UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


Washington, D.C. 20549





FORM 10-K/A





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


For the fiscal year ended December 31, 2010 or





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





For the transition period from __________to_________




Commission file number: 333-152571





Recovery Energy, Inc.


(Name of registrant as specified in its charter)





NEVADA

74-3231613(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)





1515 Wynkoop Street, Suite 200, Denver, CO 80202


(Address of principal executive offices, including zip code)





Registrant’s telephone number including area code:  (303)-951-7920


Securities registered under Section 12(b) of the Act:





None





Securities registered under Section 12(g) of the Act:





Title of each class$0.0001 par value Common Stock




Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  o No x





Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes  o No x





Indicate by check mark if the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x No o





Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not  contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 (as defined in Rule 12b-2 of the Act):





Large accelerated filer
o
Accelerated filer
oNon-accelerated filer
o
Smaller reporting company
x




Table of Contents





Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  oNo x





State the aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the fiscal quarter ending March 31, 2011:  $66,860,959.





As of March 31, 2011, 60,982,425 shares of the registrant’s common stock were issued and outstanding.





Explanatory Note:  We are filing this amendment to update our annual report for the year ended December 31, 2010 to conform to the responses we have made to comments received from the staff of the Securities and Exchange Commission on a registration statement on Form S-1.  We are also amending our quarterly reports on Form 10-Q for the periods ended September 30, 2010 and March 31, 2011 for this reason.













FORM 10-K/A ANNUAL REPORT


FISCAL YEAR ENDED DECEMBER 31, 2010


RECOVERY ENERGY INC





Item

PagePART I1 AND 2.
Business and Properties
31A.
Risk Factors
211B.
Unresolved Staff Comments
313.
Legal Proceedings
314.
Reserved
31PART II5.
Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
316.
Selected Financial Data
327.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
337A.
Quantitative and Qualitative Disclosures About Market Risk
428.
Financial Statements and Supplementary Data
429.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
429A(T).
Controls and Procedures
429B.
Other Information
44PART III10.
Directors, Executive Officers and Corporate Governance
4411.
Executive Compensation
4712.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
5013.
Certain Relationships and Related Transactions, and Director Independence
5114.
Principal Accountant Fees and Services
54PART IV15.
Exhibits and Financial Statement Schedules
55




Table of Contents





CAUTIONARY NOTICE





This annual report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  Those forward-looking statements include our expectations, beliefs, intentions and strategies regarding the future.  Such forward-looking statements relate to, among other things, our proposed exploration and drilling operations on our various properties, the expected amount of capital required to finance our 2011 capital budget, the expected production and revenue from our various properties, and estimates regarding the reserve potential of our various properties.  These and other factors that may affect our results are discussed more fully in “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and elsewhere in this report.  We caution readers not to place undue reliance on any forward-looking statements.  We do not undertake, and specifically disclaim any obligation, to update or revise such statements to reflect new circumstances or unanticipated events as they occur, except as required by law, and we urge readers to review and consider disclosures we make in this and other reports that discuss factors germane to our business.  See in particular our reports on Forms 10-K, 10-Q, and 8-K subsequently filed from time to time with the Securities and Exchange Commission.





PART I


Items 1. and 2.  BUSINESS and PROPERTIES





Industry terms used in this report are defined in the Glossary of Oil and Natural Gas Term located at the end of this Item 1 and 2.





General





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.





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 annual report on Form 10-K/A.  A copy of this annual report on Form 10-K/A is located at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 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.





Company Overview & Strategy





We have developed and acquired an oil and natural gas base of proved reserves, as well as a portfolio of development drilling and exploratory drilling opportunities of high-impact conventional and non-conventional prospects with an emphasis on multiple producing horizons and the Niobrara shale resource play. We believe these prospects offer 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. Between January 1 and December 31, 2010 we acquired and developed 19 producing wells. As of March 31, 2011 we owned interests in approximately 155,000 gross (133,000 net) leasehold acres, of which 152,000 gross (131,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska in the DJ Basin.  We intend to continue to evaluate and invest in acquisitions and internally generated prospects.  It is our long-term goal to maximize our DJ Basin acreage position through development drilling of our conventional horizons as well as development of our Niobrara 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.


3
 Table of Contents




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.





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





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





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





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





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





Controlling Costs.We maximize our returns on capital by minimizing our expenditures on general and administrative expenses. We also minimize initial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that have already invested capital in such. Historically, we also outsourced some of our geological, geophysical, reservoir engineering and land functions in order to help reduce capital requirements.  We recently brought many of these functions in-house to provide us with greater ability to maximize the value of our growing leasehold position.





Since December 31, 2010 we have 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.




4
 Table of Contents




Principal Oil and Gas Interests




As of December 31, 2010 we owned 19  producing wells, 1 shut-in well, 1 injection well, and 2 wells in progress in the Wyoming, Nebraska and Colorado portion of the DJ Basin, as well as approximately 134,000 gross (117,500 net) acres, of which 130,000 gross (114,000 net) acres are classified as undeveloped acreage.   Our primary targets within the DJ Basin are the conventional Dakota and Muddy ‘J’ formations, in addition to the developing unconventional Niobrara shale play.  Additional horizons include the Coddell, Greenhorn and Pierre Shale.  Our current production and our recent drilling efforts have focused on the conventional Dakota and Muddy ‘J’ target horizons.   During 2010, we made capital expenditures of approximately $4.6 million related primarily to drilling and completion operations where we drilled 3 gross (2.1 net) wells and completed 2 gross (1.4 net) wells.  As of December 31, 2010 we had 2 gross (2.0 net) wells in progress.





As of December 31, 2010 we had net proved reserves of 744 mboe and for the year ending December 21, 2010 we produced 136 mboe.





As of March 31, 2011 we were operating one drilling rig on our acreage, which focused on our first horizontal Niobrara well.





2011 Capital Budget





Our anticipated 2011 capital expenditure budget is $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.





Capital Resources





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.




5
 Table of Contents





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.





Reserves





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





We emphasize that reserve estimates are inherently imprecise and that estimates of all new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties.  Accordingly, these estimates are expected to change as new information becomes available.  The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by us.  Neither prices nor costs have been escalated.  The following table should be read along with the section entitled “Risk Factors — Risks Related to Our Company - The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated.”  No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year. We did not have third party engineers review probable, possible and resource based reserves as of December 31, 2010.  These reserve categories are currently being determined across our substantial acreage position and are expected to identify significant potential in all unproven classifications and from multiple horizons.


6
 Table of Contents





As of December 31,2010


2009 (1)


2008 (1)Reserve data:Proved developedOil (MBbl)


278



-



-Gas (MMcf)


308



-



-MBOE


329



-



-Proved undevelopedOil (MBbl)


415



-



-Gas (MMcf)


-



-



-MBOE


415



-



-Total ProvedOil (MBbl)


693



-



-Gas (MMcf)


308



-



-MBOE


744



-



-Proved developed reserves %


44
%


-
%


-
%Proved undeveloped reserves %


56
%


-
%


-
%Reserve value data :Proved developed PV-10

$
11,377,009


$
-


$
-Proved undeveloped PV-10


12,217,798



-



-Total proved PV-10

$
23,594,807


$
-


$
-Standardized measure of discounted future cash flows

$
23,594,807


$
-


$
-Reserve life (years)


21.92



-



-





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





Proved undeveloped reserves added during the year resulted from engineering analysis of properties acquired during the year and did not change materially as a result of drilling activities conducted during the year, nor were there any material transfers of proved undeveloped reserves to the proved developed category.





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





Internal Controls Over Reserves Estimate





Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserve quantities and values in compliance with the regulations of the Securities and Exchange Commission.  Responsibility for compliance in reserve bookings is delegated to our Senior Reservoir Engineer.





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


7
 Table of Contents





Third-party Reserves Study





A independent third party reserve study is performed by RE Davis using their own engineering assumptions and other economic data provided by us.  100 percent of our total calculated proved reserve PV-10 value is audited by RE Davis.  RE Davis is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services for over 20 years.  The technical person at RE Davis primarily responsible for overseeing our reserve audit is the President and CEO who received a Bachelor of Science degree in Chemical and Petroleum Engineering from the University of Houston and is a registered Professional Engineer in the States of Texas.  He is also a member of the Society of Petroleum Engineers.  The RE Davis report is included as Exhibit 99.1 to this annual report.





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





Production





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





For the Year Ended December 31,2010


2009 (1)


2008 (1)Net productionOil (MMBbl)


133.709



-



-Gas (MMcf)


14.914



-



-MBOE


136.195



-



-Average net daily productionOil (Bbl)


366



-



-Gas (Mcf)


41



-



-BOE


373



-



-Average realized sales price, excluding the effects of our economic hedgesOil (per Bbl)

$
71.08


$
-


$
-Gas (per Mcf)

$
4.56


$
-


$
-Per BOE

$
70.29


$
-


$
-Average realized sales price, including the effects of our economic hedgesOil (per Bbl)

$
75.27


$
-


$
-Gas (per Mcf)

$
4.56


$
-


$
-Per BOE

$
74.47


$
-


$
-Production costs per BOELease operating expense (2)

$
6.33


$
-


$
-DD&A

$
36.98


$
-


$
-Production taxes

$
7.76


$
-


$
-





(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


8
 Table of Contents





Productive Wells





As of December 31, 2010, we had working interests in 16 gross (15.2 net) productive oil wells, and 3 gross (1.5 net) productive gas wells. Productive wells are either wells producing in commercial quantities or wells capable of commercial production although currently shut-in.  Multiple completions in the same wellbore are counted as one well.  A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.





Acreage




As of December 31, 2010 we owned 19  producing wells in the Wyoming, Nebraska and Colorado portion of the DJ Basin, as well as approximately 134,000 gross (117,000 net) acres, of which 130,000 gross (114,000 net) acres was classified as undeveloped acreage.
 
 As of December 31, 2010 our primary assets included acreage located in Laramie County, Wyoming, Banner, Kimball, and Scotts Bluff Counties, Nebraska, and Weld, Arapahoe and Elbert Counties, Colorado.  Subsequent to December 31, 2010 we acquired additional acreage in Laramie and Goshen County, Wyoming and Weld County, Colorado.




The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 2010.





Undeveloped


DevelopedGross


Net


Gross


NetDJ Basin


134,047



116,820



3,720



3,037Total


134,047



116,820



3,720



3,037




9
 Table of Contents


Drilling Activity


The following table describes the development and exploratory wells we drilled during the years ended December 31, 2010, 2009, and 2008.





For the Year Ended December 31,2010


2009 (1)


2008 (1)Gross


Net


Gross


Net


Gross


NetDevelopment:










-



-



-



-Productive wells


2.0



1.4



-



-



-



-Dry wells


1.0



0.7



-



-



-



-3.0



2.1



-



-



-



-Exploratory:Productive wells


-



-



-



-



-



-Dry wells


-



-



-



-



-



--



-



-



-



-



-Total


3.0



2.1



-



-



-



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





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





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





In addition to the wells drilled and completed in 2010 included in the table above, we were in the process of drilling 2 gross (2.0 net) wells which are currently in the assessment and completion phase, all of which was located in the DJ Basin.  Between December 31 and March 31, 2010 we drilled 2 gross (2.0 net) wells. One of the wells was plugged and abandoned and the second was temporarily abandoned.







10
 Table of Contents





Major Customers





During 2010, the Company had one customer, Shell Trading (US), individually accounting for approximately 64 percent of our total oil and gas production revenue.  During 2008 and 2009, the Company did not have any production or customers.





Employees





As of March 31, 2010 we had eight employees. For the foreseeable future, we intend to only add additional personnel as our operational requirements grow. In the interim, we plan to continue to use the services of independent consultants and contractors to perform various professional services, including land, legal, environmental and tax services. We believe that by limiting our management and employee costs, we are able to better control total costs and retain flexibility in terms of project management.





Title to Properties





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





Seasonality





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





11
 Table of Contents




Competition





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





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





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





Recent Developments and Related Transactions





During the fourth quarter of 2010 and through March 31, 2011, we have engaged in the following transactions, some of which were with related parties:





In November 2010, the State Bradbury 14-36 well which we completed in August 2010, was connected to a natural gas sales pipeline. This well is located on a 640 acre oil and gas lease in Arapahoe County, Colorado known as Comanche Creek. We acquired 50% interests in this prospect and the Omega prospect in January 2010 from Davis as part of the Wilke acquisition. We acquired an additional 12.5% working interest in the Comanche Creek prospect in June 2010 from Davis in exchange for a 1% overriding royalty interest on our existing 50% working interest, resulting in us owning 62.5% working interest. The remaining 37.5% working interest is split between Davis and Timothy N. Poster, a member of our board of directors, with Davis holding 12.5% and Mr. Poster holding 25% of the working interest. The operations of the well will be covered by a joint operating agreement.





In November 2010, the Company entered into a purchase agreement with Edward Mike Davis, L.L.C. 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, we 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. Also 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 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.





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.





In December 2010, Hexagon extended the maturity date of our loan to September 1, 2012. On January 1, 2011, we issued a five year warrant with a $1.50 exercise price to Hexagon as required under the extension agreement executed in June 2010. Hexagon, together with its affiliates, own approximately 12.8% of our outstanding stock as of February 2, 2011.





12
 Table of Contents





In February 2011, the Company entered into a purchase agreement for a private placement sale of $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 upon the closing of certain acquisitions in February, 2011. $3,000,000 of the proceeds from the sale of the Debentures is restricted to acquisition of and drilling activities on the properties which were cover by the acquisitions, and are 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, so long as the stock utilized to pay the interest expense is covered under an effective registration statement. 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 on approximately 1,700 leasehold acres in the Grover Field and surrounding area in Weld County, Colorado, and approximately 6,600 net acres in Goshen County, Wyoming. The purchase price was $1,253,780 in cash and $653,449 in common stock.





In March 2011, the Company closed on 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 2,312,942 shares of our common stock.





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





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





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





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:




13
 Table of Contents




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





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





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




14
 Table of Contents





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





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





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





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





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





15
 Table of Contents




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





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





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





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





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




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.
  16
 Table of Contents





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





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





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





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





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





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





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





17
 Table of Contents





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.




18
 Table of Contents





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.




19
 Table of Contents





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.





20
 Table of Contents





Item 1A. RISK FACTORS





CAUTIONARY STATEMENT REGARDING FUTURE RESULTS, FORWARD-LOOKING


INFORMATION AND CERTAIN IMPORTANT FACTORS





In this report we make, and from time to time we otherwise make, written and oral statements regarding our business and prospects, such as projections of future performance, statements of management’s plans and objectives, forecasts of market trends, and other matters that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements containing the words or phrases “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimates,” “projects,” “believes,” “expects,” “anticipates,” “intends,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions identify forward-looking statements, which may appear in documents, reports, filings with the Securities and Exchange Commission, news releases, written or oral presentations made by officers or other of our representatives to analysts, stockholders, investors, news organizations and others, and discussions with management and other of our representatives. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.





Our future results, including results related to forward-looking statements, involve a number of risks and uncertainties. No assurance can be given that the results reflected in any forward-looking statements will be achieved. Any forward-looking statement speaks only as of the date on which such statement is made. Our forward-looking statements are based upon assumptions that are sometimes based upon estimates, data, communications and other information from operators, government agencies and other sources that may be subject to revision. Except as required by law, we do not undertake any obligation to update or keep current either (i) any forward-looking statement to reflect events or circumstances arising after the date of such statement, or (ii) the important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or which are reflected from time to time in any forward-looking statement.





In addition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors, include the following:





Risks Related to our Company





We have historically incurred losses and cannot assure investors as to future profitability.  We have historically incurred losses from operations during our history in the oil and natural gas business. As of December 31, 2010, we had a cumulative deficit of approximately $50 million. Many of our properties are in the exploration stage, and to date we have established a limited volume of proved reserves on our properties. Our ability to be profitable in the future will depend on successfully implementing our acquisition, exploration, development and production activities, all of which are subject to many risks beyond our control. Even if we become profitable on an annual basis, we cannot assure you that our profitability will be sustainable or increase on a periodic basis. In addition, should we be unable to continue as a going concern, realization of assets and settlement of liabilities in other than the normal course of business may be at amounts significantly different from those in the financial statements included in this 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 December 31, 2010, we had working capital of $5,586,906, including $6,679,285 of cash and cash equivalents of which $1,150,541 was 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.





21
 Table of Contents





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 December 31, 2010, 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. As of March 31, 2011 we had 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 one of our officers could adversely affect us. We are dependent on the extensive experience of our chief executive officer and our chief financial officer to implement our acquisition and growth strategy. The loss of the services of either of these individuals could have a negative impact on our operations and our ability to implement our strategy.





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.





22
 Table of Contents





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; 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.





23
 Table of Contents





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.





24
 Table of Contents





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 $20.1 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.





25
 Table of Contents





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. 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;




26
 Table of Contents




●
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:





27
 Table of Contents




●  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.





28
 Table of Contents





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:





29
 Table of Contents




●  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.





30
 Table of Contents





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.





Item 1B.  UNRESOLVED STAFF COMMENTS




As a smaller reporting company, we are not required to disclose information under this item.





Item 3. LEGAL PROCEEDINGS





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





Item 4. RESERVED





PART II





Item 5.  MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES





Recent Market Prices





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


Low2011First Quarter

$
4.00


$
1.952010Fourth Quarter

$
2.50


$
1.81Third Quarter

$
2.50


$
1.50Second Quarter

$
4.00


$
0.25First Quarter

$
5.50


$
2.052009Fourth Quarter

$
5.75


$
3.00September 25, 2009 through September 30, 2009

$
6.00


$
4.25





31
 Table of Contents





On March 11, 2011, there were approximately 64 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.





Securities Authorized for Issuance Under Equity Compensation Plans





The following table provides information with respect to our common shares issuable under various officer employment contracts and under director appointment agreements as of December 31, 2010:





Number of

Securities to be

Issued Upon

Exercise of

Outstanding

Options, Grants, Warrants

and Rights (a)


Weighted-Average

Exercise Price of

Outstanding Options, Grants,

Warrants and Rights (b)


Number of Securities

Remaining Available

for Future Issuance

Under Equity

Compensation Plans

(Excluding Securities

Reflected in Column (a) (b)Equity compensation plans approved by security holders


-


$
-



-Equity compensation plans not approved by security holders


8,943,187



-



-Total


8,943,187


$
-



-





Dividend Policy





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





Recent Sales of Unregistered Securities





We have previously disclosed by way of quarterly reports on Form 10-Q and current reports on Form 8-K filed with the SEC all sales by us of our unregistered securities during 2010.





Item 6.  SELECTED FINANCIAL DATA





As a smaller reporting company, we are not required to provide this information.








32
 Table of Contents
  Item 7.  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 Form 10-K. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors including those set forth in our “Risk Factors” described herein.





General





We are an independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the DJ Basin. Our business strategy is designed to create 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.





For the three and twelve month periods ended December 31, 2010, our total production was 29,470 and 136,195 net BOE, respectively.





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 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.





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.  For financial reporting purposes the Wilke Field acquisition was considered a predecessor business and information with respect to these properties is provided on page 36. Because of the subsequent property acquisitions by the Company during 2010 and the operations of the Wilke Field properties by another company, comparable financial information is not provided within this discussion  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 EndedDecember 31, 2010Volume

Average PriceProduct:Oil (Bbls)


26,984


$
77.19Natural 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.





33
 Table of Contents





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 productionOil (Bbl)


133,709



-



-Gas (Mcf)


14,914



-



-MBOE


136,195



-



-Average net daily productionOil (Bbl)


366



-



-Gas (Mcf)


41



-



-BOE


373



-



-Average realized sales price, excluding the effects of hedgingOil (per Bbl)

$
71.08


$
-


$
-Gas (per Mcf)

$
4.56


$
-


$
-Per BOE

$
70.29


$
-


$
-Average realized sales price, including the effects of hedgingOil (per Bbl)

$
75.27


$
-


$
-Gas (per Mcf)

$
4.56


$
-


$
-Per BOE

$
74.47


$
-


$
-Production costs per BOELease 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.  See discussion of our predecessor operations on page 36.(2)
Approximately $2.35/BOE of lease operating expense relates to surface, subsurface, road repairs and work-over activities.





34
 Table of Contents





General and Administrative Expenses





General and administrative expenses were $3,635,060 and $15,530,248 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 and a non-cash warrant modification expense of $2,953,450 for the year ended December 31, 2010. Total non-cash general and administrative expenditures for the three and twelve months ended December 31, 2010 was approximately $3,039,000 and $13,300,000, 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, nor our predecessor business, did not incur interest expense from inception through December 31, 2009.





We incurred a net loss to common shareholders of $19,739,033 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.




35
 Table of Contents
  Wilke Field Acquisition Properties, for the year ended December 31, 2009





For financial reporting purposes the Wilke Field acquisition was considered our predecessor business. As previously indicated these were operated by another company. However, information with respect to Wilke Field properties for the year ended December 31, 2009, is provided below.





For the year ended December 31, 2009, total production was 101,087 net barrels of oil for total oil sale revenue of $4,671,274, for an average price per barrel of $46.21. Average daily production for the year ended December 31, 2009 was 277 BOPD. Production costs were $453,176, or $4.48 per barrel and production taxes were $267,818, or $2.65 per barrel. Depreciation, depletion and amortization expense for the year ended December 31, 2009 was $2,705,953, or $26.77 per barrel, and was comprised of $2,690,188 of depletion expense on the oil and gas properties and $15,765 of accretion expense on the asset retirement obligation. Total operating costs per barrel were $33.90, for a gross margin per barrel of $12.31, or 26.6%





During the year ended December 31, 2009, net cash provided by operating activities was $3,860,088. The primary changes in operating cash during the year ended December 31, 2009 was $993,327 of net income, adjusted for non-cash charges of $2,705,953 of depreciation, depletion and amortization expense (“DD&A”) and accretion expense, and a decrease in accounts receivable of $145,495.





During the year ended December 31, 2009, net cash used by investing activities was $1,036,052, and was comprised solely of drilling capital expenditures.





During the year ended December 31, 2009, net cash used in financing activities was $2,824,036, and was comprised solely of distributions.





Plan of Operations





Our plan of operations for the next twelve months 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 $20.1 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 $20.1 million credit facilities.





36
 Table of Contents





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.





37
 Table of Contents





During the year ended December 31, 2010, our working capital increased to $4,436,365 compared to a negative working capital of ($44,229) at December 31, 2009. The higher working capital and cash position is primarily the result of capital raised during the twelve months ended December 31, 2010 as well as the addition of several producing oil and gas properties during the year ended December 31, 2010.





During the year ended December 31, 2010, net cash provided by operating activities was $3,758,694. The primary changes in operating cash during the year ended December 31, 2010 were $(19,739,033) of net loss, adjusted for non-cash charges of $5,036,648 of depreciation, depletion and amortization expenses and accretion expense, $8,376,220 of stock-based compensation, $3,989,649 of amortization of deferred financing costs, $2,953,450 in warrant modification expense, $1,578,080 of non-cash compensation expense, bad debt expense of $400,000 and a non-cash loss on derivative contracts of $398,840.  In addition, we had an increase in accounts receivable of $757,554, an increase of $1,129,665 in restricted cash, offset by an increase in accounts payable of $872,014.





During the year ended December 31, 2010, net cash used by investing activities was $(46,809,757). The primary changes in investing cash during the year ended December 31, 2010 was $46,891,204 in expenditures related to our acquisitions which consisted primarily of the proved and unproved acreage, $1,887,111 in drilling expenditures, offset by $2,000,000 in proceeds received from the sale of an interest in property to the TRW Exploration joint venture.





During the year ended December 31, 2010, net cash provided by financing activities was $48,471,408. The primary changes in financing cash during the year ended December 31, 2010 were net proceeds from the sale of common stock for $23,011,727, proceeds from the exercise of warrants for $5,121,000, and the issuance of debt in connection with the acquisitions for $28,500,000, offset by debt repayments of ($8,061,319).





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 $20.1 million, and our recent commitment for $8 million of convertible debentures (as described under "Business - Recent Developments and Related Transactions"), 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 $20.1 million credit agreements which matures 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 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.





38
 Table of Contents





Use of Estimates





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 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.




39
 Table of Contents




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. The Company adopted the updated guidance effective March 6, 2009, and applied it to its three DJ BasinAcquisitions 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.





40
 Table of Contents





Derivative Instruments





During 2010, the Company entered in to 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





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





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





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 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.





41
 Table of Contents





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 Holdings, Inc., 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, 2010, 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.  In our major tax jurisdiction, the earliest years remaining subject to examination are April 20, 2009 and April 30, 2010.





Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK





As a smaller reporting company, we are not required to provide the information under this item.





Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA





Our financial statements appear immediately after the signature page of this report. See "Index to Financial Statements" on page 41 of this report.





Item 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE





None.





Item 9A(T).  CONTROLS AND PROCEDURES





We maintain a system of disclosure controls and procedures that are designed to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.





We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K.  Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures are effective for the purpose discussed above as of the end of the period covered by this Annual Report on Form 10-K.  There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.





42
 Table of Contents





MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING





To the Stockholders’ of Recovery Energy Inc





Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  The Company’s internal control over financial reporting includes those policies and procedures that:





(i)  pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;


(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and


(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of    the Company’s assets that have a material effect on the financial statements.


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





Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control—Integrated Framework.





Based on our assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2010.





The Company’s independent registered public accounting firm has not issued an attestation report on the Company’s internal controls over financial reporting.





/s/ ROGER A PARKER

/s/ JEFFREY A BEUNIERRoger A. Parker

Jeffrey A BeunierChief Executive Officer

President and Chief Financial OfficerMarch 31, 2011

March 31, 2011





This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management's report in this Annual Report.





There were no changes in our internal control over financial reporting during the quarter ended December 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.





43
 Table of Contents





Item 9B.  OTHER INFORMATION





None.





PART III





Item 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE





MANAGEMENT





Our officers and directors as of March 31, 2011 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
PositionRoger A. Parker
49
Chief Executive Officer, Director, Chairman of Board of DirectorsJeffrey A. Beunier
37
President, Chief Financial Officer and DirectorJames J. Miller
33
DirectorTimothy N. Poster
42
DirectorConway 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, 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.





Jeffrey A. Beunier: Chief Executive Officer, President, Chief Financial Officer and Director.  Mr. Beunier is the founder and principal of Open Choke Capital Management, LLC in Denver, Colorado since June 2007, which provides consulting services to hedge fund and private investors focusing on energy related transactions.  Additionally, Mr. Beunier advised independent oil and gas operators on capital structure and funding sources and since April of 2009, Mr. Beunier performed turnaround management and restructuring services on behalf of a national restructuring firm.  From February 2005 to June 2007, Mr. Beunier was the Vice President and Portfolio Director of Madison Capital Management, LLC in Denver, Colorado. He was responsible for sourcing, underwriting, and managing distressed investment opportunities and sourcing, underwriting, structuring, and managing investment opportunities in the commercial, industrial and energy sectors. From July 2003 to November 2004, he worked for Summit Investment Management, LLC as a Senior Underwriter and Senior Asset Officer. Mr. Beunier holds a Bachelor degree from the Pennsylvania State University where he majored in accounting with a minor in Real Estate.  In March 2001, he became a licensed CPA.





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.




44
 Table of Contents




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.





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.”





45
 Table of Contents





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.




46
 Table of Contents
  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.





Code of Ethics





We have adopted a code of conduct that applies to our directors and employees (including our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions), and have posted the text of the policy on our website (www.recoveryenergyco.com). If we make any substantive amendments to our code of conduct or grant any waiver, including any implicit waiver, from a provision of the code to our chief executive officer, president, chief financial officer or chief accounting officer or corporate controller, we will disclose the nature of such amendment or waiver on that website or in a report on Form 8-K.





Section 16(b) Beneficial Ownership Reporting Compliance





Section 16(a) of the Securities Exchange Act of 1934 requires that our directors and executive officers, and beneficial owners of more than 10% of our outstanding common stock to file reports with the SEC disclosing their ownership of common stock and changes in such ownership. The rules of the SEC require insiders to provide Recovery with copies of all Section 16(a) reports that the insiders file with the SEC. Recovery believes that, with respect to the 2010 fiscal year, its directors, executive officers and 10% stockholders complied with all Section 16(a) filing requirements, except thatEdward Mike Davis filed four late forms covering four transactions and Capital Asset Lending, Inc.,Westmoore Lending Opportunities, Inc., Westmoore Management, LLC, Westmoore Lending, LLC and Matthew Jennings did not file any required forms..  In making these statements, we have relied upon examination of the copies of Forms 3, 4 and 5, and amendments thereto, providedto us and the written representations of our directors, executive officers and 10% stockholders.




Item 11.  EXECUTIVE COMPENSATION





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.




47
 Table of Contents





Name and

principal position

Year

Salary


Bonus


Stock

Awards


Other

compensation


TotalRoger A. Parker (chief executive

2010

$
160,000



-0-
(1)

$
5,671,955
(5)

$
851,040
(2)(3)

$
6,712,995officer since May 1, 2010)

2009

$
-0-



-0-






$
-0-


$
-0-Jeffrey A. Beunier (chief executiveofficerfrom September 1, 2009to April 30, 2010; president

2010

$
216,666


$
50,000
(1)

$
1,181,396
(4)

$
791,040
(3)

$
2,239,102and chief financial officerfrom May 1, 2010 to April 11, 2011)

2009

$
50,769



-0-


$
82,068
(4)

$
91,187


$
132,837Lanny 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.  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.





48
 Table of Contents





Jeffrey A. Beunier.  We had an employment agreement with Mr. Beunier, who resigned as our chief financial officer in April, 2011.  Under his employment agreement Mr. Beunier received an annual base salary of $225,000 and was 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. Beunier received grants totaling 2,100,000 shares of our common stock.  50% of his granted shares vested on January 1, 2011 and the remaining shares were scheduled to vest in six equal amounts on the first day of each calendar quarter commencing on April 1, 2011 and ending on July 1, 2012.  The shares were to vest immediately upon a change of control or if Mr. Beunier's services as chief financial officer were terminated other than for cause or by Mr. Beunier.  Mr. Beunier's agreement permitted Mr. Beunier to engage in other business activities in the energy industry as long as such activities did not unreasonably or materially interfere with the performance of Mr. Beunier’s duties for the Company





Compensation of Directors





The table below sets forth the compensation earned by our non-employee directors during the 2010 and 2009 fiscal years. 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


TotalRoger A. Parker(1)

2010

$
-0-


$
773,305


$
30,000
(2)

$
803,3052009

$
-0-


$
386,653


$
11,250
(2)

$
397,903James J. Miller

2010

$
15,000


$
275,570



-0-


$
290,5702009

$
1,250


$
6,938






$
8,188Timothy N. Poster

2010

$
5,000


$
384,953






$
389,9532009

$
-0-


$
-0-






$
-0-Conway J. Schatz

2010

$
10,000


$
89,721



-0-


$
99,7212009

$
-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.





49
 Table of Contents





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.





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.





Securities Authorized for Issuance Under Equity Compensation Plans





Information relating to securities authorized for issuance under our equity compensation plans is set forth in “Item 5, Market for Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities” above in this annual report.





Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS





The following table sets forth certain information with respect to beneficial ownership of our common stock as of April 29, 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. Beneficial ownership is determined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended. In computing the number of shares beneficially owned by a person or a group and the percentage ownership of that person or group, shares of our common stock subject to options or warrants currently exercisable or exercisable within 60 days after the date hereof are deemed outstanding, but are not deemed outstanding for the purpose of computing the percentage ownership of any other person. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Recovery Energy, 1515 Wynkoop Street, Suite 200, Denver, Colorado 80202.
  Name and Address of Beneficial Owner

Beneficially Owned


Percent of Class Beneficially OwnedDirectors and Executive OfficersRoger A. Parker, President, Chief Executive Officer and Chairman of Board of Directors


5,500,000(1)



8.8
%James J. Miller, Director


200,000(1)



0.3
%Conway J. Schatz, Director


150,000(1)



0.2
%Timothy N. Poster, Director


500,000(1)



0.8
%Officers and directors as a group (four persons)


6,500,000



10.2
%Hexagon Investments, LLC


10,500,000(2)



10.4
%Scott J. Reiman


10,500,000(2)



10.4
%Reiman Foundation (2)


10,500,000(2)



10.4
%Edward Mike Davis, L.L.C.


12,461,667(3)



19.9
%Steven B. Dunn


4,000,000 (4)



6.4
%Steven B. Dunn Custodian for Steven Winston Dunn UTMA


4,000,000 (4)



6.4
%JMB Capital Partners Master Fund, L.P.


6,666,667(5)



10.7
%J. Steven Emerson Roth IRA Pershing LLC as Custodian


5,150,000 (6)



8.2
%J. Steven Emerson IRA RO II Pershing  LLC as Custodian


5,150,000 (6)



8.2
%J. Steven Emerson


5,150,000 (6)



8.2
%Emerson Family Foundation


5,150,000 (6)



8.2
%


50
 Table of Contents
  (1)
These shares are subject to vesting as described under “Management - Executive Compensation”.(2)
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) 516,032 shares owned by Scott J. Reiman and (v) 983,968 shares owned by Reiman Foundation, which is controlled by Scott J. Reiman.  Mr. Reiman is President of Hexagon Investments.(3)
Edward Mike Davis has sole voting control over Edward Mike Davis, L.L.C.(4)
Includes (i) 1,666,667 shares owned by Steven B Dunn, (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) 333,333 shares owned by Steven B Dunn custodian for Steven W Dunn, (iv) and (iv) 333,333 shares underlying warrants held by Steven B Dunn custodian for Steven W Dunn for $1.50 per share exercisable at any time through May 23, 2015.(5)
Includes (i) 3,333,333 shares owned by JMB Capital Partners Master Fund, L.P. and (ii) 3,333,333 shares underlying warrants held by JMB Capital Partners Master Fund, L.P. for $1.50 per share exercisable at any time through May 23, 2015.(6)
Includes (i) 1,920,000 shares owned by J. Steven Emerson Roth IRA Pershing LLC as Custodian, (ii) 1,280,000 shares underlying warrants held by J. Steven Emerson Roth IRA Pershing LLC as Custodian for $1.50 per share exercisable at any time through May 23, 2015, (iii) 720,000 shares owned by J. Steven Emerson IRA RO II Pershing  LLC as Custodian, (iv) 330,000 shares underlying warrants held by J. Steven Emerson IRA RO II Pershing  LLC as Custodian for $2.20 per share exercisable at any time through September 29, 2015, (v) 300,000 shares owned by J. Steven Emerson, (vi) 200,000 shares underlying warrants held by J. Steven Emerson for $1.50 per share exercisable at any time through May 23, 2015, (vii) 240,000 shares owned by Emerson Family Foundation, (viii) 160,000 shares underlying warrants held by Emerson Family Foundation for $1.50 per share exercisable at any time through May 23, 2015.


Item 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE





Transactions with Related Persons





During fiscal year 2010 through March 31, 2011, 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 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.  51
 Table of Contents
  ●
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. Included in the acquisition were six producing wells and interests in 1240 acres.●
Approximately 60,000 acres located in Banner and Kimball Counties, Nebraska and Laramie and Goshen Counties, Wyoming acquired in May, 2010 for $20,000,000 cash and 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.  These properties were undeveloped with no proved reserves or production. The purchase price was $8,000,000 in cash which was due to the sellers on or before December 20, 2010.  We issued 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.  52
 Table of Contents
  ·
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.







53
 Table of Contents
  Item 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
 We expect that a representative of Hein & Associates will be present at the annual meeting and available to respond to appropriate questions from our stockholders. The representative will have an opportunity to make a statement to the stockholders if the representative desires to do so.




Webb & Company was our independent registered public accounting firm in 2008 and until September 21, 2009.  Jewett Schwartz Wolfe & Associates was our independent registered public accounting firm from September 21, 2009 until January 19, 2010.  Hein & Associates became our independent registered public accounting firm on January 19, 2010.  There were no disagreements on any matter of accounting principles or practices, financial statement disclosures or auditing scope or procedures, which disagreements if not resolved to their satisfaction would have caused either Webb & Company or Jewett Schwartz to make reference thereto in their respective opinions.




The following table sets forth fees billed by our principal accounting firm of Hein & Associates, LLP for the years ended December 31, 2010 and 2009:




Year Ended December 31,2010


2009Audit Fees

$
169,265


$
42,863Audit Related Fees


-



-Tax Fees


10,350



-All Other Fees


26,550



-$
206,165


$
42,863





54
 Table of Contents





PART IV


Item 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES





INDEX TO FINANCIAL STATEMENTS




a)





Report of Independent Registered Public Accounting Firm

F-1Consolidated Balance Sheets

F-2Consolidated Statements of Operations

F-4Consolidated Statements of Shareholders' Equity

F-5Consolidated Statements of Cash Flows

F-6Notes to Financial Statements

F-8




55
 Table of Contents


b) Financial statement schedules





Not applicable.





c) Exhibits





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





2.1
Membership Unit Purchase Agreement by and among Recovery Energy, Lanny M. Roof, Judith Lee and Michael Hlvasa dated as of September 21, 2009 (incorporated herein by reference to Exhibit 2.1 from our current report filed on form 8-K filed on September 22, 2009).
 3.1
Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to Company's form S-1 filed on July 28, 2008).3.2
Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to Company's periodic report on form 8-K filed on June 18, 2010).4.1
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).10.1
Cancellation agreements, dated September 21, 2009 between Universal Holdings, Inc. and two former shareholders.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).
  56
 Table of Contents
  10.13
Purchase and Sale Agreement with Edward Mike Davis, L.L.C. dated effective as of April 1, 2010 (incorporated herein by reference to Exhibit 10.16 to Company's current report filed on form 8-K filed on March 25, 2010).10.14
Credit Agreement with Hexagon Investments, LLC dated effective as of March 25, 2010 (incorporated herein by reference to Exhibit 10.17 to Company's current report filed on form 8-K filed on March 25, 2010).10.15
Promissory Note for financing with Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.18 to Company's current report filed on form 8-K filed on March 25, 2010).10.16
Nebraska Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.19 to Company's current report filed on form 8-K filed on March 25, 2010).10.17
Wyoming Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.20 to Company's current report filed on form 8-K filed on March 25, 2010).10.18
Purchase and Sale Agreement with Edward Mike Davis, L.L.C. for purchase of oil and gas properties dated as of April 1, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on April 20, 2010).10.19
Credit Agreement with Hexagon Investments, LLC dated as of April 14, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on April 20, 2010).10.20
Promissory Note with Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on April 20, 2010).10.21
Warrant to Purchase Common Stock by Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.4 to the Company's current report filed on form 8-K filed on April 20, 2010).10.22
Wyoming Mortgage to Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.5 to the Company's current report filed on form 8-K filed on April 20, 2010).10.23
Securities Purchase Agreement dated as of April 26, 2020 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on April 30, 2010).10.24
Agreement with C.K. Cooper dated April 8, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on May 4, 2010).10.25
Purchase Agreement dated May 6, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on May 12, 2010).10.26
Promissory Note dated May 6, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on May 12, 2010).10.27
Security Agreement dated May 6, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on May 12, 2010).10.28
Purchase Agreement with Edward Mike Davis, L.L.C. and Spottie, Inc. dated May 15, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on May 20, 2010).
  57
 Table of Contents
  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-K10.36
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).
  58
 Table of Contents
  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.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).23.2
Consent of RE Davis.31.1
Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 200231.2
Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 200232.1
Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 200232.2
Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 200299.1
Report of RE Davis.




59
 Table of Contents


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.




As discussed in Note 16 to the consolidated financial statements, the 2010 consolidated financial statements have been restated to correct a misstatement.




/s/ HEIN & ASSOCIATES LLP





Denver, Colorado





March 31, 2011, except for Note 16 for which the date is July 22, 2011





F-1
 Table of Contents





RECOVERY ENERGY, INC.


CONSOLIDATED BALANCE SHEETS





December 31


December 312010 (Restated)


2009AssetsCurrent Assets:Cash

$
5,528,744


$
108,400Restricted Cash


1,150,541



20,876Accounts Receivable


857,554



100,000Prepaid assets


27,772



55,249Total current assets


7,564,611



284,525Oil 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



470Prepaid advisory fees


979,449



-Deferred financing costs


3,211,566



-Restricted cash and deposits


185,707



110,031Assets held for sale


-



500,000Total other assets


4,432,958



610,501Total Assets

$
68,121,929


$
895,026





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




F-2
 Table of Contents




Table of Contents





RECOVERY ENERGY, INC.


CONSOLIDATED BALANCE SHEETS





December 31


December 312010 (Restated)


2009Liabilities and Shareholders' EquityCurrent Liabilities:Accounts payable

$
968,295


$
106,355Liabilities from price risk management


398,840



-Related Party Payable


11,638



70,876Common Stock Issuable


-



100,000Accrued expenses


1,540,592



51,523Short term note


208,881



-Total current liabilities


3,128,246



328,754Asset retirement obligation


507,280



-Term notes


20,229,801



-Total long term liabilities


20,737,081



-Total Liabilities


23,865,327



328,754Common Stock Subject to Redemption Rights, $0.0001 par value;


86,258



172,51642,500 and 85,000 shares issued and outstanding as of December 31, 2010 and 2009Other 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



1,077Additional Paid in Capital


93,814,977



30,304,060Accumulated deficit


(49,650,414
)


(29,911,381
)Total other shareholders' equity


44,170,344



393,756Total 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.




F-3
 Table of Contents




Table of Contents





RECOVERY ENERGY, INC.


CONSOLIDATED STATEMENTS OF OPERATIONS





Year Ended


March 6, 2009December 31, 2010 (Restated)


(Inception) through

December 31, 2009Revenue: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 $13,097,346 and $684,778 for the periods ended December 31, 2010 and 2009)


15,530,248



1,057,306Depreciation, depletion and amortization


5,036,648



-Impairment of equipment


-



2,750,000Bad debt expense


400,000



-Fair value of common stock and warrants issued in aborted property acquisitions


-



8,404,106Restructuring and related consulting costs


-



17,700,000Total costs and expenses


22,885,182



29,911,412Loss from operations


(13,127,490
)


(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
)

$
31Net Loss

$
(19,739,033
)

$
(29,911,381
)Earnings per common shareBasic  and Diluted

$
(0.54
)

$
(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.




F-4
 Table of Contents




Table of Contents


RECOVERY ENERGY, INC.


CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY


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





Other Shareholders' EquityCommon Stock Subject








Additionalto Redemption


Common Stock


Paid-In


AccumulatedShares


Amount


Shares


Amount


Capital


Deficit


TotalBalance, 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



-



3,250,000Common stock issued in lock-up agreement


85,000



172,516



-



-



-



-



-Common stock issued in restructuring


-



-



5,000,000



500



17,499,500



-



17,500,000Common stock issued in attempted acquisition


-



-



1,700,000



170



5,824,830



-



5,825,000Common stock issued for cash


-



-



125,000



12



499,988



-



500,000Restricted stock and performance options issued to employees and directors


-



-



-



-



684,778



-



684,778Warrants issued for financing commitment


-



-



-



-



3,329,106



-



3,329,106Common 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
)


393,756Common stock issued for property acquisitions


-



-



11,716,667



1,172



15,786,328



-



15,787,500Common stock issued in connection with financing property acquisitions


-



-



5,000,000



500



5,249,500



-



5,250,000Common stock issued for cash


-



-



15,915,154



1,592



14,924,142



-



14,925,734Common stock issued for services


-



-



2,008,862



201



2,256,038



-



2,256,239Restricted stock issued to employees and directors


-



-



8,943,187



894



8,375,326



-



8,376,220Warrants exercised for cash


-



-



3,414,000



341



5,120,658



-



5,120,999Warrants issued for cash, services and fees


-



-



-



-



11,712,671



-



11,712,671Common stock no longer subject to redemption


(42,500)



(86,258)



42,500



4



86,254



-



86,258Net loss


-



-



-



-



-



(19,739,033
)


(19,739,033
)Balance, December 31, 2010


42,500


$
86,258



57,814,369


$
5,781


$
93,814,977


$
(49,650,414
)

$
44,170,344





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




F-5
 Table of Contents





Table of Contents





RECOVERY ENERGY, INC.


CONSOLIDATED STATEMENTS OF CASH FLOWS





Year Ended

December 31, 2010 (Restated)


March 6, 2009

(inception) through

December 31, 2009Cash flows from operating activities:Net loss

$
(19,739,033
)

$
(29,911,381
)Adjustments to reconcile net loss to net cash provided by operating activities:Impairment


-



2,750,000Bad debt expense


400,000



-Stock issued for services


325,043



-Stock based compensation


8,376,220



884,778Warrant modification expense


2,953,450



-Fair value of warrants issued


-



3,329,106Non-cash restructuring costs


-



17,500,000Loss on aborted property acquisitions


-



5,075,000Changes 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



72,469Restricted cash


(1,129,665
)


(20,876
)Related party production payments


(69,312
)


70,876Accrued expenses


1,489,068



24,038Net 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



1,500,000Sale of drilling rigs


100,000



-Additions of property and equipment


(55,766
)


(750,470
)Cash acquired in acquisition






140Investment in operating bonds


(75,675
)


(110,031
)Net cash provided by (used in) investing activities


(46,809,757
)


639,639Cash flows from financing activities:Proceeds from sale of common stock, units and exercise of warrants


28,132,727



500,000Proceeds from debt issuance


28,500,000



-Common stock reacquired in attempted Church acquisition


-



(750,000
)Common stock issuable


(100,000
)


100,000Repayment 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



108,400Cash 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.




F-6
 Table of Contents





Table of Contents





RECOVERY ENERGY, INC.


CONSOLIDATED STATEMENTS OF CASH FLOWS





Supplemental disclosure of non-cash investing and financing activities:

Year Ended

December 31, 2010 (Restated)


March 6, 2009

(inception) through December 31, 2009Cash paid for interest

$
2,655,131


$
-Cash paid for income taxes

$
-


$
-Non-cash transactions:Purchase of rigs for note payable

$
-


$
3,250,000Purchase of properties for note payable and common stock

$
15,787,500


$
8,025,000Stock 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.




F-7
 Table of Contents




Table of Contents





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.





F-8
 Table of Contents




Table of Contents





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.





F-9
 Table of Contents




Table of Contents





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.





F-10
 Table of Contents




Table of Contents





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

$
405,2892012


405,2892013


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.





F-11
 Table of Contents




Table of Contents





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.





F-12
 Table of Contents





Table of Contents





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


478,208Retirements


-Accretion expense


28,042Change in estimate


1,030December 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.





Warrant Modification Expense





The Company accounts for the modification of warrants in accordance with the provisions of ASC 718— Stock Compensation which requires companies to treat a modification as an exchange of the old award for a new award. The incremental value is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a period expense or amortized over the performance or vesting date. We estimate the incremental value of each warrant using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree of subjective judgment is the estimated volatility of our stock price.





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.





F-13
 Table of Contents




Table of Contents





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.





F-14
 Table of Contents




Table of Contents





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.





F-15
 Table of Contents




Table of Contents





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 FieldConsideration given:Cash payment funded by debt

$
4,500,000


$
6,000,000


$
15,000,000Stock


-



412,500



1,875,000Total consideration attributable to allocation

$
4,500,000


$
6,412,500


$
16,875,000Allocation of purchase price:Proved oil and gas properties

$
4,418,267


$
4,675,099


$
15,529,268Unproved oil and gas properties


83,200



1,791,619



1,070,975Total fair value of oil and gas properties acquired


4,501,467



6,466,718



16,600,243Oil and gas revenue receivable


195,594



-



-Total assets


4,697,061



6,466,718



16,600,243Accounts 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


$
16,398,945Supplemental 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
)





F-16
 Table of Contents




Table of Contents





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 EndedDecember 31,2010


2009(Unaudited)


(Unaudited)Operating revenues

$
12,941,108


$
6,070,500Operating loss

$
(10,599,304
)

$
(29,001,745
)Net loss

$
(19,063,015
)

$
(33,489,536
)Pro forma loss per common share:Basic and diluted

$
(0.52
)

$
(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.





F-17
 Table of Contents




Table of Contents





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 YearPrior (1)

$
-2008 (1)


-2009 (1)


-2010


33,605,727Total

$
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.





F-18
 Table of Contents




Table of Contents





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

quarter
Barrels per

Day
Price per

Barrel2011First quarter


18,900



210


$
85.25Second quarter


9,900



110


$
85.97Third quarter


9,900



110


$
84.95Fourth 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



2009Realized 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.




F-19
 Table of Contents




Table of Contents





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

TotalLiabilityCommodity 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.




F-20
 Table of Contents




Table of Contents





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.





F-21
 Table of Contents




Table of Contents





RECOVERY ENERGY, INC.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





NOTE 7 - LOAN AGREEMENTS (Continued)





Annual Amortization of Deferred Financing Costs:





2011

$
1,764,0192012

$
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.




F-22
 Table of Contents




Table of Contents





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


2009Deferred tax assets:Oil and gas properties and equipment

$
(1,335,490
)

$
1,045,275Net operating loss carry-forward


7,285,426



2,670,740Share based compensation


3,902,007



1,022,045Abandonment obligation


188,728



-Derivative instruments


148,384



-Other


(30,896
)


4,386Total deferred tax asset


10,158,159



4,742,446Valuation 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

2009Effective federal tax rate

35.00%


35.00%Effect of permanent differences

(21.78)%


(20.40)%State tax rate

2.20%


3.01%Change in rate

(0.23)%


0.00%Other

3.07%


(1.76)%Valuation allowance

(18.26)%


(15.85)%Net

0%


0%





F-23
 Table of Contents




Table of Contents





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. 3,414,000 of these warrants were subsequently exercised during 2010 for $5,121,000 of cash. In connection with the exercise, the Company granted a new warrant for each warrant exercised. The new warrants have an exercise price of $2.20 per share, which was slightly greater than the concurrent market price of the Company's common stock, and expire on September 29, 2015. The value of the new warrants, calculated at $2,953,450 using the Black Scholes method, was expensed as a warrant modification and included in general and administrative expenses (See Note 16).





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 restructuring 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.





F-24
 Table of Contents




Table of Contents





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

$
140Accounts 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

$
29,977,280Earnings (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.




F-25
 Table of Contents




Table of Contents





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-AverageShares

Exercise PriceOutstanding at March 6, 2009


-



-Granted


750,000


$
3.50Exercised, forfeited, or expired


-



-Outstanding at December 31, 2009


750,000


$
3.50Exercisable at December 31, 2009


750,000


$
3.50Granted


25,720,933


$
1.67Exercised, forfeited, or expired


(3,414,000
)


1.50Outstanding at December 31, 2010


23,056,933


$
1.76Exercisable 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


2009Weighted-average volatility


80
%


230
%Expected dividends


0.00
%


0.00
%Expected term (in years)


3 – 5



3Risk-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).




F-26
 Table of Contents




Table of Contents





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:





SharesRestricted Stock Grants Outstanding at March 6, 2009


-Granted


1,484,200Vested


-Outstanding at December 31, 2009


1,484,200Granted


7,458,987Vested


-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.





F-27
 Table of Contents




Table of Contents





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 undeveloped oil and gas leases 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 undeveloped 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.




F-28
 Table of Contents





Table of Contents





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



323,493Sale of reserves


-



-Production


(133,709
)


(14,914
)December 31, 2010


692,388



308,579Proved Developed Reserves, included above:Balance, December 31, 2008


-



-Balance, December 31, 2009


-



-Balance, December 31, 2010


277,669



308,579Proved 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.





F-29
 Table of Contents





Table of Contents





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.





F-30
 Table of Contents




Table of Contents





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.





F-31
 Table of Contents




Table of Contents





RECOVERY ENERGY, INC.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





NOTE 16- REVISION TO FINANCIAL STATEMENTS





The financial statements as of December 31, 2010 and for the year then ended, are revised to incorporate additional general and administrative expense relating to warrant modification expense of $2,953,450 during the year ended December 31, 2010, following further analysis of modifications to the Company’s then outstanding warrants.





During September 2010, the Company made a temporary offer to all warrant holders who had received a warrant as part of the unit offering that was closed in May 2010. For all warrant holders who exercised their warrant during September, the Company would grant that warrant holder with a replacement warrant with a $2.20 exercise price. The closing price of the Company’s stock on the offering date was $2.05. A recent analysis of this 2010 transaction determined that the $2,953,450 increase in the value of the exercised warrants should be categorized as a current period warrant modification expense, as opposed to being categorized as an equity cost and netted out of gross proceeds in additional paid in capital. The increase in warrant value was calculated using the Black Scholes method of valuation and included as a period expense in general and administrative expense. The assumptions used in the calculation were as follows: volatility – 50%, dividends expected – 0%, expected term – 5 years, and risk free interest rate – 1.28%.





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





Year Ended December 31, 2010Prior to Restatement


RestatedConsolidated Balance Sheet:Additional Paid in Capital
$
90,861,527


$
93,814,977Accumulated Deficit

(46,696,964
)


(49,650,414
)Consolidated Statement of Operations:General and Administrative

12,576,798



15,530,248Total Costs and Expenses

19,931,732



22,885,182Loss from Operations

(10,174,040
)


(13,274,490
)Net Loss

(16,785,583
)


(19,739,033
)Earnings per Common Share: Basic and Diluted

(0.46
)


(0.54
)Consolidated Statement of Cash Flows:Net Loss

(16,785,583
)


(19,739,033
)Adjustment for Warrant Modification Expense

-



2,953,450Net Cash Provided by Operating Activities

3,758,694



3,758,694




F-32
 Table of Contents




SIGNATURES





Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.








RECOVERY ENERGY INCDate: August 12, 2011
By:
/s/ Roger A ParkerRoger A. ParkerPresident, Chief Executive Officer and Chairman of the Board of Directors

(Authorized Signatory)





Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and the capacities and on the dates indicated.





Signature

Title

Date/s/ Roger A. Parker

President, Chief Executive Officer and Chairman of

August 12, 2011Roger A Parker

the Board of Directors/s/ A. Bradley Gabbard

Chief Financial and Accounting Officer

August 12, 2011A. Bradley Gabbard/s/ James J Miller

Director

August 12, 2011James J Miller/s/ Conway Schatz

Director

August 12, 2011Conway Schatz/s/ Tim Poster

Director

August 12, 2011Tim Poster






F-32