues and Direct Operating Expenses – For the three months ended March 31, 2009 and 2010
  F-66
Notes to Financial Statements
 
F-67
     
State Line Field Acquisition Properties
   
Report of Independent Registered Public Accounting Firm
 
F-70
Statements of Revenues and Direct Operating Expenses – For the three months ended March 31, 2010
 
F-71
Notes to Financial Statements
 
F-72
 

 

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 as of December 31, 2010 and 2009, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the year ended December 31, 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting  principles  used and significant estimates made by management, as well as evaluating the overall financing 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, 2010 and 2009, and the results of their operations and their cash flows for the year ended December 31, 2010 and for the period from March 6, 2009 (Inception) through December 31, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ HEIN & ASSOCIATES LLP
 
Denver, Colorado
 
March 31, 2011 
 
 
RECOVERY ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
 
   
December 31
   
December 31
 
   
2010
   
2009
 
Assets
Current Assets:
           
Cash
 
$
5,528,744
   
$
108,400
 
Restricted Cash
   
1,150,541
     
20,876
 
Accounts Receivable
   
857,554
     
100,000
 
Prepaid assets
   
27,772
     
55,249
 
Total current assets
   
7,564,611
     
284,525
 
                 
Oil and gas properties (full cost method), at cost:
               
Undeveloped properties
   
33,605,594
     
-
 
Developed properties
   
26,307,975
     
-
 
Wells in progress
   
1,219,397
     
-
 
Total Property and equipment
   
61,132,966
     
-
 
                 
Less accumulated depreciation, depletion and amortization
   
(5,008,606
)
   
-
 
Net properties and equipment
   
56,124,360
     
-
 
                 
Other assets:
               
Office equipment, net
   
56,236
     
470
 
Prepaid advisory fees
   
979,449
     
-
 
Deferred financing costs
   
3,211,566
     
-
 
Restricted cash and deposits
   
185,707
     
110,031
 
Assets held for sale
   
-
     
500,000
 
Total other assets
   
4,432,958
     
610,501
 
                 
Total Assets
 
$
68,121,929
   
$
895,026
 
                 
 
The accompanying notes are an integral part of these financial statements. 
 
 

 
RECOVERY ENERGY, INC.
CONSOLIDATED BALANCE SHEETS

   
December 31
   
December 31
 
   
2010
   
2009
 
Liabilities and Shareholders' Equity
Current Liabilities:
           
Accounts payable
 
$
968,295
   
$
106,355
 
Liabilities from price risk management
   
398,840
     
-
 
Related Party Payable
   
11,638
     
70,876
 
Common Stock Issuable
   
-
     
100,000
 
Accrued expenses
   
1,540,592
     
51,523
 
Short term note
   
208,881
     
-
 
Total current liabilities
   
3,128,246
     
328,754
 
                 
Asset retirement obligation
   
507,280
     
-
 
Term notes
   
20,229,801
     
-
 
Total long term liabilities
   
20,737,081
     
-
 
                 
Total Liabilities
   
23,865,327
     
328,754
 
                 
                 
Common Stock Subject to Redemption Rights, $0.0001 par value;
   
86,258
     
172,516
 
42,500 and 85,000 shares issued and outstanding as of December 31, 2010 and 2009
               
                 
Other Shareholders’ Equity:
               
Preferred Stock, $0.0001 par value: 10,000,000 authorized; no shares issued or outstanding
   
-
     
-
 
Common Stock, $0.0001 par value: 100,000,000 shares authorized; 57,814,369 shares and 10,774,000 shares issued and outstanding (excluding shares subject to redemption) as of December 31, 2010 and 2009
   
5,781
     
1,077
 
Additional Paid in Capital
   
90,861,527
     
30,304,060
 
Accumulated deficit
   
(46,696,964
)
   
(29,911,381
)
Total other shareholders' equity
   
44,170,344
     
393,756
 
                 
Total Liabilities, Common Stock Subject to Redemption Rights and Other Shareholders’ Equity
 
$
68,121,929
   
$
895,026
 
 
The accompanying notes are an integral part of these financial statements. 
 
 

RECOVERY ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

   
Year Ended
   
March 6, 2009
(Inception) through
 
   
December 31, 2010
   
December 31, 2009
 
Revenue:
           
Oil sales
 
$
9,504,737
   
$
-
 
Gas sales
   
68,075
     
-
 
Operating fees
   
13,487
     
-
 
Realized gain (loss) on hedges
   
570,233
     
-
 
Price risk management activities
   
(398,840
)
   
-
 
                 
Total Revenues
   
9,757,692
     
-
 
                 
Costs and expenses:
               
Production costs
   
862,042
     
-
 
Production taxes
   
1,056,244
     
-
 
General and administrative (includes non-cash consideration of $10,143,896 and $684,778 for the periods ended December 31, 2010 and 2009)
   
12,576,798
     
1,057,306
 
Depreciation, depletion and amortization
   
5,036,648
     
-
 
Impairment of equipment
   
-
     
2,750,000
 
Bad debt expense
   
400,000
     
-
 
Fair value of common stock and warrants issued in aborted property acquisitions
   
-
     
8,404,106
 
Reorganization and merger costs
   
-
     
17,700,000
 
                 
Total costs and expenses
   
19,931,732
     
29,911,412
 
                 
Loss from operations
   
(10,174,040
)
   
(29,911,412
)
                 
Unrealized gain on Lock-up
 
$
28,666
   
$
-
 
Interest expense (includes non-cash interest expense of $3,989,649 and $0 for the periods ended December 31, 2010 and 2009)
 
$
(6,640,209
)
 
$
31
 
                 
Net Loss
 
$
(16,785,583
)
 
$
(29,911,381
)
                 
Earnings per common share
               
Basic  and Diluted
 
$
(0.46
)
 
$
(3.05
)
                 
Weighted average shares outstanding:
               
Basic and diluted
   
36,671,213
     
9,815,683
 

The accompanying notes are an integral part of these financial statements.
 
 
RECOVERY ENERGY, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
For the year ended December 31, 2010 and from March 6, 2009 (Inception) through December 31, 2009
 
         
Other Shareholders' Equity
 
                                     
                                     
   
Common Stock Subject
               
Additional
             
   
to Redemption
   
Common Stock
   
Paid-In
   
Accumulated
       
   
Shares
   
Amount
   
Shares
   
Amount
   
Capital
   
Deficit
   
Total
 
                                           
Balance, March 6, 2009 (Inception)
   
-
   
$
-
     
-
   
$
-
   
$
-
   
$
-
   
$
-
 
                                                         
Common stock issued in reverse merger
   
-
     
-
     
2,099,000
     
210
     
(33,957
   
-
     
(33,747
)
                                                         
Common stock issued in exchange of debt
   
  -
     
  -
     
2,100,000
     
210
     
3,249,790
     
-
     
3,250,000
 
                                                         
Common stock issued in lock-up agreement
   
85,000
     
172,516
     
  -
     
  -
     
  -
     
-
     
           -
 
                                                         
Common stock issued in reorganization
   
  -
     
  -
     
5,000,000
     
500
     
17,499,500
     
  -
     
17,500,000
 
                                                         
Common stock issued in attempted acquisition
   
  -
     
  -
     
1,700,000
     
170
     
5,824,830
     
  -
     
5,825,000
 
                                                         
Common stock issued for cash
   
  -
     
  -
     
125,000
     
12
     
499,988
     
  -
     
500,000
 
                                                         
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
   
  -
     
  -
     
(250,000
)
   
(25
)
   
(749,975
)
   
  -
     
(750,000
)
                                                         
Net loss
   
  -
     
 -
     
  -
     
  -
     
  -
     
(29,911,381
)
   
(29,911,381
)
                                                         
Balance, December 31, 2009
   
85,000
     
172,516
     
10,774,000
     
1,077
     
30,304,060
     
(29,911,381
)
   
393,756
 
                                                         
Common stock issued for property acquisitions
   
  -
     
  -
     
11,716,667
     
1,172
     
15,786,328
     
  -
     
15,787,500
 
                                                         
Common stock issued in connection with financing property acquisitions
   
  -
     
  -
     
5,000,000
     
500
     
5,249,500
     
  -
     
5,250,000
 
                                                         
Common stock issued for cash
   
  -
     
  -
     
15,915,154
 
   
1,592
     
14,924,142
     
  -
     
14,925,734
 
                                                         
Common stock issued for services
   
  -
     
  -
     
2,008,862
     
201
     
2,256,038
     
  -
     
2,256,239
 
                                                         
Restricted stock issued to employees and directors
   
  -
     
  -
     
8,943,187
     
894
     
8,375,326
     
  -
     
8,376,220
 
                                                         
Warrants exercised for cash
   
  -
     
  -
     
3,414,000
     
341
     
5,120,658
     
  -
     
5,120,999
 
                                                         
Warrants issued for cash, services and fees
   
  -
     
  -
     
  -
     
  -
     
8,759,221
     
  -
     
8,759,221
 
                                                         
Common stock no longer subject to redemption
   
(42,500)
     
(86,258)
     
42,500
     
4
     
86,254
     
  -
     
86,258
 
                                                         
Net loss
   
  -
     
  -
     
  -
     
  -
     
  -
     
(16,785,583
   
(16,785,583
)
                                                         
Balance, December 31, 2010
   
42,500
   
$
86,258
     
57,814,369
   
$
5,781
   
$
90,861,527
   
$
(46,696,964
 
$
44,170,344
 
 
The accompanying notes are an integral part of these financial statements.
 
 
 
RECOVERY ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
         
March 6, 2009
 
   
Year Ended
December 31, 2010
   
(inception) through
December 31, 2010
 
             
Cash flows from operating activities:
           
Net loss
 
$
(16,785,583
)
 
$
(29,911,381
)
Adjustments to reconcile net loss to net cash provided by operating activities:
               
Impairment
   
-
     
2,750,000
 
Bad debt expense
   
400,000
     
-
 
Stock issued for services
   
325,043
     
-
 
Stock based compensation
   
8,376,220
     
884,778
 
Fair value of warrants issued
   
-
     
3,329,106
 
Non-cash reorganization costs
   
-
     
17,500,000
 
Loss on aborted property acquisitions
   
-
     
5,075,000
 
Changes in the fair value of derivatives
   
398,840
     
-
 
Compensation expense recognized for assignment of overrides
   
1,578,080
     
-
 
Amortization of deferred financing costs
   
3,989,649
     
-
 
Depreciation, depletion, and amortization and accretion of asset retirement obligation
   
5,036,648
     
-
 
                 
Changes in operating assets and liabilities:
               
Accounts receivable
   
(757,554
)
   
(100,000
)
Other assets
   
35,246
     
(55,249
)
Accounts payable
   
872,014
     
72,469
 
Restricted cash
   
(1,129,665
)
   
(20,876
)
Related party production payments
   
(69,312
)
   
70,876
 
Accrued expenses
   
1,489,068
     
24,038
 
Net cash provided by (used in) operating activities
   
3,758,694
     
(381,239
)
                 
Cash flows from investing activities:
               
Additions of producing properties and equipment (net of purchase price adjustment)
   
(25,580,793
)
   
-
 
Acquisition of undeveloped property interests
   
(18,560,412
)
   
-
 
Drilling capital expenditures
   
(4,637,111
)
   
-
 
Sale of undeveloped property interests
   
2,000,000
     
1,500,000
 
Sale of drilling rigs
   
100,000
     
-
 
Additions of property and equipment
   
(55,766
)
   
(750,470
)
Cash acquired in acquisition
           
140
 
Investment in operating bonds
   
(75,675
)
   
(110,031
)
Net cash provided by (used in) investing activities
   
(46,809,757
)
   
639,639
 
                 
Cash flows from financing activities:
               
Proceeds from sale of common stock, units and exercise of warrants
   
28,132,727
     
500,000
 
Proceeds from debt issuance
   
28,500,000
     
-
 
Common stock reacquired in attempted Church acquisition
   
-
     
(750,000
)
Common stock issuable
   
(100,000
)
   
100,000
 
Repayment of debt
   
(8,061,319
)
   
-
 
Net cash provided by (used in) financing activities
   
48,471,408
     
(150,000
)
                 
Net increase in cash and cash equivalents
   
5,420,345
     
108,400
 
Cash and cash equivalents, beginning of period
   
108,400
     
-
 
                 
Cash and cash equivalents, end of period
 
$
5,528,745
   
$
108,400
 
 
The accompanying notes are an integral part of these financial statements. 
 

RECOVERY ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
         
March 6, 2009
 
Supplemental disclosure of non-cash investing and financing activities:
 
Year Ended
December 31, 2010
   
(inception) through December 31, 2010
 
Cash paid for interest
 
$
2,655,131
   
$
-
 
Cash paid for income taxes
 
$
-
   
$
-
 
                 
Non-cash transactions:
               
Purchase of rigs for note payable
 
$
-
   
$
3,250,000
 
Purchase of properties for note payable and common stock
 
$
15,787,500
   
$
8,025,000
 
Stock and warrants issued for deferred financing costs
 
$
6,867,735
   
$
-
 
Stock and warrants issued for prepaid financial advisory fees
 
$
1,234,510
   
-
 
Default on note in property acquisition
 
$
-
   
$
(2,200,000
)
Property additions for asset retirement obligation
 
$
479,238
   
$
-
 
                 
Net liabilities assumed in reverse merger:
 
$
-
   
$
33,886
 
                 

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

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”). 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. Recovery is an independent oil and gas exploration and production company.

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.
 
The accompanying consolidated financial statements include Recovery Energy Inc and its wholly-owned subsidiaries Recovery Oil and Gas, LLC and Recovery Energy Services, LLC.   Intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates in the Preparation of Financial Statements

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.
 
Liquidity
 
Since inception, we have raised approximately $62 million in cash generally through private placements of debt and equity securities.  Although we have a flexible capital program for 2011, we cannot give assurances that our current working capital, our cash flow from operations or any available borrowings will be sufficient to fund our anticipated capital expenditures. If our existing and potential sources of liquidity through operating cash flows and cash contributions from joint venture participants are not sufficient to undertake our planned capital expenditures, we may be required to alter our drilling program, pursue additional joint ventures with third parties, sell interests in one or more of our properties or sell equity or debt securities. If we are not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our expenditures, restructure our operations, sell properties on terms which otherwise may not be as favorable and/or curtail our planned exploration and drilling program.
 
Cash and Cash Equivalents
 
Cash and cash equivalents include cash in banks and highly liquid debt securities that have original maturities of three months or less. Financial instruments that potentially subject the Company to concentration of credit risk consist primarily of cash deposits.  

Restricted Cash

Restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities, and amounts are restricted pursuant to our loan agreements.
 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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 in 2010 or 2009.

During 2010, the Company wrote off a note receivable for $400,000 as a bad debt expense (see Note 13).

Assets Held For Sale
 
Assets held for sale are recorded at the lower of cost or estimated net realizable value.

Concentration of Credit Risk
 
The Company's cash equivalents and short-term investments are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company may at times have balances in excess of the federally insured limits.
 
The Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, 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, 2010, over 64% of the Company's production was 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 and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.
 
Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.
 
 

 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 
Estimated reserve quantities and future net cash flows have the most significant impact on the Company because these reserve estimates are used in providing a measure of the Company's overall value. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company's proved properties.
 
Estimating accumulations of 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 Securities and Exchange Commission (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.

The optimal method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Most of the Company's wells have been producing for a period of less than six years and for some, less than a year. Because of this short production history, other generally less accurate methods such as volumetric analysis and analogy to the production history of wells of ours and other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Company's estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Company's wells are produced over time and more data is available, the estimated proved reserves will be re-determined at least on a quarterly basis in accordance with applicable rules established by the SEC and may be adjusted based on that data.

Depletion and Impairment of Proved Oil and Gas Properties
 
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. The cost of acquiring and evaluating unproved properties are initially excluded from depletion calculations. Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves. For this purpose, we convert our petroleum products and reserves to a common unit of measure. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues was computed by applying a twelve month average of the first day of the month price of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.
 
There were no impairment charges recognized for the year ended December 31, 2010. The Company did not own any oil and gas properties for the period ended December 31, 2009.

 Impairment of Unproved Oil and Gas Properties
 
The Company's unproved properties are evaluated quarterly for the possibility of potential impairment. For the year ended December 31, 2010 no impairment was recorded. The Company did not own any oil and gas properties for the period ended December 31, 2009.
 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Wells in Progress
 
Wells in progress at December 31, 2010 represent the costs associated with wells that have not reached total depth or been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test. The costs for these wells is then transferred to proved property when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods. At December 31, 2010, the Company had two wells awaiting completion in the DJ Basin.  The Company did not own any leases as of December 30, 2009 and therefore did not have any wells in progress.

Deferred Financing Costs
 
For the year ending December 31, 2010, the Company recorded deferred financing costs of approximately $7,200,000 related to the closing of its credit facilities (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 $4,000,000 in the year ended December 31, 2010. The Company did not record any amortization expense or have any debt outstanding as of December 31, 2009.

Prepaid Advisory Fees
 
The Company had prepaid financial advisory fees of approximately $987,000 as of December 31, 2010.  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 totaling $1,234,000.  The amount is being amortized over the term of the underlying agreement. The Company amortized $247,000 in prepaid fees for the year ended December 31, 2010, and will amortize the balance over the next three years and review the asset for impairment on a quarterly basis. No impairment was taken during 2010.
 
The following schedule details the future expense of the prepaid advisory fees.
 
2011
 
$
405,289
 
2012
   
405,289
 
2013
   
168,871
 
   
$
979,449
 

Impairment of Long-lived Assets
 
The Company accounts for the impairment and disposition of long-lived assets (other than the full cost pool) in accordance with ASC 360, Impairment or Disposal of Long-Lived Assets. ASC 360 requires that the Company’s long-lived assets, including its drilling rigs, be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred.  An impairment charge to current operations is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the differences in the carrying value and estimated fair value of the impaired asset.  For the year ended December 31, 2009, the Company recorded impairment expense of $2,750,000 related to the two medium depth drilling rigs.

Fair Value of Financial Instruments

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

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Commodity Derivative Instrument

The Company has entered into commodity derivative contracts, as described below. The Company has utilized swaps to reduce the effect of price changes on a portion of our future oil production. A swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price. The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions.
 
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company'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.
 
Other Property and Equipment
 
Other property and equipment such as office furniture and equipment, vehicles, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is recorded using the straight-line method over the estimated useful lives of three years for computer equipment, and five years for office equipment and vehicles. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition
 
The Company records revenues from the sales of natural gas and crude oil when they are produced and sold.
 
Asset Retirement Obligation
 
The Company follows accounting for asset retirement obligations in accordance with ASC 410, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are included in the ceiling test calculation. Asset retirement obligations incurred in 2010 are classified as Level 3 (unobservable inputs) fair value measurements. The Company did not have any asset retirement obligations in 2009.  The asset retirement liability is allocated to operating expense using a systematic and rational method. As of December 31, 2010 and 2009, the Company recorded a net asset of $479,238 and $0, respectively, and a related liability of $507,280 and $0, respectively.

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

December 31, 2009
 
$
-
 
Liabilities incurred
   
478,208
 
Retirements
   
-
 
Accretion expense
   
28,042
 
Change in estimate
   
1,030
 
         
December 31, 2010
 
$
507,280
 
 
Share Based Compensation
 
The Company accounts for share-based compensation in accordance with the provisions of ASC 718— Stock Compensation which requires companies to estimate the fair value of share-based payment 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.  We estimate the fair value of each share-based award using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards and the estimated volatility of our stock price.

Loss per Common Share
 
Basic earnings (loss) per share is computed based on the weighted average number of common shares outstanding during the period presented. In addition to common shares outstanding, and in accordance with ASC 260 – Earnings per share. Diluted loss per share is computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares had been issued. Potentially dilutive securities, such as stock grants and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive. For the period ending December 31, 2010, outstanding warrants of 23,056,933 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.
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
 
Income Taxes
 
For tax reporting, the Company will continue to file its tax returns on an April 30 year end, which is the tax year end of Universal, the legal acquirer.  
 
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 carryforwards. 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.

On March 6, 2009, the Company adopted the provisions of ASC 740 –Income taxes. ASC 740 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under ASC 740, 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, 2009, the Company has determined that no liability is required to be recognized due to adoption of ASC 740.

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, 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, 20010 and 2009.
 
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Issued Accounting Pronouncements 
 
Recent accounting pronouncements that the Company has adopted or will be required to adopt in the future are summarized below:

In January 2010, the FASB issued Accounting Standards Update ("ASU") 2010-03, Extractive Activities—Oil and Gas (Topic 932), to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules. The significant modifications involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month average of the first day of the month prices and additional disclosure requirements. In contrast to the applicable SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. In April 2010, the FASB issued ASU 2010-14 which amends the guidance on oil and gas reporting in ASC 932.10.S99-1 by adding the Codification SEC Regulation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU 2010-14 are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. The Company adopted the provisions of these updates for the year ended December 31, 2009.
 
In January 2010, the FASB issued ASU 2010-06, "Improving Disclosures About Fair Value Measurements", which provides amendments to fair value disclosures. ASU 2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. The revised guidance for transfers into and out of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010, with the amendments to Level 3 disclosures effective beginning after January 1, 2011. ASU 2010-06 concerns disclosure only. Neither the current requirements nor the amendments effective in 2011 will have a material impact on the Company's financial position or results of operations.
 
 In December 2010, the FASB issued ASU No. 2010-29, Disclosure of Supplementary Pro Forma Information for Business Combinations (ASU 2010-29). ASU 2010-29 requires a public entity who discloses comparative pro forma information for business combinations that occurred in the current reporting period to disclose revenue and earnings of the combined entity as though the business combination(s) occurred as of the beginning of the comparable prior annual period only. This update also expands the supplemental pro forma disclosures required to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. ASU 2010-29 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010 and early adoption is permitted. The Company adopted the provisions of this update for its business combinations that occurred during 2010.
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

DJ Basin Properties Acquisitions – Accounted for as a Business Combination

In January 2010, the Company acquired the Wilke Field from Edward Mike Davis, L.L.C. (“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.    

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.  

All three of the acquisitions above were accounted for using the acquisition method under ASC 805, which requires the acquired assets and liabilities to be recorded at 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
)
                         
 
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS (Continued)

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
 
$
(7,645,854
)
 
$
(29,001,745
)
                 
Net loss
 
$
(16,109,565
)
 
$
(33,489,536
)
                 
Pro forma loss per common share:
               
    Basic and diluted
 
$
(0.44
)
 
$
(3.23
)

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

In July 2010, the Company acquired a 100% working interest in  undeveloped leases in the state of Wyoming for approximately $200,000 in cash after expenses.
 
In August 2010, the Company farmed into approximately 240 net acres in the state of Wyoming in exchange for carrying Davis, the lease owner, for a 26% working interest in one well, which has been drilled, and by assigning 83 net acres in a lease owned by the Company. 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 entered into a purchase agreement with Davis and Spottie, Inc. for the purchase of 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. 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.  We issued 6,666,667 shares of our common stock to acquire the property with an estimated fair value of approximately $12,000,000.
 
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS (Continued)

In December 2010, the Company entered into an acquisition and development agreement with TRW Exploration, LLC whereby TRW Exploration paid $2,000,000 and a 40% carried interest in two horizontal wells. TRW Exploration is required to fund the drilling and completion costs of two horizontal wells on the lands covered by the leases, up to $3,500,000 per well. Costs above $3,500,000 per well shall be shared in accordance with the parties respective interests in the leased lands. The Company is required to use commercially reasonable efforts to commence the first of these wells on the lands covered by the leases by March 31, 2011, and to use commercially reasonable efforts to commence the second well within 180 days of completion of the first well.
 
During the fourth quarter of 2009, the Company pursued a number of acquisition opportunities.  The Company entered into two purchase and sale agreements with 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.
 
The following table presents information regarding the Company's net costs incurred in the purchase of proved and unproved properties, and in the exploration and development activities:
 
 
For the Year Ended December 31,
 
 
2010
 
2009 (1)
 
2008 (1)
 
Property Acquisition costs:
                 
Proved
 
$
24,770,721
   
$
-
   
$
-
 
Unproved
   
33,605,727
     
-
     
-
 
    Exploration costs
   
-
     
-
     
-
 
    Development costs
   
2,756,651
     
-
     
-
 
Total
 
$
61,133,099
   
$
-
   
$
-
 
 
(1)  
Prior to January 1, 2010, the Company did not own any oil and gas properties 
 
DD&A expense related to the proved properties per BOE of production for the year ended December 31, 2010, was $36.98.  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 or 2008.

The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized as of December 31, 2010 by the year in which such costs were incurred:
 
   
Unproved Additions by Year
 
Prior (1)
 
$
-
 
2008 (1)
   
-
 
2009 (1)
   
-
 
2010
   
33,605,727
 
Total
 
$
33,605,727
 
 
(1)  
Prior to January 1, 2010, the Company did not own any oil and gas properties 
 
During 2010, no unproved land costs were determined to be impaired and reclassified to proved property and included in the ceiling test and depletion calculations.  Prior to January 1, 2010, we did not own any oil and gas properties.

The Company incurred $195,075 for the year ended December 31, 2010, in acquisition related expenses which was included in General and Administrative expenses on the Statement of Operations.
 
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
 
 
2010
 
2009 (1)
 
Beginning balance
  $ -     $ -  
Additions to capital wells in progress costs pending the determination of proved reserves
    1,219,254       -  
Ending balance
  $ 1,219,254     $ -  
 
(1)  
Prior to January 1, 2010 the Company did not own any oil and gas properties

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

NOTE 5 - FINANCIAL INSTRUMENTS AND DERIVATIVES

As of December 31, 2009, the Company had no commodity swaps. During March 2010, the Company entered into two commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices.  As of December 31, 2010, the Company had commodity swaps for the following oil volumes:

   
Barrels per
   
Barrels per
   
Price per
 
quarter
Day
Barrel
2011
                       
First quarter
   
18,900
     
210
   
$
85.25
 
Second quarter
   
9,900
     
110
   
$
85.97
 
Third quarter
   
9,900
     
110
   
$
84.95
 
Fourth quarter
   
9,900
     
110
   
$
84.95
 

Subsequent to year-end, the Company entered into an additional commodity swap for 100 barrels per day from November 2011, through October 2012, at a price of $100.20 per barrel.
 
The amount of gain (loss) recognized in income related to our derivative financial instruments was as follows:
 
 
For the Year Ended December 31,
 
 
2010
 
2009
 
Realized gain on oil contracts
$
570,233
     
-
 
Loss on commodity price risk management activities
$
( 398,840
)
 
$
-
 
 
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 risk management activities line on the consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of income.
 
 

 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company records certain of its assets and liabilities on the balance sheet at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:
 
 
Level 1
Quoted prices (unadjusted) for identical assets or liabilities in active markets.
       
 
Level 2
Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable.
       
 
Level 3
Unobservable inputs that reflect the Company’s own assumptions.

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

Cash and cash equivalents

Cash and cash equivalents include all cash balances and any highly liquid investment with an original maturity of 90 days or less. The carrying amount approximates fair value because of the short maturity of these instruments. At December 31, 2010 the Company had $5,528,744 in unrestricted cash and cash equivalents.

Derivative instruments

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, and the credit rating of its counterparty. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.
 
In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

At December 31, 2010, the types of derivative instruments utilized by the Company included commodity swaps (See Note 3). 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.

The following table provides a summary of the fair values of assets and liabilities measured at fair value:
 
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Liability
                       
Commodity swap contracts
 
$
   
$
(398,840)
   
$
   
$
(398,840)
 
Total liability at fair value
 
$
   
$
(398,840)
   
$
   
$
(398,840)
 
 
The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three months ended December 31, 2010.
 
 

 
RECOVERY ENERGY, INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

Concentration of Credit Risk

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

At December 31, 2010, the Company’s derivative financial instruments were held with a single counterparty. The Company continually reviews the credit-worthiness of its counterparties. The Company’s derivative instruments are part of master netting agreements, which reduces credit risk by permitting the Company to net settle for transactions with the same counterparty.

NOTE 7 - LOAN AGREEMENTS

The Company entered into three separate loan agreements with Hexagon Investments, LLC (“Hexagon”) during the twelve months ending December 31, 2010.  All three loans bear annual interest of 15%, and mature on September 1, 2012.  

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 cash flows 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 issued an aggregate of 5 million shares of common stock and 2 million warrants for the Company’s common stock exercisable at $2.50 per share in connection with the origination.  Additionally, the lender received an overriding royalty interest in the 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 1 million warrants with an exercise price of $1.50 per share. The loan modification agreements required the Company to issue 1 million five year warrants to purchase common stock at $1.50 per share to Hexagon if the Company did not repay the loans in full by January 1, 2011.  

In December, 2010 Hexagon extended the maturity to September 1, 2012.

Since the loans were not paid in full by January 1, 2011, the Company issued 1 million additional warrants with an exercise price of $1.50 per share to Hexagon which was valued at approximately $1,600,000, and was expensed  to General and administrative expenses when incurred.

As of December 31, 2010, the outstanding balance on the loan agreements was approximately $20,200,000, of which approximately $200,000 was classified as a current liability and approximately $21.2 million was classified as a long term liability.  For the year ended December 31, 2010, the Company incurred cash interest expense of $2,655,131 on the loan agreements of which $121,570 was accrued as of December 31, 2010. The Company made approximately $5.1 million in principal payments for the year ended December 31, 2010.

Deferred financing costs related to stock, warrants and overriding royalty interests placed in conjunction with the loan agreements total $7,201,743.  During the year ended December 31, 2010, the Company amortized $3,989,649.  Amortization expense for deferred financing costs is included in the Interest Expense line item on the Statement of Operations.  The remaining $3,211,566 in Deferred Financing Costs is classified as long term asset on the Balance Sheet.  The deferred financing costs will amortize on a straight line basis over the remaining life of the loan agreements as detailed below.
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
NOTE 7 - LOAN AGREEMENTS (Continued)
 
Annual Amortization of Deferred Financing Costs:

2011
 
$
1,764,019
 
2012
 
$
1,447,547
 
  
The Company did not capitalize any interest costs for the year ended December 31, 2010.

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

Subsequent to December 31, 2010, the Company issued $8 million in secured convertible debentures.

The Company is subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements. As of December 31, 2010, 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.

NOTE 8 - COMMITMENTS and CONTINGENCIES

Environmental and Governmental Regulation

At December 31, 2010 and 2009 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, 2010 and 2009, 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 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 chief financial officer are no longer entitled to stock grants based on market capitalization milestones.
 
No shares have been issued under these agreements, however under ASC 718 Compensation—Stock Compensation, the Company recorded $200,000 of expense during the period ending December 31, 2009 and no expense for the period ending December 31, 2010.

In November, 2010 we entered into a Put Option Agreement with Grandhaven Energy, LLC ("Grandhaven") whereby Grandhaven has the right to require us to purchase 25% of certain overriding royalty interests it acquired from Davis for a purchase price of up to $2.4 million.  The put option expired unexercised on March 31, 2011. Grandhaven is an affiliate of Hexagon. 
 
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9 - RELATED PARTY TRANSACTIONS

Five of the seven acquisitions the Company completed since the beginning of the year have been with the same seller, Edward Mike Davis, L.L.C.  Davis owned approximately 21.5% of the issued and outstanding shares as of December 31, 2010.  The cash portion of the purchase price for the first three acquisitions were financed with loans from Hexagon which owned approximately 11.2% of the stock issued and outstanding at December 31, 2010.  Hexagon received overriding royalty interests in both the Albin Field assets and the State Line Field assets.  Hexagon also received warrants to purchase 2 million shares of the Company’s common stock at $2.50 per share in connection with the financing of an acquisition and warrants to purchase 1 million shares the Company’s common stock for $1.50 per share in connection with amendments to the loan agreements. A representative of Hexagon also serves on the Company’s Board of Directors.

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, 2010 and 2009 were:
 
   
2010
   
2009
 
Deferred tax assets:
           
  Oil and gas properties and equipment
  $ (1,335,490 )   $ 1,045,275  
  Net operating loss carry-forward
    7,285,426       2,670,740  
  Share based compensation
    3,902,007       1,022,045  
  Abandonment obligation
    188,728       -  
  Derivative instruments
    148,384       -  
  Other
    (30,896     4,386  
Total deferred tax asset
    10,158,159       4,742,446  
                 
Valuation allowance
    (10,158,159     (4,742,446
Net deferred tax asset
  $ -     $ -  
 
Reconciliation of the Company’s effective tax rate to the expected federal tax rate is:
 
 
2010
   
2009
 
Effective federal tax rate
  35.00%
     
35.00%
 
Effect of permanent differences
  (7.78)%
     
(20.40)%
 
State tax rate
  2.20%
     
3.01%
 
Change in rate
(0.23)%
     
 0.00%
 
Other
  3.07%
     
(1.76)%
 
Valuation allowance
(32.26)%
     
(15.85)%
 
Net
  0%
     
0%
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
NOTE 10 - INCOME TAXES (Continued)
 
At December 31, 2010 and 2009, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $19,582,000 and $6,800,000, 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, 2010 will expire in 2030.
 
NOTE 11 - SHAREHOLDERS’ EQUITY

As of December 31, 2010, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 57,814,369 of common shares were issued and outstanding (not including the 42,500 shares issued and outstanding under a lock-up agreement).  No preferred shares were issued or outstanding.  

During 2010, the Company issued 46,997,869 shares of common stock.  The stock issuances were comprised of 11,716,667 shares issued for acquisitions valued at $15,787,500, 2,008,862 shares issued for services valued at $2,256,239, 5,000,000 shares issued in connection with the loan agreements valued at $5,250,000, 8,943,187 shares issued as restricted stock grants to employees valued at $10,283,622, and 15,915,153 shares issued for $20,046,733 of cash.
 
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. 3,41400 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.
 
In addition to shares issued in connection with our reverse merger, from March 6, 2009 (Inception) to December 31, 2009, the Company issued 6,575,000 shares of common stock.  The stock issuance was comprised of 1,450,000 shares issued in attempted acquisitions with an approximate fair value of $5,075,000, 5,000,000 shares issued as compensation to consultants and our chairman with an approximate fair value of $17,500,000, and 125,000 shares issued for $500,000 in cash.

Reverse Merger

On September 21, 2009 Coronado Resources, LLC merged with Recovery Energy, Inc (f/k/a Universal Holdings, Inc).  Coronado assumed all existing assets and liabilities of Recovery.  

Recovery issued 85,000 additional shares in conjunction with the reverse merger under a lock-up agreement (See detailed discussion in Temporary Equity below) and in connection with the merger, the Company agreed to convert a note that was issued by Coronado on May 31, 2009 in the principal amount of $3,250,000 (the “Coronado Note into an aggregate of 2,100,000 shares of our common stock in full satisfaction of the Coronado Note.  Additionally, in conjunction with the reverse merger and pursuant to cancellation agreements executed by the previous financial officers of Universal Holdings, Inc, 5,000,000 shares of common stock were considered returned to the Company.

Recovery issued a total of 2,185,000 shares of its common stock as a result of the reverse merger to the controlling shareholders of Coronado, and 2,099,000 shares to the existing shareholders of Universal.

As a result of this merger, Coronado was deemed the acquirer for accounting purposes, and the transaction was accounted for as a reverse acquisition.  Further, we followed the current guidance of the SEC related to reverse mergers between a private company and a public shell company, and considered the reverse merger as equivalent to a reverse capitalization.  Accordingly, as per SEC guidance for this type of transaction, we recorded no goodwill in the merger.

Subsequent to the reverse merger, the controlling shareholder group acquired 5 million shares of our common stock in conjunction with a reorganization of the company as compensation for their efforts with the reverse merger and ongoing strategic initiatives.  We recognized $17.5 million in non-cash compensation expense for the year ended December 31, 2009.
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11 - SHAREHOLDERS’ EQUITY (continued)

Assets acquired and liabilities assumed of Universal by Coronado on September 21, 2009 based on their book values (which approximated their fair values) were as follows:
 
Cash
 
$
140
 
Accounts payable
   
(1,386
)
Note payable related party
   
(32,500
)
Net liabilities assumed
 
$
(33,746
)
 
In the consolidated statement of operations, expenses include the operations of Universal since September 21, 2009 which is the acquisition date.  The following proforma information presents the results of operations for the year ended December 31, 2009 as if the acquisition had occurred on March 6, 2009:

   
(Unaudited)
 
Revenue
 
$
-
 
Net Loss
 
$
29,977,280
 
Earnings (loss) per share
 
$
(3.05
)
 
For all periods presented, the financial statements of Coronado have been adopted as the historic financial statements of Recovery.  On October 12, 2009 the name of the Company was changed to Recovery Energy, Inc.

Temporary Equity

As part of the reverse merger, 85,000 shares of common stock were issued and outstanding under a lock-up agreement that has terms which may result in the Company reacquiring the shares due to circumstances outside of the Company’s control and therefore the shares are preferential to common shares.  The 85,000 shares, which were valued at $172,516, covered by the lock-up agreement are treated as temporary equity and reported separately from other shareholders’ equity for the period ended December 31, 2009.

As of December 31, 2010, 42,500 shares of the original 85,000 shares of the Company’s common stock issued under the lock-up agreement were issued and outstanding.  Originally, as described above, the lock-up agreement covered 85,000 shares, split between two lock up periods, one lock up period ending September 21, 2010 and the second lock up period ending March 21, 2011.  The 42,500 shares covered under the first lock up period were moved to permanent equity on September 21, 2010 as the lock up period expired.  At December 31, 2010, the 42,500 were treated as temporary equity and reported separately from other shareholders’ equity were valued at $86,258.  At December 31, 2009, the 85,000 shares, were treated as temporary equity and reported separately from other shareholders’ equity were valued at $172,516.
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11 - SHAREHOLDERS’ EQUITY (continued)

A summary of warrant activity for the years ended December 31, 2010 and 2009 is presented below:
 
       
Weighted-Average
 
   
Shares
 
Exercise Price
 
Outstanding at March 6, 2009
   
-
     
-
 
Granted
   
750,000
   
$
3.50
 
Exercised, forfeited, or expired
   
-
     
-
 
Outstanding at December 31, 2009
   
750,000
   
$
3.50
 
Exercisable at December 31, 2009
   
750,000
   
$
3.50
 
                 
Granted
   
25,720,933
   
$
1.67
 
Exercised, forfeited, or expired
   
(3,414,000
)    
1.50
 
Outstanding at December 31, 2010
   
23,056,933
   
$
1.76
 
Exercisable at December 31, 2010
   
16,892,933
   
$
1.50
 

The aggregate intrinsic value of warrants was $9,291,113 and $1,500,000 based on the Company’s closing common stock price of $2.05 and $5.50 as of December 31, 2010 and 2009, respectively, and the weighted average remaining contract life was 4.40 years and 4.92 years.  

Assumptions used in estimating the fair value of the warrants issued for the periods indicated:
 
     
2010
   
2009
Weighted-average volatility
   
80%
   
230%
Expected dividends
   
0.00%
   
0.00%
Expected term (in years)
   
3 – 5
   
3
Risk-free rate
   
0.02% - 2.61%
   
1.49%
 
On January 1, 2011 the Company issued 1,000,000 5-year warrants with an exercise price of $1.50 to Hexagon (see Note 7).
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12 - SHARE BASED COMPENSATION

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

The Company accounts for stock based compensation arrangements in accordance with the provisions of ASC 718 Compensation – Stock Compensation.  ASC 718 requires measurement and recording to the financial statements of the costs of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, recognized over the period during which an employee is required to provide services in exchange for such award. The Company implemented ASC 718 effective March 6, 2009.

During 2009, the Company granted 1,484,200 shares of restricted common stock to officers and directors. 1,112,840 shares vest on January 1, 2011, with the remaining 371,360 shares vesting equally over the next 15 quarters. The fair value of these share grants was calculated to be approximately $4,290,000.

During 2010, the Company granted 6,965,800 shares of restricted common stock to officers and directors. 462,500 shares vest on January 1, 2011, 187,500 shares vest on April 1, 2011, 5,500,000 shares vest on May 1, 2011, with the remainder vesting over the following two years. The fair value of these share grants was calculated to be approximately $5,621,500.
  
During 2010, the Company granted 493,187 shares of restricted common stock to employees. 169,728 shares vest on January 1, 2011, 167,729 shares vest during 2012, and 155,730 shares vest during 2013. The fair value of these share grants was calculated to be approximately $4,290,000.

The Company recognized stock compensation expense of $8,376,220 and $684,778 for the year ended December 31, 2010 and 2009, respectively.
 
A summary of stock grant activity for the year ended December 31, 2010 and 2009 is presented below:
 
   
Shares
 
Restricted Stock Grants Outstanding at March 6, 2009
   
-
 
Granted
   
1,484,200
 
Vested
   
-
 
Outstanding at December 31, 2009
   
1,484,200
 
         
Granted
   
7,458,987
 
Vested
   
-
 
Outstanding at December 31, 2010
   
8,943,187
 

Total unrecognized compensation cost related to non-vested stock granted was $1,376,953 and $3,804,733 as of December 31, 2010 and 2009, respectively. The cost at December 31, 2010 and 2009, is expected to be recognized over a weighted-average remaining service period of 0.23 years and 1.22 years, respectively.
 
 

 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
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 require certain capital improvements prior to their ability to be functional in operations.
 
New management determined that future drilling operations are not part of their strategic plans.  Management has 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.  At December 31, 2009 the rigs were classified as held for sale.

In May 2010, the Company entered into a purchase and sell 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, the Company has elected to fully reserve the $600,000 note receivable (book basis of $400,000) as the ability to recover the amount and the value of the underlying collateral is uncertain at this time.

NOTE 14- SUBSEQUENT EVENTS
 
In February 2011, the Company issued in a private placement sale $8,000,000 aggregate principal amount of three year 8% Senior Secured Convertible Debentures with a group of accredited investors, who are existing shareholders of the Company. The Debentures were issued on February 8, 2011. $3,000,000 of the proceeds from the sale of the Debentures is restricted to acquisition of and drilling activities on specified properties, which were pledged as collateral for the Debentures. The balance of the proceeds are to be used by the Company for working capital. The Debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $2.35 per share, subject to adjustment. 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 compensation in the form of Debentures with an aggregate principal amount equal to 5% of the gross proceeds from the sale.
  
In February 2011, the Company closed on the acquisition of oil and gas leases from various private individuals 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 closed on a purchase agreement on certain oil and gas interests located in Laramie County, Wyoming. The purchase price was $6,469,552 cash and 2,312,942 shares of common stock.  The Company also closed on two acquisitions of oil and gas leases from various private individuals for a combined $551,519 in cash in Goshen County, Wyoming.

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

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
NOTE 15- SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
 
The following table sets forth information for the years ended December 31, 2010, 2009 and 2008 with respect to changes in the Company's proved (i.e. proved developed and undeveloped) reserves:
 
   
Crude Oil
(Bbls)
 
Natural Gas
(Mcf)
 
           
December 31, 2008
   
-
   
-
 
 
Purchase of reserves
   
-
   
-
 
 
Revisions of previous estimates
   
-
   
-
 
 
Extensions and discoveries
   
-
   
-
 
 
Sale of reserves
   
-
   
-
 
 
Production
   
-
   
-
 
December 31, 2009
   
-
   
-
 
 
Purchase of reserves
   
643,955
   
-
 
 
Revisions of previous estimates
   
123,679
   
-
 
 
Extensions, discoveries
   
58,463
   
323,493
 
 
Sale of reserves
   
-
   
-
 
 
Production
   
(133,709)
   
(14,914)
 
December 31, 2010
   
692,388
   
308,579
 
Proved Developed Reserves, included above:
             
 
Balance, December 31, 2008
   
-
   
-
 
 
Balance, December 31, 2009
   
-
   
-
 
 
Balance, December 31, 2010
   
277,669
   
308,579
 
Proved Undeveloped Reserves, included above:
             
 
Balance, December 31, 2008
   
-
   
-
 
 
Balance, December 31, 2009
   
-
   
-
 
 
Balance, December 31, 2010
   
414,719
   
-
 
 
As of December 31, 2010, we had estimated proved reserves of 692,388 barrels ("MBbls") of oil and 308,579 thousand cubic feet ("MCF") of natural gas and with a present value discounted at 10% of $23.6 million. Our reserves are comprised of 93% crude oil and 7% natural gas on an energy equivalent basis.
 
The following values for the 2010 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31, 2010 natural gas price of $4.39 per MMBtu (NYMEX price) and crude oil price of $77.78 per barrel (West Texas Intermediate price). All prices are then further adjusted for transportation, quality and basis differentials.
 
During the year, the Company completed multiple acquisitions which included proved reserves associated with producing properties. Included in the Company's December 31, 2010 proved reserves and classified as 'Purchase of reserves' in the table above, are 643,955 barrels of crude oil attributable to the acquisition.
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 15- SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
 
The following summary sets forth the Company's future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in ASC Topic 932:

 
(In thousands)
 
 
For the Year Ended December 31,
 
 
2010
 
2009 (1)
 
2008 (1)
 
Future oil and gas sales
 
$
51,816
   
$
-
   
$
-
 
Future production costs
   
(11,614
)
   
-
     
-
 
Future development costs
   
(8,063
)
   
-
     
-
 
Future income tax expense
   
-
     
-
     
-
 
                         
Future net cash flows
   
32,139
     
-
     
-
 
10% annual discount
   
(8,544
)
   
-
     
-
 
                         
Standardized measure of discounted future net cash flows (2)
 
$
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 NOLs will be realized within future carryforward 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.


RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
NOTE 15— SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Continued)
 
The principle sources of change in the standardized measure of discounted future net cash flows are:

 
(In thousands)
 
 
For the Year ended December 31,
 
 
2010
 
2009 (1)
 
2008 (1)
 
Balance at beginning of period
 
$
-
   
$
-
   
$
-
 
Sales of oil and gas, net
   
(7,655
)
   
-
     
-
 
Net change in prices and production costs
   
3,084
     
-
     
-
 
Net change in future development costs
   
(4,563
)
   
-
     
-
 
Extensions and discoveries
   
5,067
     
-
     
-
 
Acquisition of reserves
   
18,967
     
-
     
-
 
Sale of reserves
   
-
     
-
     
-
 
Revisions of previous quantity estimates
   
5,245
     
-
     
-
 
Previously estimated development costs incurred
   
-
     
-
     
-
 
Net change in income taxes
   
-
     
-
     
-
 
Accretion of discount
   
2,043
     
-
     
-
 
Other
   
1,407
     
-
     
-
 
Balance at end of period
 
$
23,595
   
$
-
   
$
-
 
                         
(1) Prior to January 2010, the Company did not own any oil and gas assets
 
 
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.
 
 
 

RECOVERY ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

   
March 31,
   
December 31,
 
   
2011
   
2010
 
Assets
Current Assets
           
Cash
 
$
2,111,340
   
$
5,528,744
 
Restricted cash
   
1,998,821
     
1,150,541
 
Accounts receivable
   
1,645,985
     
857,554
 
Prepaid assets
   
167,682
     
27,772
 
Total current assets
   
5,923,828
     
7,564,611
 
                 
Oil and gas properties (full cost method), at cost:
               
Undeveloped properties
   
48,530,863
     
33,605,594
 
Developed properties
   
27,779,396
     
26,307,975
 
Wells in progress
   
2,041,787
     
1,219,397
 
Total oil and gas properties
   
78,352,046
     
61,132,966
 
                 
Less accumulated depreciation, depletion and amortization
   
(6,062,443
)
   
(5,008,606
)
Net oil and gas properties
   
72,289,603
     
56,124,360
 
                 
Other assets
               
Office equipment, net
   
57,517
     
56,236
 
Prepaid advisory fees
   
878,127
     
979,449
 
Deferred financing costs, net
   
4,485,429
     
3,211,566
 
Restricted cash and deposits
   
185,776
     
185,707
 
Total other assets
   
5,606,849
     
4,432,958
 
                 
TOTAL ASSETS
 
$
83,820,280
   
$
68,121,929
 
 
The accompanying notes are an integral part of these consolidated financial statements
 
 
 

RECOVERY ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

 
   
March 31,
   
December 31,
 
   
2011
   
2010
 
Liabilities and Shareholders' Equity
Current Liabilities
           
Accounts payable
 
$
1,095,247
   
$
968,295
 
Liabilities from price risk management
   
876,752
     
398,840
 
Related party payable
   
12,955
     
11,638
 
Accrued expenses
   
1,370,857
     
1,540,592
 
Short term note payable
   
270,410
     
208,881
 
Total current liabilities
   
3,626,221
     
3,128,246
 
                 
Asset retirement obligation
   
529,506
     
507,280
 
Term note payable
   
19,773,173
     
20,229,801
 
Convertible notes payable, net of discount
   
5,712,057
     
-
 
    Derivative liability
   
 2,783,000
     
 -
 
Total long term liabilities
   
28,797,736
     
20,737,081
 
                 
Total liabilities
   
32,423,957
     
23,865,327
 
 Commitments and Contingencies – Note 7
               
                 
Common Stock Subject to Redemption Rights, $0.0001 par value; 0 and 42,500 shares issued and outstanding as of March 31, 2011 and December 31, 2010, respectively
   
-
     
86,258
 
                 
Shareholders’ Equity
               
     Common stock, $0.0001 par value: 100,000,000 shares authorized;
               
62,483,758 and 57,814,369 shares issued and outstanding (excluding 0 and 42,500 shares subject to redemption) as of March 31, 2011 and December 31, 2010, respectively
   
6,248
     
5,781
 
     Additional paid in capital
   
101,830,226
     
90,861,527
 
     Accumulated deficit
   
(50,440,151
)
   
(46,696,964
)
Total other shareholders' equity
   
51,396,323
     
44,170,344
 
                 
TOTAL LIABILITIES, COMMON STOCK SUBJECT TO REDEMPTION RIGHTS AND SHAREHOLDERS’ EQUITY
 
$
83,820,280
   
$
68,121,929
 
 
The accompanying notes are an integral part of these consolidated financial statements
 
 
 
 RECOVERY ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
       
   
Three Months Ended
March 31,
 
   
2011
   
2010
 
             
Revenue
           
Oil sales
 
$
1,801,814
   
$
622,595
 
Gas sales
   
108,829
     
-
 
Operating fees
   
8,228
     
1,125
 
Realized loss on hedges
   
(167,284
)
   
-
 
Price risk management activities
   
(477,912
)
   
(133,369
)
                 
Total revenues
   
1,273,675
     
490,351
 
                 
Costs and expenses
               
Production costs
   
446,985
     
121,877
 
Production taxes
   
202,299
     
35,488
 
   General and administrative (includes non-cash expense of $0.7 million and $1.9 million , respectively)
   
1,600,594
     
2,343,321
 
Depreciation, depletion, amortization and accretion
   
1,075,930
     
231,917
 
                 
Total costs and expenses
   
3,325,808
     
2,732,603
 
                 
Loss from operations
   
(2,052,133
)
   
(2,242,252
)
                 
Unrealized gain on lock-up
   
1,115
     
15,209
 
    Interest expense and financing costs (includes non-cash expense of $0.8 million and  $0.5 million, respectively)
   
(1,692,169
)
   
(593,672
)
                 
Net loss
 
$
(3,743,187
)
 
$
(2,820,715
)
                 
Net loss per common share
               
Basic and diluted
 
$
(0.06
)
 
$
(0.24
)
                 
Weighted average shares outstanding:
               
Basic and diluted
   
59,112,825
     
11,711,037
 
 
The accompanying notes are an integral part of these consolidated financial statements
 
 
 
RECOVERY ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
   
Three Months Ended
March 31,
 
 
   
2011
   
2010
 
             
Cash flows from operating activities:
           
Net loss
 
$
(3,743,187
)
 
$
(2,820,714
)
Adjustments to reconcile net loss to net cash used in operating activities:
               
    Stock issued for services
   
126,483
     
-
 
    Stock based compensation
   
546,530
     
1,106,437
 
    Changes in the fair value of derivatives
   
477,912
     
133,369
 
    Compensation expense recognized for assignment of overrides
   
-
     
826,510
 
    Amortization of deferred financing costs
   
837,376
     
466,174
 
    Depreciation, depletion, amortization and accretion
   
1,075,930
     
231,917
 
Changes in operating assets and liabilities:
               
    Accounts receivable
   
(788,431
)
   
(326,561
    Other assets
   
(83,072
)
   
9,908
 
    Accounts payable
   
117,271
     
208,314
 
    Restricted cash
   
(848,280
)
   
(18,561
    Related party payable
   
10,998
     
(56,214
)
    Accrued expenses
   
(169,735)
     
44,089
 
Net cash used in operating activities
   
(2,440,205)
     
(195,332)
 
                 
Cash flows from investing activities:
               
Additions of producing properties and equipment (net of purchase price adjustments)
   
-
     
(48,421
    Acquisition of undeveloped properties
   
(8,416,874
)
   
(10,313,184
    Drilling capital expenditures
   
(2,281,487
)
   
-
 
    Additions of office equipment
   
(13,472
)
   
(501
    Investment in operating bonds
   
(69
)
   
(165
)
Net cash used in investing activities
   
(10,711,902
)
   
(10,362,271
                 
Cash flows from financing activities:
               
    Proceeds from sale of common stock, units and exercise of warrants
   
2,129,801
     
300,000
 
    Proceeds from debt
   
8,000,000
     
10,500,000
 
    Repayment of debt
   
(395,098
)
   
(178,750
Net cash provided by financing activities
   
9,734,703
     
10,621,250
 
                 
Change in cash and cash equivalents
   
(3,417,404
   
63,647
 
Cash and cash equivalents at beginning of period
   
5,528,744
     
108,400
 
                 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
 
$
2,111,340
   
$
172,047
 
 
The accompanying notes are an integral part of these consolidated financial statements 

 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)
 
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Basis of Presentation
 
The accompanying unaudited interim consolidated financial statements were prepared by Recovery Energy, Inc. (“Recovery” or the “Company”) in accordance with generally accepted accounting principles (“GAAP”) in the United States applicable to interim financial statements and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year.  Such financial statements conform to the presentation reflected in the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission (the "SEC") for the year ended December 31, 2010. The current interim period reported herein should be read in conjunction with the financial statements and summary of significant accounting policies and notes included in the Company's Annual Report on Form 10-K for the year ended December 31, 2010. Certain amounts in the 2010 consolidated financial statements have been reclassified to conform to the 2011 consolidated financial statement presentation. Such reclassifications had no effect on net income.

Principles of Consolidation

The accompanying consolidated financial statements include Recovery Energy, Inc. and its wholly-owned subsidiaries Recovery Oil and Gas, LLC, and Recovery Energy Services, LLC.  All intercompany accounts and transactions have been eliminated in consolidation.
 
Use of Estimates
 
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe that our estimates are reasonable. Our most significant financial estimates are associated with our estimated proved oil and gas reserves as well as valuation of common stock used in issuances of common stock, options and warrants and the valuation of the conversion rights related to the convertible notes payable.

Liquidity
 
Since inception, we have raised approximately $72 million in cash generally through private placements of debt and equity securities.  Although we have a flexible capital program for 2011, we cannot give assurances that our current working capital, our cash flow from operations or any available borrowings will be sufficient to fund our anticipated capital expenditures. If our existing and potential sources of liquidity through operating cash flows and cash contributions from joint venture participants are not sufficient to undertake our planned capital expenditures, we may be required to alter our drilling program, pursue additional joint ventures with third parties, sell interests in one or more of our properties or sell equity or debt securities. If we are not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our expenditures, restructure our operations, sell properties on terms which otherwise may not be as favorable and/or curtail our planned exploration and drilling program.
 
 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)
 
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

Restricted Cash

Restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities, and are restricted pursuant to our loan agreements, and certain proceeds from the Company’s convertible notes payable proceeds which are restricted to capital expenditures on certain leasehold interests.
 
Accounts Receivable

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

Concentration of Credit Risk
 
The Company's cash equivalents and short-term investments are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company may at times have balances in excess of the federally insured limits.
 
The Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.

Oil and Gas Producing Activities
 
The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.
 
 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)
 
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

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

The optimal method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Most of the Company's wells have been producing for a period of less than six years and for some, less than a year. Because of this short production history, other generally less accurate methods such as volumetric analysis and analogy to the production history of wells of ours and other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Company's estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Company's wells are produced over time and more data is available, the estimated proved reserves will be re-determined at least on a quarterly basis in accordance with applicable rules established by the SEC and may be adjusted based on that data.

 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

  
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Depletion and Impairment of Proved Oil and Gas Properties
 
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. The cost of acquiring and evaluating unproved properties are initially excluded from depletion calculations. Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated proved reserves. For this purpose, we convert our petroleum products and reserves to a common unit of measure. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues was computed by applying a twelve month average of the first day of the month price of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.
 
There were no impairment charges recognized for the three month periods ended March 31, 2011 and 2010.

Wells in Progress
 
Wells in progress at March 31, 2011 represent the costs associated with wells that have not reached total depth or been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test. The costs for these wells are then transferred to proved property when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods. At March 31, 2011, the Company had commenced drilling on one well and had two wells awaiting completion.
 
Deferred Financing Costs
 
For the three months ended March 31, 2011, the Company recorded deferred financing costs of approximately $2,000,000 related to the extension of its term notes and the closing of its convertible notes. Deferred financing costs include origination (warrants issued and overriding royalty interests assigned to our lender), and legal and engineering fees incurred in connection with the Company's credit facility, which are being amortized over the term of the credit facility. The Company recorded amortization expense of approximately $837,000 for the three months ended March 31, 2011.

Prepaid Advisory Fees
 
The Company had prepaid financial advisory fees of approximately $878,000 as of March 31, 2011.  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 totaling approximately $1,234,000.  The amount is being amortized over the term of the underlying agreement. The Company amortized approximately $101,000 in prepaid fees for the three months ended March 31, 2011.
 
 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

  
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Long-lived Assets
 
The Company accounts for the impairment and disposition of long-lived assets (other than the full cost pool) in accordance with ASC 360, Impairment or Disposal of Long-Lived Assets. ASC 360 requires that the Company’s long-lived assets be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred.  An impairment charge to current operations is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the differences in the carrying value and estimated fair value of the impaired asset.  No impairment was recorded during the three month periods ended March 31, 2011 and 2010.


Fair Value of Financial Instruments

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

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

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

  
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

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

Revenue Recognition
 
The Company records revenues from the sales of natural gas and crude oil when they are produced and sold.
 
Asset Retirement Obligation
 
The Company follows accounting for asset retirement obligations in accordance with ASC 410, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are included in the ceiling test calculation. 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 March 31, 2011, the Company recorded a net asset of $491,562 and a related liability of $529,506.

The information below reconciles the value of the asset retirement obligation for the periods presented:
 
   
For the Three
Months Ended
March 31, 2011
   
For the Year Ended December 31, 2010
 
Balance, beginning of period 
 
$
507,280
   
$
-
 
Liabilities incurred
   
12,324
     
478,208
 
Accretion expense
   
9,902
     
28,042
 
Change in estimate
   
-
     
1,030
 
Balance, end of period
 
$
529,506
   
$
507,280
 

 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

 
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

 Share Based Compensation
 
The Company accounts for share-based compensation in accordance with the provisions of ASC 718— Stock Compensation which requires companies to estimate the fair value of share-based payment 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.  We estimate the fair value of each share-based award using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards and the estimated volatility of our stock price.

Loss per Common Share
 
Basic earnings (loss) per share is computed based on the weighted average number of common shares outstanding during the period presented. In addition to common shares outstanding, and in accordance with ASC 260 – Earnings per share, diluted loss per share is computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares had been issued. Potentially dilutive securities, such as stock grants and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive. For the period ended March 31, 2011, outstanding warrants of 22,555,600 have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. Accordingly, basic shares equal diluted shares for all periods presented.
 
NOTE 2 – OIL AND GAS PROPERTIES

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

 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

  
NOTE 3 – WELLS IN PROGRESS
 
The following table reflects the net changes in capitalized additions to wells in progress for the periods presented, and includes amounts that were capitalized and reclassified to proved properties in the same period.
 
   
For the Three Months Ended March 31, 2011
   
For the Year Ended December 31, 2010
 
Balance, beginning of period 
 
$
1,219,397
   
$
-
 
Additions to wells in progress
   
2,202,438
     
2,750,499
 
Reclassifications to proved properties
   
(1,380,048
   
(1,531,102
)
Balance, end of period
 
$
2,041,787
   
$
1,219,397
 
 
NOTE 4 - FINANCIAL INSTRUMENTS AND DERIVATIVES

During 2011 and 2010, the Company has entered into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices.  As of March 31, 2011, the Company had commodity swaps for the following oil volumes:

   
Barrels per
   
Barrels per
   
Price per
 
quarter
Day
Barrel
2011
                       
Second quarter
   
9,900
     
110
   
$
85.97
 
Third quarter
   
9,900
     
110
   
$
84.95
 
Fourth quarter
   
16,000
     
178
   
$
91.15
 
                         
2012
                       
First quarter
   
9,100
     
101
   
$
101.2
0
Second quarter
   
9,100
     
101
   
$
101.2
0
Third quarter
   
9,200
     
102
   
$
101.2
0
Fourth quarter
   
3,100
     
100
   
$
101.2
0
 
The amount of gain (loss) recognized in income related to our derivative financial instruments was as follows:
 
   
For the Three Months Ended March 31,
 
   
2011
   
2010
 
Realized loss on oil contracts
 
$
(167,284
)
 
$
-
 
Loss on commodity price risk management activities
 
$
( 477,912
)
 
$
(133,369
)
 
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 risk management activities line on the consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of operations.
 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

 
NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company records certain of its assets and liabilities on the balance sheet at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:
 
 
Level 1
Quoted prices (unadjusted) for identical assets or liabilities in active markets.
       
 
Level 2
Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable.
       
 
Level 3
Unobservable inputs that reflect the Company’s own assumptions.

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

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 March 31, 2011, 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.

 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

  
 NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

The following table provides a summary of the fair values of assets and liabilities measured at fair value:
 
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Liability
                       
Derivative Liability
 
$
   
$
   
$
 (2,783,000
)
 
$
 (2,783,000
)
Commodity swap contracts
 
$
   
$
(876,752
 
$
   
$
(876,752
)
Total liability at fair value
 
$
   
$
(876,752
 
$
(2,783,000
)
 
$
(3,659,752
 
The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three months ended March 31, 2011.

At March 31, 2011, the Company’s commodity swap contracts were held with a single counterparty. The Company continually reviews the credit-worthiness of its counterparties. The Company’s derivative instruments are part of master netting agreements, which reduces credit risk by permitting the Company to net settle for transactions with the same counterparty. The Company's derivative liability relates to certain variable conversion rights issued in connection with the Company's convertible notes.
 
The Company used level 3 inputs to estimate the fair value of common stock used in the acquisition of unproved oil and gas properties during the quarter ended.
 
NOTE 6 - LOAN AGREEMENTS

Term Notes

The Company entered into three separate loan agreements with Hexagon Investments, LLC (“Hexagon”) during the 2010.  All three loans bear annual interest of 15% and mature on September 1, 2012.  

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 cash flows 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 1 million warrants with an exercise price of $1.50 per share. The loan modification agreements required the Company to issue 1 million five year warrants to purchase common stock at $1.50 per share to Hexagon if the Company did not repay the loans in full by January 1, 2011.  

In December 2010, Hexagon extended the maturity to September 1, 2012.
 
 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

  
NOTE 6 – LOAN AGREEMENTS (Continued)

Since the loans were not paid in full by January 1, 2011, the Company issued 1,000,000 additional warrants with an exercise price of $1.50 per share to Hexagon which was valued at approximately $1,600,000, and is being amortized over the remaining term of the loan.

The Company is subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements. As of March 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 issued in a private placement $8,400,000 aggregate principal amount of three year 8% Senior Secured Convertible Debentures with a group of accredited investors, who are existing shareholders of the Company. Of the proceeds from the sale, $3,000,000 is restricted to acquisition of and drilling activities on specified properties, which were pledged as collateral for the Debentures. The balance of the proceeds are to be used by the Company for working capital. The Debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $2.35 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 calculated the fair value of the conversion feature to be approximately $2,787,000. This amount has been estimated by Management and been accounted for as a discount to the note payable and will be accreted on a straight line basis over the life of the convertible notes payable. During the second quarter the Company intends to have a third party review of its estimate of the fair value of this conversion right and it is likely this estimate may change. Management does not believe any change, however, will be material to its financial position or results of operations. As the conversion adjustment qualifies the instrument as a derivative, the offset was recorded as a derivative liability and will be adjusted quarterly based on its fair value. Any gains or losses on this liability will be recorded within the Statement of Operations. The fair value adjustment between the date of issuance and March 31, 2011 was not significant.

Interest Expense

For the three months ended March 31, 2011, the Company incurred interest expense of approximately $1,692,000, of which approximately $837,000 was non-cash interest expense related to the amortization of the deferred financing costs, and accretion of the convertible notes payable discount.
 
 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

 
NOTE 7 - COMMITMENTS and CONTINGENCIES

Environmental and Governmental Regulation

At March 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 March 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 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 chief financial officer were no longer entitled to stock grants based on market capitalization milestones.
 
No shares were issued under these agreements; however the Company recorded approximately $200,000 of expense during the three months ended March 31, 2010.

 
 
 
RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)


NOTE 8 - SHAREHOLDERS’ EQUITY

Common Stock

As of March 31, 2011, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 62,483,758 of common shares were issued and outstanding.  No preferred shares were issued or outstanding.  

During the three months ended March 31, 2011, the Company issued 4,626,889 shares of common stock.  The stock issuances were comprised of 2,698,556 shares issued for acquisitions valued at $6,508,395, 40,000 shares issued for services valued at $82,000, 387,000 shares issued as restricted stock grants to employees valued at $1,064,250, and 1,501,333 shares issued in connection with warrant exercises for $2,903,794 of cash.
 
Temporary Equity

As part of the reverse merger in 2009, 85,000 shares of common stock were issued and outstanding under a lock-up agreement that has terms which may result in the Company reacquiring the shares due to circumstances outside of the Company’s control and therefore the shares are preferential to common shares.  The 85,000 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 42,500 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 42,500 shares covered under the lock-up agreement were moved to permanent on equity.

Warrants

On January 1, 2011, the Company issued 1 million warrants with an exercise price of $1.50 per share to Hexagon which was valued at approximately $1,600,000.

 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

  
NOTE 9 - SHARE BASED COMPENSATION

The Company has not adopted a stock incentive plan for its management team.  Each member of the board of directors and the management team was awarded restricted stock grants in their respective appointment or employment agreements.

The Company accounts for stock based compensation arrangements in accordance with the provisions of ASC 718 Compensation – Stock Compensation.  ASC 718 requires measurement and recording to the financial statements of the costs of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, recognized over the period during which an employee is required to provide services in exchange for such award. The Company implemented ASC 718 effective March 6, 2009.

During the three months ended March 31, 2011, the Company granted 387,000 shares of restricted common stock to employees of which 54,000, 116,500, 141,500, and 75,000 shares vest during the years ended December 31, 2011, 2012, 2013, and 2014, respectively. The fair value of these share grants was calculated to be approximately $1,064,000.

The Company recognized stock compensation expense of approximately $546,000 and $906,000 for the three months ended March 31, 2011 and 2010, respectively.
 
A summary of restricted stock grant activity for the three months ended March 31, 2011, and the year ended December 31, 2010 is presented below:
 
   
Shares
 
Balance outstanding at January 1, 2010
   
1,484,200
 
Granted
   
7,458,987
 
Vested
   
-
 
Balance outstanding at December 31, 2010
   
8,943,187
 
Granted
   
387,000
 
Vested
   
(175,000
Balance outstanding at March 31, 2011
   
9,155,187
 
 
Total unrecognized compensation cost related to non-vested stock granted was $1,820,443 as of March 31, 2011. The cost at March 31, 2011 is expected to be recognized over a weighted-average remaining service period of 0.23 years.
 
 
 

RECOVERY ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF MARCH 31, 2011
(UNAUDITED)

  
NOTE 10 – SUBSEQUENT EVENTS

On April 11, 2011, our president and chief financial officer resigned. In connection with his resignation the Company entered into a separation agreement with him pursuant to which he will receive as severance one year's base salary of $225,000, a bonus for 2010 in the same amount, if any, paid to our chief executive officer, as determined by our compensation committee of the board of directors in its sole discretion, and will retain his 1,925,000 unvested shares of our common stock, which will vest in four equal installments of 481,250 shares quarterly commencing July 15, 2011.

 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Shareholders of Recovery Energy, Inc.:
 
We have audited the accompanying statements of operations, members’ capital and cash flows of the Wilke Field Acquisition Properties for the year ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on theses financial statements based on our audit.
 
We conducted our audit 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 statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statements presentation. We believe that our audit provides a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above presents fairly, in all material respects, the results of operations and cash flows of the Wilke Field Acquisition Properties, for the year ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
 
/s/ Hein & Associates LLP
Denver, Colorado
June 1, 2011
 

WILKE FIELD ACQUISITION PROPERTIES

STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2009
 
Revenue:
     
Oil and gas sales
  $ 4,671,274  
         
Costs and Expenses:
       
Production taxes
    267,818  
Lease operating expense
    453,176  
Depreciation, depletion and amortization
    2,705,953  
         
Allocated general and administrative
    251,000  
Total costs and expenses
    3,677,947  
         
net income
    993,327  
         
Pro Forma Income Taxes (unaudited)
    398,324  
         
Pro Forma Net Income (unaudited)
  $ 595,003  
 
The accompany notes are an integral part of these financial statements
 

WILKE FIELD ACQUISITION PROPERTIES

STATEMENT OF MEMBER’S CAPITAL

FOR THE YEAR ENDED DECEMBER 31, 2009
 
Balance, January 1, 2009
  $ 2,960,920  
         
Capital contribution
    -  
Distributions
    (2,824,036 )
Net income
    993,327  
         
Balance, December 31, 2009
  $ 1,130,211  
 
The accompany notes are an integral part of these financial statements
 
 

WILKE FIELD ACQUISITION PROPERTIES

STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2009
 
       
Cash Flows from Operating Activities:
     
Net income
  $ 993,327  
Adjustments to reconcile net income to net cash provided by operating activities:
       
Depreciation, depletion and amortization
    2,690,188  
Accretion of asset retirement obligation
    15,765  
Changes in operating assets and liabilities:
       
Accounts receivable
    145,495  
Accounts payable and accrued expenses
    15,313  
         
Net cash provided by operating activities
    3,860,088  
Cash Flows from Investing Activities:
       
Capital expenditures
    (1,036,052 )
         
Net cash used in investing activities
    (1,036,052 )
Cash Flows from Financing Activities:
       
Distributions
    (2,824,036 )
         
Net cash used in financing activities
    (2,824,036 )
         
Increase (Decrease) in Cash
    -  
Cash, beginning of year
    -  
Cash, end of year
  $ -  
 
The accompany notes are an integral part of these financial statements
 

WILKE FIELD ACQUISITION PROPERTIES
NOTES TO FINANCIAL STATEMENTS

1. Basis Of Presentation:
 
In January 2010, Recovery Energy, Inc. (the “Company”) acquired the Wilke Field oil and gas properties (the “Wilke Field Acquisition Properties”) from Edward Mike Davis, L.L.C. (the “Seller”) for approximately $4,500,000.  These historical financial statements, which include statement of operations, member’s capital and cash flows, were required under Rule 3-05 of the Securities and Exchange Commission (“SEC”) Regulation S-X.
 
The Wilke Field Acquisition Properties were operated by the Seller along with several other oil and gas properties and other personal interests as a limited liability company.  The Company with the assistance of the Seller have “carved out” such interests and have presented the related operations for 2009 on a stand-alone basis.  The related assets and liabilities of the properties have previously been included with the Company in its filings with the SEC and are therefore not included herein.
 
The Wilke Field Acquisition Properties on a stand-alone basis have no specific general and administrative costs or income taxes.  The Company, with the assistance of the Seller, has estimated related overhead costs at $251,000 and reflected those costs as charges to allocated general and administrative expense in the statement of operations with a corresponding credit to contributed capital.
 
As the Wilke Field Acquisition Properties were included in the Seller’s personal tax return along with the Seller’s other interests, specific taxes cannot be allocated to the properties.  The Company, as a taxable C corporation, has included pro forma income taxes on a stand-alone basis as if such properties were taxed as a C corporation.
 
Fair Value of Financial Instruments
 
The acquired financial instruments, including accounts receivable and payable, are carried at cost, which approximates their fair value because of the short-term maturity of these instruments.
 
Concentration of Credit Risk
 
Substantially all of the acquired receivables are within the oil and gas industry, primarily from the sale of oil and gas.  Collectability is dependent upon the general economic conditions of the industry.  Most of the receivables are not collateralized and, to date, the Company has not had any bad debts.
 
 
 
WILKE FIELD ACQUISITION PROPERTIES
NOTES TO FINANCIAL STATEMENTS


1. Basis Of Presentation: (Continued)

Oil and Gas Producing Activities

The Wilke Field Acquisition Properties follow the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool").  Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition and exploration activities.  Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves.  Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs.  The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties.  The properties are reviewed quarterly for impairment.  When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

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

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.
 
 
 
WILKE FIELD ACQUISITION PROPERTIES
NOTES TO FINANCIAL STATEMENTS

1. Basis Of Presentation: (Continued)

The optimal method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data.  The accuracy of the decline analysis method generally increases with the length of the production history.  Most of the Wilke Field Acquisition Properties’ wells have been producing for a period of less than six years and, for some, less than a year.  Because of this short production history, other generally less accurate methods such as volumetric analysis and analogy to the production history of wells of ours and other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Wilke Field Acquisition Properties’ estimates of proved reserves including developed producing, developed non-producing and undeveloped.  As the Wilke Field Acquisition Properties’ wells are produced over time and more data is available, the estimated proved reserves will be re-determined at least on a quarterly basis in accordance with applicable rules established by the SEC and may be adjusted based on that data.

Depletion and Impairment of Proved Oil and Gas Properties

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.  The cost of acquiring and evaluating unproved properties are initially excluded from depletion calculations.  Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves.  For this purpose, we convert our petroleum products and reserves to a common unit of measure.  For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil.  Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization.  Should capitalized costs exceed this ceiling, impairment is recognized.  The present value of estimated future net revenues was computed by applying a twelve month average of the first day of the month price of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.
 
There was no impairment recognized for the year ended December 31, 2009.

Impairment of Unproved Oil and Gas Properties

The Wilke Field Acquisition Properties’ unproved properties are evaluated quarterly for the possibility of potential impairment.  For the year ended December 31, 2009, no impairment was recorded.
 
 
 
WILKE FIELD ACQUISITION PROPERTIES
NOTES TO FINANCIAL STATEMENTS

1. Basis Of Presentation: (Continued)

Wells in Progress

Wells in progress represent the costs associated with wells that have not reached total depth or been completed as of year end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test.  The costs for these wells are transferred to proved properties when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods. As of December 31, 2009, there were no wells in progress.

Abandonment Liability

The Wilke Field Acquisition Properties follow the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.”  This Statement generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires recognition of the fair value of asset retirement obligations in the financial statements by capitalizing that cost as a part of the cost of the related asset. In regards to the Wilke Field Acquisition Properties, this Statement applies directly to the plug and abandonment liabilities associated with the net working interest in the well bores. The additional carrying amount is depleted over the estimated lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and is accreted at the end of each accounting period through charges to operations. During the year ended December 31, 2009, accretion expense was $15,765. There were no other changes to the abandonment liability.

Revenue Recognition

The Wilke Field Acquisition Properties recognize oil and gas revenues for the portion of production that pertains to its ownership percentage under the entitlement method.  Purchase, sale and transportation of natural gas are recognized upon completion of the sale and when transported volumes are delivered according to the terms of the contract.

Income Taxes

The Wilke Field Acquisition Properties consist of oil and gas properties.  As such, they are not subject to income taxes as their income or loss is required to be included in the income tax returns of Edward Mike Davis, L.L.C. For financial presentation purposes, pro forma income tax expense has been calculated on the statement of operations using an effective tax rate of 40.1%.

Use of Estimates and Certain Significant Estimates

The preparation of the Wilke Field Acquisition Properties financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes.  Actual results could differ from those estimates.  These estimates include realizability of receivables, selection of the useful lives for property and equipment, timing and costs associated with its retirement obligations and general and administrative expenses related to the properties.  Significant assumptions are also required in the valuation of proved oil and gas reserves, which will affect the depletion calculation and possibly any impairment of oil and gas properties.  It is at least reasonably possible those estimates could be revised in the near term and those revisions could be material.
 
 
 
WILKE FIELD ACQUISITION PROPERTIES
NOTES TO FINANCIAL STATEMENTS

2. Commitments and Contingencies:
 
Pursuant to the terms of the Purchase and Sale Agreement between the Seller and the Company, there were no claims, litigation or disputes pending as of the effective date of the Purchase and Sale Agreement, or any matters arising in connection with indemnification, and the Seller is not aware of any legal, environmental or other commitments or contingencies that would have a material adverse effect.

Environmental Issues

The Company is engaged in oil and gas exploration and production of the Wilke Field Acquisition Properties and may become subject to certain liabilities as they relate to environmental clean up of well sites or other environmental restoration procedures as they relate to the drilling of oil and gas wells and the operation thereof.  Acquisition of existing or previously drilled well bores, the Wilke Field Acquisition Properties may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated.  Should it be determined that a liability exists with respect to any environmental clean up or restoration, the liability to cure such a violation could fall upon the Company.  Management believes its properties are operated in conformity with local state and Federal regulations.  No claim has been made, nor is the Company aware of any uninsured liability that it may have, as it relates to any environmental clean up, restoration or the violation of any rules or regulations relating thereto.

Other

The Wilke Acquisition Properties have no lease obligation, including office.  Reflected in allocated general and administrative expenses is $10,000 of estimated office expense associated with the properties.

3. Oil & Gas Activities:

The acquired Company oil and natural gas activities are entirely within the United States.  Costs incurred in oil and natural gas producing activities are as follows:
 
Unproved property acquisition
  $  
Proved property acquisition
     
Development
     
Exploration
    1,036,052  
         
Total
  $ 1,036,052  

During 2009, additions to oil and gas properties of approximately $197,000 were recorded for the estimated costs of future abandonment related to new wells drilled or acquired.
 
 
 
WILKE FIELD ACQUISITION PROPERTIES
NOTES TO FINANCIAL STATEMENTS
 
4. Supplemental Disclosures of Oil and Gas Producing Activities (unaudited):
 
Reserve Quantities – The following table summarizes the estimated quantities of proved oil and gas reserves of the Wilke Field Acquisition Properties. These amounts were derived from reserve estimates prepared by management. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The oil and gas reserves stated below are attributable solely to properties within the United States.
 
   
Oil
(Bbl)
 
       
Balance – January 1, 2009
   
139,031
 
         
Production
   
(101,087
)
Extensions and discoveries
   
4,809
 
Revisions to previous quantity estimate
   
639
 
         
Balance – December 31, 2009
   
43,392
 
         
Proved developed reserves:
       
December 31, 2009
   
43,392
 
 
 
 
WILKE FIELD ACQUISITION PROPERTIES
NOTES TO FINANCIAL STATEMENTS
 
4. Supplemental Disclosures of Oil and Gas Producing Activities (Unaudited) (Continued):
Standardized Measure of Discounted Future Net Cash Flows – The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with the provisions of ASC 932. Future cash inflows were computed by applying a twelve month average of the first day of the month prices with respect to December 31, 2009, to estimated future production, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Wilke Field Acquisition Properties.
 
   
2009
 
Future cash flows
 
$
2,319,000
 
Future production costs
   
(539,000
)
Future development costs
     
Future income tax expense
   
(414,000
)
         
Future net cash flows
   
1,366,000
 
10% annual discount for estimated timing of cash flows
   
(371,000
)
         
Standardized measure of discounted future net cash flows
 
$
995,000
 
 
The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:
 
   
2009
 
Beginning of year
 
$
2,323,000
 
         
Sale of oil and gas produced, net of production costs
   
(3,950,000
)
Net changes in prices and production costs
   
1,167,000
 
Extensions, discoveries and improved recoveries
   
169,000
 
Development costs – net
   
 
Purchases of mineral in place
   
 
Revisions of previous quantity estimates
   
21,000
 
Net change in income taxes
   
774,000
 
Accretion of discount
   
232,000
 
Changes in production rates and other
   
259,000
 
         
End of year
 
$
995,000
 
 
 
 
WILKE FIELD ACQUISITION PROPERTIES
NOTES TO FINANCIAL STATEMENTS
 
4. Supplemental Disclosures of Oil and Gas Producing Activities (Unaudited) (Continued):


The twelve month average of the first day of the month prices for the year ended December 31, 2009, inclusive of adjustments for quality and location used in determining future net revenues, related to the standardized measure calculation was $53.44
 
 
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Shareholders of Recovery Energy, Inc.:
 
We have audited the accompanying statement of revenues and direct operating expenses of the Albin Field Acquisition Properties for the year ended December 31, 2009. This statement of revenues and direct operating expenses is the responsibility of the Company’s management. Our responsibility is to express an opinion on the statement of revenues and direct operating expenses based on our audits.
 
We conducted our audit 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 statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statements presentation. We believe that our audit provides a reasonable basis for our opinion.
 
The accompanying statement of revenues and direct operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission (for inclusion in Recovery Energy, Inc.’s Form 8-K) and is not intended to be a complete financial presentation of the properties revenues and expenses.
 
In our opinion, the statement of revenues and direct operating expenses referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the Albin Field Acquisition Properties, for the year ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

 
/s/ Hein & Associates LLP
Denver, Colorado
August 12, 2010
 
 
ALBIN FIELD ACQUISITION PROPERTIES
 
STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
 
FOR THE YEAR ENDED DECEMBER 31, 2009

 
   
Year Ended December 31, 2009
 
       
Revenues
  $ 1,399,226  
         
Direct Operating Expenses:
       
Lease operating expense
    104,343  
Production taxes
    79,756  
Total direct operating expenses
    184,099  
         
Revenue in excess of direct operating expenses
  $ 1,215,127  
 
See accompanying auditor’s report and notes to the Statements of Revenues and Direct Operating Expenses
 
 
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
FOR THE THREE MONTHS ENDED MARCH 31, 2009 AND 2010

 
   
Three Months Ended March 31, 2009
(Unaudited)
   
Three Months Ended March 31, 2010
(Unaudited)
 
             
Revenues
 
$
91,357
   
$
740,501
 
                 
Direct Operating Expenses:
               
Lease operating expense
   
5,038
     
104,605
 
Production taxes
   
5,207
     
42,209
 
Total direct operating expenses
   
10,245
     
146,814
 
                 
Revenue in excess of direct operating expenses
 
$
81,112
   
$
593,687
 

 
See accompanying auditor’s report and notes to the Statements of Revenues and Direct Operating Expenses
 

NOTES TO THE STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES
 
1. The Properties:
 
In March, 2010, Recovery Energy, Inc. (the “Company”) acquired the Albin Field oil and gas properties from Edward Mike Davis, L.L.C. (the “Seller”) for approximately $6,000,000 and 550,000 shares of the Company’s common stock. The properties are referred to herein as the “Albin Field Acquisition Properties.”
 
2. Basis Of Presentation:
 
The accompanying statements of revenues and direct operating expenses were derived from the historical accounting records of the Seller and reflect the acquired interest in the revenues and direct operating expenses of the properties acquired. Such amounts may not be representative of future operations. The statements do not include depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense as these costs may not be comparable to the expenses expected to be incurred by the Company on a prospective basis.
 
The Company used the sales method to record revenue, where revenue is recognized based on the amount sold to purchasers. Direct operating expenses include payroll, leases and well repairs, production taxes, maintenance, utilities and other direct operating expenses.
 
The process of preparing financial statements in conformity with generally accepted principles requires the use of estimates and assumptions regarding certain types of revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.
 
During the periods presented, the properties acquired were not accounted for or operated as a separate division by the Seller. Certain costs, such as depreciation, depletion and amortization, interest, accretion, and general and administrative expenses were not allocated to the individual properties. Historical financial statements reflecting financial position, results of operations and cash flows required by generally accepted accounting principles are not presented as such information is not readily available on an individual property basis and not meaningful to the oil and gas properties acquired. Accordingly, the historical statements of revenue and direct operating expenses are presented in lieu of the financial statements required under Rule 3-05 of the Securities and Exchange Commission Regulation S-X.
 
The accompanying statements of revenue and direct expenses for the periods ended March 31, 2009 and 2010 have been prepared in accordance with the Securities and Exchange Commission’s accounting guidelines for the preparation of interim financial information. In the opinion of management, the accompanying statements include all adjustments considered necessary to present fairly unaudited revenue and direct expenses for the three months ended March 31, 2009 and 2010. Interim results are not necessarily indicative of the results that may be expected for a full year because of the impact of fluctuations in prices received for oil and other factors.
 
 
 
NOTES TO THE STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES
 
3. Commitments and Contingencies:
 
Pursuant to the terms of the Purchase and Sale Agreement between the Seller and the Company, there are no claims, litigation or disputes pending as of the effective date of the Purchase and Sale Agreement, or any matters arising in connection with indemnification, and the Seller is not aware of any legal, environmental or other commitments or contingencies that would have a material adverse effect on the statements of revenues and direct operating expenses.

 
4. Supplemental Disclosures of Oil and Gas Producing Activities (Unaudited):
 
Reserve Quantities – The following table summarizes the estimated quantities of proved oil and gas reserves of the Albin Field Acquisition Properties. These amounts were derived from reserve estimates prepared by management. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The oil and gas reserves stated below are attributable solely to properties within the United States.

   
Oil
(Bbl)
 
Balance – January 1, 2009
   
-
 
         
Production
   
(24,103
)
Extensions and discoveries
   
43,926
 
Revisions to previous quantity estimate
   
20,793
 
         
Balance – December 31, 2009
   
363,380
 
         
Proved developed reserves:
       
December 31, 2009
   
213,678
 
 
 
NOTES TO THE STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES
 
4. Supplemental Disclosures of Oil and Gas Producing Activities (Unaudited) (Continued):
 
Standardized Measure of Discounted Future Net Cash FlowsThe standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with the provisions of ASC 932. Future cash inflows were computed by applying a twelve month average of the first day of the month prices to estimated future production, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Albin Field Acquisition Properties.
 
   
2009
 
Future cash flows
 
$
16,643,439
 
Future production costs
   
(4,898,703
)
Future development costs
   
(2,500,000
)
Future income tax expense
   
-
 
         
Future net cash flows
   
9,244,736
 
10% annual discount for estimated timing of cash flows
   
(4,063,671
)
         
Standardized measure of discounted future net cash flows
 
$
5,181,065
 
 
The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:
 
   
2009
 
Beginning of year
  $ 3,959,228  
         
Sale of oil and gas produced, net of production costs
    (1,215,127 )
Net changes in prices and production costs
    1,317,388  
Extensions, discoveries and improved recoveries
    1,031,397  
Development costs – net
    (1,000,000 )
Purchases of mineral in place
    -  
Revisions of previous quantity estimates
    451,264  
Net change in income taxes
    -  
Accretion of discount
    546,373  
Changes in production rates and other
    90,542  
         
End of year
  $ 5,181,065  
 
The twelve month average of the first day of the month prices for the year ended December 31, 2009, inclusive of adjustments for quality and location used in determining future net revenues, related to the standardized measure calculation was $45.80.
 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Shareholders of Recovery Energy, Inc.:
 
We have audited the accompanying statement of revenues and direct operating expenses of the State Line Field Acquisition Properties for the three months ended March 31, 2010. This statement of revenues and direct operating expenses is the responsibility of the Company’s management. Our responsibility is to express an opinion on the statement of revenues and direct operating expenses based on our audit.
 
We conducted our audit 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 statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement. 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 audit provides a reasonable basis for our opinion.
 
The accompanying statement of revenues and direct operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission (for inclusion in Recovery Energy, Inc.’s Form 8-K) and is not intended to be a complete financial presentation of the properties revenues and expenses.
 
In our opinion, the statement of revenues and direct operating expenses referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the State Line Field Acquisition Properties, for the three months ended March 31, 2010, in conformity with U.S. generally accepted accounting principles.
 

/s/ Hein & Associates LLP
Denver, Colorado
August 12, 2010
 

 
STATE LINE FIELD ACQUISITION PROPERTIES
 
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
FOR THE THREE MONTHS ENDED MARCH 31, 2010

   
Three Months Ended March 31, 2010
 
       
Revenues
 
$
2,442,915
 
         
Direct Operating Expenses:
       
Lease operating expense
   
166,408
 
Production taxes
   
342,008
 
Total direct operating expenses
   
508,416
 
         
Revenue in excess of direct operating expenses
 
$
1,934,499
 
 
See accompanying auditor’s report and notes to the Statement of Revenues and Direct Operating Expenses

 
NOTES TO THE STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES


1. The Properties:
 
In April, 2010, Recovery Energy, Inc. (the “Company”) acquired the State Line Field oil and gas properties, from Edward Mike Davis, L.L.C. (the “Seller”) for approximately $15,000,000 and 2,500,000 shares of the Company’s common stock. The properties are referred to herein as the “State Line Field Acquisition Properties.” The acquisition was comprised of six wells and 1,240 undeveloped acres. As the wells were drilled in 2010, there was no related production during 2009.
 
2. Basis Of Presentation:
 
The accompanying statements of revenues and direct operating expenses were derived from the historical accounting records of the Seller and reflect the acquired interest in the revenues and direct operating expenses of the properties acquired. Such amounts may not be representative of future operations. The statements do not include depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense as these costs may not be comparable to the expenses expected to be incurred by the Company on a prospective basis.
 
The Company used the sales method to record revenue, where revenue is recognized based on the amount sold to purchasers. Direct operating expenses include payroll, leases and well repairs, production taxes, maintenance, utilities and other direct operating expenses.
 
The process of preparing financial statements in conformity with generally accepted principles requires the use of estimates and assumptions regarding certain types of revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.
 
During the periods presented, the properties acquired were not accounted for or operated as a separate division by the Seller. Certain costs, such as depreciation, depletion and amortization, interest, accretion, and general and administrative expenses were not allocated to the individual properties. Historical financial statements reflecting financial position, results of operations and cash flows required by generally accepted accounting principles are not presented as such information is not readily available on an individual property basis and not meaningful to the oil and gas properties acquired. Accordingly, the historical statements of revenue and direct operating expenses are presented in lieu of the financial statements required under Rule 3-05 of the Securities and Exchange Commission Regulation S-X.
 
3. Commitments and Contingencies:
 
Pursuant to the terms of the Purchase and Sale Agreement between the Seller and the Company, there are no claims, litigation or disputes pending as of the effective date of the Purchase and Sale Agreement, or any matters arising in connection with indemnification, and the Seller is not aware of any legal, environmental or other commitments or contingencies that would have a material adverse effect on the statements of revenues and direct operating expenses.
 
 
NOTES TO THE STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES
 
 
4. Supplemental Disclosures of Oil and Gas Producing Activities (Unaudited):
 
Reserve Quantities – The following table summarizes the estimated quantities of proved oil and gas reserves of the State Line Field Acquisition Properties. These amounts were derived from reserve estimates prepared by management. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The oil and gas reserves stated below are attributable solely to properties within the United States.
 
   
Oil
(Bbl)
 
       
Balance – January 1, 2010
   
-
 
         
Production
   
(32,570
)
Extensions and discoveries
   
231,506
 
Revisions to previous quantity estimate
   
-
 
         
Balance – December 31, 2009
   
198,936
 
         
Proved developed reserves:
       
March 31, 2010
   
198,936
 
 
Standardized Measure of Discounted Future Net Cash Flows – The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with the provisions of ASC 932. Future cash inflows were computed by applying prices using a twelve month average of the first day of the month to estimated future production, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the State Line Field Acquisition Properties.
 
 
NOTES TO THE STATEMENTS OF REVENUES
AND DIRECT OPERATING EXPENSES
 
4. Supplemental Disclosures of Oil and Gas Producing Activities (Unaudited) (Continued):
 
   
2010
 
       
Future cash flows
 
$
12,583,192
 
Future production costs
   
(2,949,655
)
Future development costs
   
-
 
Future income tax expense
   
-
 
         
Future net cash flows
   
9,633,537
 
10% annual discount for estimated timing of cash flows
   
(3,062,165
)
         
Standardized measure of discounted future net cash flows
 
$
6,571,372
 
 
The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:
 
   
2010
 
       
       
Beginning of year
 
$
-
 
         
Sale of oil and gas produced, net of production costs
   
(1,934,499
)
Net changes in prices and production costs
   
-
 
Extensions, discoveries and improved recoveries
   
8,505,871
 
Development costs – net
   
-
 
Purchases of mineral in place
   
-
 
Revisions of previous quantity estimates
   
-
 
Net change in income taxes
   
-
 
Accretion of discount
   
-
 
Changes in production rates and other
   
-
 
         
End of year
 
$
6,571,372
 
 
The average of the first day of the previous twelve months wellhead prices in effect at March 31, 2010, inclusive of adjustments for quality and location used in determining future net revenues, related to the standardized measure calculation is as follows:
 
   
2010
 
       
Oil (per Bbl)
 
$
63.25
 

 
 
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
 
$
6,766
 
Legal Fees and Expenses
 
$
75,000
 
Accounting Fees and Expenses
 
$
10,000
 
Miscellaneous
 
$
8,234
 
Total:
 
$
90,000
 
 
Item 14. Indemnification of directors and officers.
 
Section 5.1 of Article V of our bylaws provides for indemnification of our directors and officers against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with which action, suit or proceeding, if such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of Recovery Energy and, with respect to any criminal action or proceeding, had no reasonable cause to believe such conduct was unlawful. The termination of any action, suite or proceeding by judgment, order, settlement, conviction or upon plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the person did not act in good faith and in a manner which such person reasonably believed to be in or not opposed to be the best interests of Recovery Energy and, with respect to any criminal action or proceeding, that such person had reasonable cause to believe that such conduct was unlawful.
 
Section 5.2 of Article V of our bylaws provides for indemnification of our directors and officers against expenses (including attorney's fees) actually and reasonably incurred by him in connection with the defense or settlement of such action or suit, if such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of Recovery Energy, except that 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 Recovery Energy 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.
 
Subsection 1 of Section 78.7502 of Chapter 78 of the Nevada Revised Statutes provides that a corporation may 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 in an action brought by or on behalf of the corporation) if that 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 or enterprise, against expenses, including attorneys' fees, judgments, fines and amounts paid in settlement actually and reasonably incurred by that person in connection with such action, suit or proceeding, if that person acted in good faith and in a manner which that person reasonably believed to be in, or not opposed to, the best interests of the corporation, and, with respect to any criminal action or proceedings, had no reasonable cause to believe his 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, alone, does not create a presumption that the person did not act in good faith and in a manner which the person reasonably believed to be in, or not opposed to, the best interests of the corporation, and that, with respect to any criminal action or proceeding, the person had reasonable cause to believe his action was unlawful.
 
Subsection 2 of Section 78.7502 of the Nevada Revised Statutes provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit brought by or on behalf of the corporation to procure a judgment in its favor because the person acted in any of the capacities set forth above, against expenses, including amounts paid in settlement and attorneys' fees, actually and reasonably incurred by that person in connection with the defense or settlement of such action or suit, if the person acted in accordance with the standard set forth above, except that no indemnification may be made in respect of any claim, issue or matter as to which such person shall have 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 such action or suit was brought or other court of competent jurisdiction determines 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.
 
 

 
Subsection 3 of Section 78.7502 of the Nevada Revised Statutes further provides that, to the extent a director or officer of a corporation has been successful on the merits or otherwise in the defense of any action, suit or proceeding referred to in subsections 1 and 2 thereof, or in the defense of any claim, issue or matter therein, that person shall be indemnified by the corporation against expenses (including attorneys' fees) actually and reasonably incurred by that person in connection therewith.
 
Section 78.751 of the Nevada Revised Statutes provides that unless indemnification is ordered by a court, the determination to provide indemnification must be made by the stockholders, by a majority vote of a quorum of the board of directors who were not parties to the action, suit or proceeding, or in specified circumstances by independent legal counsel in a written opinion. In addition, the articles of incorporation, bylaws or an agreement made by the corporation may provide for the payment of the expenses of a director or officer of the expenses of defending an action as incurred upon receipt of an undertaking to repay the amount if it is ultimately determined by a court of competent jurisdiction that the person is not entitled to indemnification.
 
Section 78.751 of the Nevada Revised Statutes further provides that the indemnification provided for therein shall not be deemed exclusive of any other rights to which the indemnified party may be entitled and that the scope of indemnification shall continue as to directors, officers, employees or agents who have ceased to hold such positions, and to their heirs, executors and administrators.
 
Finally, Section 78.752 of the Nevada Revised Statutes provides that a corporation may purchase and maintain insurance on behalf of a director, officer, employee or agent of the corporation against any liability asserted against him or incurred by him in any such capacity or arising out of his status as such whether or not the corporation would have the authority to indemnify him against such liabilities and expenses.
 
Item 15.  Recent Sales of Unregistered Securities
 
Private placements for cash
 
In November, 2009 we sold an aggregate of 125,000 shares of our common stock to one accredited investors (as defined in Regulation D) for $4.00 per share resulting in proceeds of $500,000 to us.
 
In January, 2010 we sold an aggregate of 88,889 shares of our common stock to one accredited investors (as defined in Regulation D) for $2.25 per share resulting in proceeds of $200,000 to us.
 
In March, 2010 we issued 44,445 shares of our common stock to one accredited investor (as defined in Regulation D) for $2.25 per share resulting in proceeds of $100,000 to us.
 
In April, 2010 we issued 333,333 shares of our common stock to one accredited investor (as defined in Regulation D) for $0.75 per share resulting in proceeds of $250,000 to us.
 
In May, 2010 we completed a private placement to 32 accredited investors (as defined in Regulation D) of 1,058,486 shares of our common stock at $0.75 per share resulting in gross proceeds to us of $793,732. We paid three placement agents, a combined commission of $26,158.
 
In June, 2010 we completed a private placement to 36 accredited investors (as defined in Regulation D) of units consisting of 15,901,200 shares of our common stock and five-year warrants to purchase 15,901,200 shares of our common stock at $1.50 per share. The units were priced at $1.50 resulting in gross proceeds to us of $23,851,800. We paid T.R. Winston & Company, LLC, the placement agent, a commission of 8% of the gross proceeds from the sale (not including the shares purchased by T.R. Winston described below) and an immediately exercisable five-year warrant to purchase 2,355,733 shares of common stock for $1.50 per share. In addition, T.R. Winston will also receive 8% of the proceeds paid to us upon exercise of the warrants issued to the purchasers in the private placement. T.R. Winston also purchased 1,177,867 of the shares and received warrants to purchase 1,177,867 shares of common stock from its fees in connection with the private placement.
 
In September, 2010 we issued 3,414,000 shares of our common stock upon the exercise of outstanding warrants to purchase our common stock at $1.50 per share resulting in proceeds of $5,121,000 to us. The exercising warrant holders received new five-year $2.20 warrants, exercisable immediately, for the same number of shares as they purchased through exercise of their $1.50 warrants.
 
 
In February, 2011 we completed a private placement to 4 accredited investors (as defined in Regulation D) of $8,000,000 three year 8% senior secured convertible debentures. The debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $2.35 per share, subject to adjustment. T.R. Winston & Company, LLC, the placement agent, received compensation in the form of debentures with an aggregate principal amount equal to 5% of the gross proceeds from the sale.

In March and April, 2011 we issued 1,151,331 shares of our common stock upon the exercise of outstanding warrants to purchase our common stock at $1.50 per share and 1,151,331 shares of our common stock upon the exercise of outstanding warrants to purchase our common stock at $2.20 per share, resulting in proceeds of $1,790,001 to us.
 
Shares issued in connection with acquisitions of oil and gas properties
 
In November, 2009 we issued 250,000 shares of our common stock to Edward Mike Davis, L.L.C., the seller of oil and gas properties we acquired as described in our current report on form 8-K filed on November 12, 2009. These shares were repurchased from the seller in January, 2010 for $750,000 pursuant to a put option exercised by the seller.
 
In December, 2009 we issued 1,450,000 shares of our common stock to Edward Mike Davis, L.L.C., the seller of oil and gas properties we attempted to acquire as described in our current report on form 8-K filed on December 9, 2009.
 
In March, 2010 we issued 550,000 shares of our common stock to Edward Mike Davis, L.L.C., the seller of oil and gas properties we acquired as described in our current report on form 8-K filed on March 25, 2010.
 
In April, 2010 we issued 2,500,000 shares of our common stock to Edward Mike Davis, L.L.C., the seller of oil and gas properties we acquired as described in our current report on form 8-K filed on April 20, 2010.
 
In May, 2010 we issued 2,000,000 shares of our common stock to Edward Mike Davis, L.L.C., the seller of oil and gas properties we acquired as described in our current reports on form 8-K filed on May 20, 2010 and June 4, 2010.
 
In November, 2010 we issued 6,666,667 shares of our common stock to Edward Mike Davis, L.L.C., the seller of oil and gas properties we acquired as described in our current report on for m 8-K filed on November 26, 2010.

In March, 2011 we issued 2,312,942 shares of our common stock to Wapiti, Inc., the seller of oil and gas properties we acquired as described in our current report on Form 8-K filed on February 24, 2011.
 
Shares and warrants  issued to our lender
 
In February, 2010 we issued 1,000,000 shares of our common stock to our lender Hexagon Investments, LLC in connection with receiving a $4,500,000 loan used to purchase oil and gas properties as described in our current reports on form 8-K filed on February 5, 2010 and March 4, 2010.
 
In March, 2010 we issued 750,000 shares of our common stock to our lender Hexagon Investments, LLC in connection with receiving a $6,000,000 loan used to purchase oil and gas properties as described in our current report on form 8-K filed on March 25, 2010.
 
In April, 2010 we issued 3,250,000 shares of our common stock and a five-year warrant to purchase 2,000,000 shares of our common stock at $2.50 per share to our lender Hexagon Investments, LLC in connection with receiving a $15,000,000 loan used to purchase oil and gas properties as described in our current report on form 8-K filed on April 20, 2010.
 
In June, 2010 we issued a five-year warrant to purchase 1,500,000 shares of our common stock at $1.50 per share to our lender Hexagon Investments, LLC , and in January, 2011 we issued to Hexagon a five-year warrant to purchase 1,000,000 shares of our common stock at $1.50per share Both issuances were in connection with amendments to our credit agreements necessary to purchase oil and gas properties as described in our current report on form 8-K filed on June 4, 2010.
 
Shares  and warrants  issued to service providers
 
In December, 2009 we issued a five-year warrant to purchase 750,000 shares of our common stock for $3.50 per share to a potential investor in exchange for a commitment of $20,000,000 to finance the purchase of oil and gas properties.
 
In April, 2010 we issued 30,995 shares of our common stock to C.K. Cooper & Company Inc. in exchange for financial advisory services.
 
In June, 2010 we issued 750,000 shares of our common stock, a five-year warrant to purchase 750,000 shares of our common stock for $1.50 per share and a three-year warrant to purchase 250,000 shares of our common stock for $1.50 per share to Market Development Consulting Group, Inc. in exchange for management consulting services.
 
In June, 2010 we issued a three-year warrant to purchase 50,000 shares of our common stock for $1.50 per share to Globe Media for public relations services.
 
In June, 2010 and January, 2011 we issued 50,000 shares and 40,000 shares of our common stock, respectively, to our landlord for an office lease.
 
In November, 2010 we granted 100,000 shares of our common stock to our geological consultant.
 
Shares issued to officers, directors and employees
 
In September, 2009 we granted 464,200 shares of our common stock to Jeffrey A. Beunier pursuant to his employment agreement.
 
 
In November, 2009 we granted 1,000,000 shares of our common stock to Roger A. Parker and 10,000 shares of our common stock to James Miller pursuant to their respective director appointment agreements.
 
In December, 2009 we granted 10,000 shares of our common stock to James Miller pursuant to his amended and restated director appointment agreement.
 
In February, 2010 we granted 100,000 shares of our common stock to James Miller pursuant to his amended and restated director appointment agreement.
 
In May, 2010 we granted (i) 4,500,000 shares of our common stock to Roger A. Parker pursuant to his employment agreement as our chief executive officer, (ii) 1,635,800 shares of our common stock to Jeffrey A. Beunier pursuant to his employment agreement as our chief financial officer and (iii) 80,000 shares of our common stock to James Miller pursuant to his amended and restated director appointment agreement.
 
In June, 2010 we granted 500,000 shares of our common stock to Timothy N. Poster and 150,000 shares of our common stock to Conway J. Schatz pursuant to their respective director appointment agreements.
 
In June, 2010 we granted 86,000 shares of our common stock to employees.
 
In November, 2010 we granted 307,187 shares of our common stock to employees.
 
In February, 2011 we granted 387,000 shares of our common stock to employees.
 
In May, 2011 we granted 138,000 shares of our common stock to employees.
 
Exemption from registration claimed
 
Issuance of the shares and warrants described above was not registered under the Securities Act of 1933. The issuance of these shares was exempt from registration, pursuant to Section 4(2) of the Securities Act of 1933. These securities qualified for exemption since in each case the issuance of securities by us did not involve a public offering. 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 a share certificate and/or warrants 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.” The T.R. Winston private placement was also exempt from registration pursuant to Rule 506 of Regulation D. 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 these issuances.
 
Item 16. Exhibits.

 
Exhibit No.
Description
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
Warrant to Purchase Common Stock dated December 11, 2009 (incorporated by reference to Exhibit 4.2 to Company's current report filed on form 8-K filed on December 17, 2009).
   
5.1
Legal Opinion of Brownstein Hyatt Farber Schreck, LLP.
   
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).
   
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 Spotie, 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
Employment Agreement with Roger A. Parker (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on December 23, 2010).
   
10.30
Employment Agreement with Jeffrey A. Beunier (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on December 23, 2010).
   
10.31
Director Appointment Agreement with James Miller (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on May 20, 2010).
   
10.32
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).
   
10.33
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).
   
10.34
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).
   
10.35
Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on June 4, 2010).
   
10.36
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).
 
10.37
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).
   
10.38
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).
   
10.39
Independent Director Appointment Agreement with Conway J. Schatz (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on June 7, 2010).
   
10.40
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).
   
10.41
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).
   
10.42
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).
   
10.43
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).
   
10.44
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).
   
10.45
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).
   
10.46
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).
   
10.47
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).
   
10.48
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).
   
10.49
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).
   
10.50
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).
   
10.51 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). 
   
10.52 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).
   
10.53
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). 
   
10.54
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).
   
10.55
Separation Agreement with Jeffrey A. Beunier (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on February 15, 2011).
   
14.1
Code of Ethics (incorporated herein by reference to Exhibit 14.1 to Company's annual report on form 10-K for the year ended December 31, 2009).
   
16.1
Letter from Jewett, Schwartz, Wolfe & Associates to the U.S. Securities and Exchange Commission dated January 19, 2010 (incorporated herein by reference to Exhibit 16.1 to the Company's periodic report on form 8-K dated January 21, 2010).
   
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 Brownstein Hyatt Farber Schreck, LLP (included in Exhibit 5.1).
   
23.2
Consent of Hein & Associates LLP
   
23.3
Consent of RE Davis.
   
24.1
Power of Attorney (included on the signature page of this registration statement).
   
99.1
Report of RE Davis (incorporated herein by reference to Exhibit 99.1 to the Company’s annual report on Form 10-K for the year ended December 31, 2010).
 
 
II-7

 
Item 17. Undertakings.
 
The undersigned registrant hereby undertakes:
 
Insofar as indemnification for liabilities arising under the Securities Act 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 SEC 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 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 against the registrant 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 of 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.
 
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.
 
·
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 SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20 percent 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.
 
The undersigned registrant hereby also undertakes that, for the purpose of determining any liability under the Securities Act, 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 the time shall be deemed to be the initial bona fide offering thereof.
 
The undersigned registrant hereby undertakes 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.
 
The undersigned registrant hereby undertakes that, for the purpose of determining liability under the Securities Act 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.
 
Finally, the undersigned registrant hereby undertakes that, for purposes of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, 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;
 
·
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.
 
 
SIGNATURES
 
Pursuant to the requirements of the Securities Act of 1933, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-1 and has duly caused this amendment to registration statement to be signed on its behalf by the undersigned on June 2 , 2011.
 
RECOVERY ENERGY, INC.,
a Nevada corporation
By: /s/ Roger A. Parker
Name: Roger A. Parker
Title: Chief Executive Officer
 
POWER OF ATTORNEY
 
 
Pursuant to the requirements of the Securities Act of 1933, this amendment to registration statement has been signed below by the following persons in the capacities indicated on June 2, 2011:
 
Name and Signature
 
Title
     
/s/ Roger A. Parker
 
Chief Executive Officer, Principal Executive Officer, Principal Financial Officer and Director
Roger A. Parker
   
     
/s/ Christopher Barber
 
Principal Accounting Officer
Christopher Barber
   
     
/s/ James J. Miller*
 
Director
James J. Miller
   
     
/s/ Timothy N. Poster*
 
Director
Timothy N. Poster
   
     
/s/Conway J. Schatz*
 
Director
Conway J. Schatz
   
     
* By: Roger A Parker
   
Roger A. Parker, power of attorney
   
 
 
EXHIBITS INDEX
 
Exhibit No.
Description
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
Warrant to Purchase Common Stock dated December 11, 2009 (incorporated by reference to Exhibit 4.2 to Company's current report filed on form 8-K filed on December 17, 2009).
   
5.1
Legal Opinion of Brownstein Hyatt Farber Schreck, LLP.
   
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).
   
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 Spotie, 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
Employment Agreement with Roger A. Parker (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on December 23, 2010).
 
 
10.30
Employment Agreement with Jeffrey A. Beunier (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on December 23, 2010).
   
10.31
Director Appointment Agreement with James Miller (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on May 20, 2010).
   
10.32
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).
   
10.33
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).
   
10.34
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).
   
10.35
Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K fi led on June 4, 2010).
   
10.36
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).
   
10.37
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).
   
10.38
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).
   
10.39
Independent Director Appointment Agreement with Conway J. Schatz (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on June 7, 2010).
   
10.40
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).
   
10.41
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).
   
10.42
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).
   
10.43
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).
   
10.44
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).
 
10.45
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).
   
10.46
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).
   
10.47
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).
   
10.48
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).
   
10.49
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).
   
10.50
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).
   
10.51 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). 
   
10.52  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).
   
10.53
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). 
   
10.54
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).
   
10.55
Separation Agreement with Jeffrey A. Beunier (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on February 15, 2011).
   
14.1
Code of Ethics (incorporated herein by reference to Exhibit 14.1 to Company's annual report on form 10-K for the year ended December 31, 2009).
   
16.1
Letter from Jewett, Schwartz, Wolfe & Associates to the U.S. Securities and Exchange Commission dated January 19, 2010 (incorporated herein by reference to Exhibit 16.1 to the Company's periodic report on form 8-K dated January 21, 2010).
   
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 Brownstein Hyatt Farber Schreck, LLP (included in Exhibit 5.1).
   
23.2
Consent of Hein & Associates LLP
   
23.3
Consent of RE Davis.
   
24.1
Power of Attorney (included on the signature page of this registration statement).
   
99.1
Report of RE Davis (incorporated herein by reference to Exhibit 99.1 to the Company’s annual report on Form 10-K for the year ended December 31, 2010).

 
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