f10k2010_recovery.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
 
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:  (888) 887-4449

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 o
 
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 o
  
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  o 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
o
Non-accelerated filer   
o
Smaller reporting company
x
 
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  oNo o
 
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 registrant’s most recently completed fiscal quarter:  $66,860,959.

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

DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the registrant’s definitive proxy statement for its Annual Meeting of Stockholders for 2011 to be filed with the Commission within 120 days after the close of its fiscal year are incorporated by reference into Part III hereof.
 
 
 
 
 
FORM 10-K ANNUAL REPORT
FISCAL YEAR ENDED DECEMBER 31, 2010
RECOVERY ENERGY INC

Item
 
Page
PART I
     
  4
  20
  29
  29
 29
     
PART II
     
  30
  31
  31
  38
  38
  38
  39
  40
     
PART III
     
 41
 41
 41
 41
 41
     
 
PART IV
 
     
  42

 
 
 
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 copy of this annual report on Form 10-K 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. Since January 1, 2010 we have acquired and developed 19 producing wells. We currently own 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.
 

 
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.
 
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.
 
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 are operating one drilling rig on our acreage, which is focusing 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.
 
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.
 
   
As of December 31,
 
   
2010
   
2009 (1)
   
2008 (1)
 
Reserve data:
                 
Proved developed
                 
Oil (MBbl)
    278       -       -  
Gas (MMcf)
    308       -       -  
MBOE
    329       -       -  
Proved undeveloped
                       
Oil (MBbl)
    415       -       -  
Gas (MMcf)
    -       -       -  
MBOE
    415       -       -  
Total Proved
                       
Oil (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

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. 

 
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 production
                 
Oil (MMBbl)
    133.709       -       -  
Gas (MMcf)
    14.914       -       -  
MBOE
    136.195       -       -  
Average net daily production
                       
Oil (Bbl)
    366       -       -  
Gas (Mcf)
    41       -       -  
BOE
    373       -       -  
Average realized sales price, excluding the effects of our economic hedges
                       
Oil (per Bbl)
  $ 71.08     $ -     $ -  
Gas (per Mcf)
  $ 4.56     $ -     $ -  
Per BOE
  $ 70.29     $ -     $ -  
Average realized sales price, including the effects of our economic hedges
                       
Oil (per Bbl)
  $ 75.27     $ -     $ -  
Gas (per Mcf)
  $ 4.56     $ -    
$
-  
Per BOE
 
$
74.47     $ -     $ -  
Production costs per BOE
                       
Lease operating expense (2)
  $ 6.33     $ -     $ -  
DD&A
  $ 36.98     $ -     $ -  
Production taxes
  $ 7.76     $ -     $ -  
                         
 
(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
 
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.

 
Our Drilling Activity

All of our drilling activities are conducted on a contract basis with independent drilling contractors. We do not own any drilling equipment. The following table summarizes the number of wells drilled and recompleted in 2010, 2009, and 2008, excluding any wells with only a royalty interest ownership:

   
For the Year Ended December 31,
 
   
2010
   
2009 (1)
   
2008 (1)
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
Development:
                                   
Oil
    1.00       0.76       -       -       -       -  
Gas
    1.00       0.63       -       -       -       -  
Non-productive
    1.00       0.67       -       -       -       -  
      3.00       2.06       -       -       -       -  
Exploratory:
                                               
Oil
    -       -       -       -       -       -  
Gas
    -       -       -       -       -       -  
Non-productive
    -       -       -       -       -       -  
      -       -       -       -       -       -  
Farm-out or non-consent
    -       -       -       -       -       -  
Total
    3.00       2.06       -       -       -       -  
                                                 
(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.  Subsequent to December 31, 2010 we drilled 2 gross (2.0 net) wells. One of the wells was plugged and abandoned and the second was temporarily abandoned.

Our Leaseholds

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.

Recovery Leaseholds in the DJ Basin

The following table sets forth the gross and net acres of developed and undeveloped oil and gas leasehold, fee properties, mineral servitudes, and lease options held by us as of December 31, 2010. Undeveloped acreage includes leasehold interests that may already have been classified as containing proved undeveloped reserves.
 
   
Developed Acres (1)
   
Undeveloped Acres (2)
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                     
Colorado
    1,840       1,040       -       -       1,840       1,040  
Nebraska
    600       560       61,392       58,674       61,922       59,234  
Wyoming
    1,280       1,280       68,936       55,266       70,216       56,546  
Total  (3)
    3,720       2,880       130,328       113,940       133,978       116,820  
 
(1)
Developed acreage is acreage assigned to producing wells.  Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above.
(2)
Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether such acreage contains estimated reserves.
(3)
Subsequent to December 31, 2010, we acquired additional properties, which included leases covering approximately 40 and 10 gross and net developed acres, respectively, and approximately 21,000 and 17,000 gross and net undeveloped acres, respectively.

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
 
We have 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.

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 the date of this report, 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.
 
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:
 
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.”

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

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

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

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

To date we have not experienced any materially adverse effect on our operations from obligations under environmental, health, and safety laws and regulations.  We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and that continued compliance with existing requirements would not have a materially adverse impact on us.
 
 
Glossary of Oil and Natural Gas Terms
 
The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.
 
bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
 
Bcf. Billion cubic feet of natural gas.
 
boe. Barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
boe/d. boe per day.
 
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
 
Condensate. Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons.
 
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
 
Drilling locations. Total gross locations specifically quantified by management to be included in our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
 
Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
 
Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
 
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
Formation. An identifiable layer of rocks named after its geographical location and dominant rock type.
 
Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.
 
Leasehold. Mineral rights leased in a certain area to form a project area.
 
Mbbls. Thousand barrels of crude oil or other liquid hydrocarbons.
 
Mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

Mcf. Thousand cubic feet of natural gas.
 
Mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
MMbbls. Million barrels of crude oil or other liquid hydrocarbons.
 
MMboe. Million barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
MMbtu. Million British Thermal Units.
 
MMcf. Million cubic feet of natural gas.
 
Net acres, net wells, or net reserves. The sum of the fractional working interest owned in gross acres, gross wells, or gross reserves, as the case may be.
 
Net barrel of production. The sum of the fractional revenue interest in gross production owned by the company.
 ngl. Natural gas liquids, or liquid hydrocarbons found in association with natural gas.
 
Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.
 
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
 
Present value of future net revenues (PV-10). The present value of estimated future revenues to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using the simple 12 month first of month average price and current costs (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of Recovery Energy on a comparative basis to other companies and from period to period.
 
Production. Natural resources, such as oil or gas, taken out of the ground.
 
Proved reserves. The quantities of oil, natural gas and natural gas liquids, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs under existing economic conditions and operating conditions.
 
Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
 
Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. 
  
Probable Reserves. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P estimate.

Possible Reserves. Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10-percent probability that the actual quantities recovered will equal or exceed the 3P estimate.
 
Productive well. A well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
 
Project. A targeted development area where it is probable that commercial gas can be produced from new wells.
 
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
 
Recompletion. The process of re-entering an existing well bore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
 
Reserves. Oil, natural gas and gas liquids thought to be accumulated in known reservoirs.
 
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible nature gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
 
Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.
 
Shut-in. A well that has been capped (having the valves locked shut) for an undetermined amount of time. This could be for additional testing, could be to wait for pipeline or processing facility, or a number of other reasons.
 
Standardized measure. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
 
Successful. A well is determined to be successful if it is producing oil or natural gas, or awaiting hookup, but not abandoned or plugged.
 
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
 
Water flood. A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery.
 
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
 

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 $46 million. While we have developed some of our properties, many of our properties are in the exploration stage, and to date we have established a limited volume of proved reserves on our properties. Our ability to be profitable in the future will depend on successfully implementing our acquisition, exploration, development and production activities, all of which are subject to many risks beyond our control. We cannot assure you that we will successfully implement our business plan or that we will achieve commercial profitability in the future. Even if we become profitable on an annual basis, we cannot assure you that our profitability will be sustainable or increase on a periodic basis. In addition, should we be unable to continue as a going concern, realization of assets and settlement of liabilities in other than the normal course of business may be at amounts significantly different from those in the financial statements included in this annual report.

We will require additional capital in order to achieve commercial success and, if necessary, to finance future losses from operations as we endeavor to build revenue, but we do not have any commitments to obtain such capital and we cannot assure you that we will be able to obtain adequate capital as and when required. The business of oil and gas acquisition, drilling and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. We believe that our ability to achieve commercial success and our continued growth will be dependent on our continued access to capital either through the additional sale of our equity or debt securities, bank lines of credit, project financing, joint ventures or cash generated from oil and gas operations.
 
Currently, the majority of our revenue after field level operating expenses is required to be paid to our lender as debt service. As of 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 is restricted cash. We will seek to obtain additional capital through the sale of our securities, the successful deployment of our cash on hand, bank lines of credit, joint ventures, and project financing. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price could be materially adversely affected.
 
 
We do not have a significant operating history and, as a result, there is a limited amount of information about us on which to make an investment decision. In January 2010, we acquired our first oil and gas prospects and received our first revenues from oil and gas production in February 2010. Accordingly, there is little operating history upon which to judge our business strategy, our management team or our current operations.
 
We have a history of losses and cannot assure you that we will be profitable in the foreseeable future. At December 31, 2010, we have incurred a net loss from inception of approximately $46 million. If we fail to generate profits from our operations, we may not be able to sustain our business. We may never report profitable operations or generate sufficient revenue to maintain our company as a going concern.

We have limited management and staff and will be dependent upon partnering arrangements. We have eight employees. We intend to use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We will also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:
 
the possibility that such third parties may not be available to us as and when needed; and
the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.
 
If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price could be materially adversely affected.
 
The loss of one of our officers could adversely affect us. We are dependent on the extensive experience of our chief executive officer and our president and 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.
 
 
The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, the present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. This annual report contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves. The December 31, 2010, reserve estimate was prepared by our Senior Reserve Engineer and audited by RE Davis. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development and operating expenses, and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control. You should also not assume that our initial rates of production of our wells will lead to greater overall production over the life of the wells, or that early results suggesting lack of reservoir continuity will prove to be accurate.
 
 You should not assume that the present value of future net revenues referred to in this annual report is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the un-weighted average of the closing prices during the first day of each of the twelve months preceding the end of the fiscal year. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any change in consumption by oil or natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of our oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor nor does it reflect discount factors used in the market place for the purchase and sale of oil and natural gas.
 
Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.   One of our growth strategies is to pursue selective acquisitions of undeveloped leaseholder oil and natural gas reserves. If we choose to pursue an acquisition, we will perform a review of the target properties that we believe is consistent with industry practices. However, these reviews are inherently incomplete. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties.
 
Our large inventory of undeveloped acreage and large percentage of undeveloped proved reserves may create additional economic risk.  Our success is largely dependent upon our ability to develop our large inventory of future drilling locations, undeveloped acreage and undeveloped reserves. As of December 31, 2010, approximately 56% of our total proved reserves were undeveloped. To the extent our drilling results are not as successful as we anticipate, natural gas and oil prices decline, or sufficient funds are not available to drill these locations and reserves, we may not capture the expected or projected value of these properties. In addition, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.

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

Our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas. If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties, negatively impacting the trading value of our securities. There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. We follow the full cost method of accounting for oil and gas operations whereby all costs related to exploration and development of oil and gas properties are initially capitalized into a single cost center, known as a full cost pool. We record all capitalized costs into a single cost center as all operations are conducted within the United States. Such costs include land acquisition costs, geological and geophysical expenses, carry charges on non-producing properties, and costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.
 
 
Additional write downs could occur if oil and gas prices decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results.
 
All of our producing properties and operations are located in the DJ Basin region, making us vulnerable to risks associated with operating in one major geographic area.  All of our estimated proved reserves at December 31, 2010, and our 2010 sales were generated in the DJ Basin in southeastern Wyoming, northeastern Colorado and southwestern Nebraska. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the DJ Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

Unless we find new oil and gas reserves, our reserves and production will decline, which would materially and adversely affect our business, financial condition and results of operations. Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Thus, our future oil and gas reserves and production and, therefore, our cash flow and revenue are highly dependent on our success in efficiently obtaining reserves and acquiring additional recoverable reserves. We may not be able to develop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would be materially and adversely affected.
 
Part of our strategy involves drilling in existing or emerging shale plays using available horizontal drilling and completion techniques. The results of our planned exploratory and development drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.  Operations in the Niobrara shale involve utilizing drilling and completion techniques as developed by ourselves and our service providers. Risks that we face while drilling include, but are not limited to, landing our wellbore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the wellbore and being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the wellbore during completion operations and successfully cleaning out the wellbore after completion of the final fracture stimulation stage.
 
Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Niobrara is limited. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

The unavailability or high cost of drilling rigs, equipment supplies or personnel could adversely affect our ability to execute our exploration and development plans. The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. The higher prices of oil and gas during the last several years have resulted in shortages of drilling rigs, equipment and personnel, which have resulted in increased costs and shortages of equipment in the areas where we operate. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our financial condition and results of operations could be materially and adversely affected.
 
 
Covenants in our credit agreements impose significant restrictions and requirements on us. Our three credit agreements contain a number of covenants imposing significant restrictions on us, including restrictions on our repurchase of, and payment of dividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets and create liens on our assets. These restrictions may affect our ability to operate our business, to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial conditions and results of operations.
 
Our credit agreements mature on September 1, 2012, and our lender can foreclose on several of our properties if we do not pay off or refinance our approximately $20.1 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.
 
We are exposed to operating hazards and uninsured risks. Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:
 
fire, explosions and blowouts;
pipe failure;
abnormally pressured formations; and
environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment
      (including groundwater contamination).
 
These events may result in substantial losses to us from:
 
injury or loss of life;
severe damage to or destruction of property, natural resources and equipment;
pollution or other environmental damage;
clean-up responsibilities;
regulatory investigation;
penalties and suspension of operations; or
attorney's fees and other expenses incurred in the prosecution or defense of litigation.
 
We maintain insurance against some, but not all, of these risks. We cannot assure you that our insurance will be adequate to cover these losses or liabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations.
 
The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions and weather conditions. These curtailments can last from a few days to many months.
 
We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.  We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:
  
recoverable reserves;
  
future oil and natural gas prices and their appropriate differentials;
  
development and operating costs; and
  
potential environmental and other liabilities.
 
        The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.
 
 
        Significant acquisitions and other strategic transactions may involve other risks, including:
  
diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
  
challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;
  
difficulty associated with coordinating geographically separate organizations;
  
challenge of attracting and retaining personnel associated with acquired operations; and
  
failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.
 
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

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

Our reserve estimates will depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of reserves shown in these reports.
 
In order to prepare reserve estimates in its reports, our independent petroleum consultant projected production rates and timing of development expenditures. Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary and may not be in our control. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
 
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
 

Risks Relating to the Oil and Gas Industry
 
Oil and natural gas prices are highly volatile and have declined significantly since mid 2008, and lower prices will negatively affect our financial condition, planned capital expenditures and results of operations. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following:
 
changes in global supply and demand for oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries, or OPEC;
the price and quantity of imports of foreign oil and natural gas;
acts of war or terrorism;
political conditions and events, including embargoes, affecting oil-producing activity;
the level of global oil and natural gas exploration and production activity;
the level of global oil and natural gas inventories;
weather conditions;
technological advances affecting energy consumption;
the price and availability of alternative fuels; and
market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives.
 
Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.
 
Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas, that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.
 
Our industry is highly competitive which may adversely affect our performance, including our ability to participate in ready to drill prospects in our core areas. We operate in a highly competitive environment. In addition to capital, the principal resources necessary for the exploration and production of oil and natural gas are:
  
leasehold prospects under which oil and natural gas reserves may be discovered;
drilling rigs and related equipment to explore for such reserves; and
knowledgeable personnel to conduct all phases of oil and natural gas operations.
 
We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these competitors have financial and other resources substantially greater than ours. We cannot assure you that such materials and resources will be available when needed. If we are unable to access material and resources when needed, we risk suffering a number of adverse consequences, including:
 
the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests;
loss of reputation in the oil and gas community;
a general slow down in our operations and decline in revenue; and
decline in market price of our common shares.
 
 
Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.  In December 2009, the EPA determined that emissions of carbon dioxide, methane and other ‘‘greenhouse gases’’ present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act, or CAA.  The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011.  The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
 
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances.  The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
 
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements.  Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs, and natural gas we produce.  Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.  Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
  
We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business. Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, and operating safety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may result in substantial penalties and harm to our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:
 
land use restrictions;
lease permit restrictions;
drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds;
spacing of wells;
unitization and pooling of properties;
safety precautions;
operational reporting; and
taxation.
 
Under these laws and regulations, we could be liable for:
 
personal injuries;
property and natural resource damages;
well reclamation cost; and
governmental sanctions, such as fines and penalties.
 
Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is also possible that a portion of our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See “Government Regulations” for a more detailed description of our regulatory risks.
 
 
Our operations may incur substantial expenses and resulting liabilities from compliance with environmental laws and regulations. Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:
 
require the acquisition of a permit before drilling commences;
restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and
      production activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
impose substantial liabilities for pollution resulting from our operations.
 
Failure to comply with these laws and regulations may result in:
 
the assessment of administrative, civil and criminal penalties;
incurrence of investigatory or remedial obligations; and
the imposition of injunctive relief.
 
Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Our permits require that we report any incidents that cause or could cause environmental damages. See “Business—Government Regulations” for a more detailed description of our environmental risks.
 
Risks Relating to our Common Stock
 
There is no active public market for our shares and we cannot assure you that all active trading market or a specific share price will be established or maintained. Our common stock trades on the OTC BB trading system. The OTC BB tends to be highly illiquid, in part because there is no national quotation system by which potential investors can track the market price of shares except through information received or generated by a limited number of broker-dealers that make markets in particular stocks. There is a greater chance of market volatility for securities that trade on the OTC BB as opposed to a national exchange or quotation system. This volatility may be caused by a variety of factors including:
 
 
the lack of readily available price quotations;
 
the absence of consistent administrative supervision of “bid” and “ask” quotations;
 
lower trading volume; and
 
market conditions.
 
In addition, the value of our common stock could be affected by:
 
 
actual or anticipated variations in our operating results;
 
changes in the market valuations of other oil and gas companies;
 
announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;
 
adoption of new accounting standards affecting our industry;
 
additions or departures of key personnel;
 
sales of our common stock or other securities in the open market;
 
changes in financial estimates by securities analysts;
 
conditions or trends in the market in which we operate;
 
changes in earnings estimates and recommendations by financial analysts;
 
our failure to meet financial analysts’ performance expectations; and
 
other events or factors, many of which are beyond our control.
 
In a volatile market, you may experience wide fluctuations in the market price of our securities. These fluctuations may have an extremely negative effect on the market price of our securities and may prevent you from obtaining a market price equal to your purchase price when you attempt to sell our securities in the open market. In these situations, you may be required either to sell our securities at a market price which is lower than your purchase price, or to hold our securities for a longer period of time than you planned. An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or oil and gas properties by using common stock as consideration.
 
 
Securities analysts may not initiate coverage of our shares or may issue negative reports, which may adversely affect the trading price of the shares. We cannot assure you that securities analysts will cover our company. If securities analysts do not cover our company, this lack of coverage may adversely affect the trading price of our shares. The trading market for our shares will rely in part on the research and reports that securities analysts publish about us and our business. If one or more of the analysts who cover our company downgrades our shares, the trading price of our shares may decline. If one or more of these analysts ceases to cover our company, we could lose visibility in the market, which, in turn, could also cause the trading price of our shares to decline. Further, because of our small market capitalization, it may be difficult for us to attract securities analysts to cover our company, which could significantly and adversely affect the trading price of our shares.
 
 
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
   
Low
 
2011
           
First Quarter
 
$
4.00
   
$
1.95
 
2010
           
Fourth Quarter
 
$
2.50
   
$
1.81
 
Third Quarter
 
$
2.50
   
$
1.50
 
Second Quarter
 
$
4.00
   
$
0.25
 
First Quarter
 
$
5.50
   
$
2.05
 
2009
           
Fourth Quarter
 
$
5.75
   
$
3.00
 
September 25, 2009 through September 30, 2009
 
$
6.00
   
$
4.25
 

On 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.
 
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 Factorsdescribed 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. At December 31, 2010, we owned approximately 133,000 gross (117,500 net) acres, of which 122,000 gross (115,000 net) acres was classified as undeveloped acreage.
 
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.  Therefore results are generally not comparable for the year ended December 31, 2010 to the period of inception through December 31, 2009.  We have presented the results for each period below.
 
For the Year Ending December 31, 2010

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


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

Miscellaneous Income and Operating Fees

The Company earned net operating fees of $8,987 and $13,487 during the three and twelve month periods ended December 31, 2010.  The Company realized a mark-to-market gain of $3,389 and $28,666 during the three and twelve month periods ended December 31, 2010 on a put agreement associated with 85,000 shares of stock placed in conjunction with our reverse merger in September 2009.
 
Price Risk Management Activities
 
We recorded a net loss on our derivative contracts that do not qualify for cash flow hedge accounting of $(633,494) and $(398,840) for the three and twelve month periods ended December 31, 2010.  This amount represents an unrealized non-cash loss which represents a change in the fair value of our mark-to-market derivative instruments at December 31, 2010 as detailed in “Note 5 – Financial Instruments and Derivatives” and “Note 6 – Fair Value of Financial Instruments”.  We realized a gain on our derivative contracts that do not qualify for cash flow hedge accounting of $4,598 and $570,233 for the three and twelve month periods ended December 31, 2010.  This amount represents a realized cash gain from the settlement of our forward sale contracts for the quarter ended December 31, 2010 as detailed in “Note 5 – Financial Instruments and Derivatives” and “Note 6 – Fair Value of Financial Instruments”.   
 
Oil and Gas Production Expenses, Depreciation, Depletion and Amortization
 
   
For the Year Ended December 31,
 
   
2010
   
2009 (1)
   
2008 (1)
 
Net production
                 
Oil (Bbl)
    133,709       -       -  
Gas (Mcf)
    14,914       -       -  
MBOE
    136,195       -       -  
Average net daily production
                       
Oil (Bbl)
    366       -       -  
Gas (Mcf)
    41       -       -  
BOE
    373       -       -  
Average realized sales price, excluding the effects of hedging
                       
Oil (per Bbl)
  $ 71.08     $ -     $ -  
Gas (per Mcf)
  $ 4.56     $ -     $ -  
Per BOE
  $ 70.29     $ -     $ -  
Average realized sales price, including the effects of hedging
                       
Oil (per Bbl)
  $ 75.27     $ -     $ -  
Gas (per Mcf)
  $ 4.56     $ -     $ -  
Per BOE
  $ 74.47     $ -     $ -  
Production costs per BOE
                       
Lease operating expense (2)
  $ 6.33     $ -     $ -  
DD&A
  $ 36.98     $ -     $ -  
Production taxes
  $ 7.76     $ -     $ -  
                         
Total operating costs
  $ 51.07     $ -     $ -  
                         
Gross margin percentage
    31 %   $ - %     - %
 
(1)  
Prior to January 2010, the Company did not own any oil and gas properties
(2)  
Approximately $2.35/BOE of lease operating expense relates to surface, subsurface, road repairs and work-over activities

 

General and Administrative Expenses
 
General and administrative expenses were $3,635,060 and $12,502,568 for the three and twelve month periods ended December 31, 2010.  Our general and administrative expenses for the three and twelve month periods ended December 31, 2010 included $397,136 and $1,464,990 in professional fees (financial advisors, attorneys, accountants, and reserve engineers) of which $135,982 and $372,393 were noncash, and $2,864,873 and $9,958,300 in non-cash compensation expense.  We also incurred a non-cash expense of $23,357 and $54,500 in rental expense for our office lease for the three and twelve months ending December 31, 2010.   Total non-cash general and administrative expenditures for the three and twelve months ended December 31, 2010 was approximately $143,000 and $10,400,000, respectively.  This compares to approximately $1,057,306 in general and administrative expenditures from inception through December 31, 2009 which included non-cash expenditures of $690,000.

Depreciation Expense

Depreciation and amortization expense were $1,141,038 and $5,036,648 for the three and twelve month periods ended December 31, 2010.

Interest Expense

Total interest expense was $2,041,954 and $6,640,209 for the three and twelve month periods ended December 31, 2010.  The interest expense was comprised of $1,237,273 and $3,989,649 in non-cash amortization of expenses for the three and twelve month periods ending December 31, 2010 related to warrants issued and overriding royalty interests assigned to our lender in conjunction with the closing of the three credit agreements and the extension of the credit agreements.  We incurred $804,751 and $2,655,131 in cash interest expense for the three and twelve month periods ended December 31, 2010.  We did not incur interest expense from inception through December 31, 2009.
 
We incurred a net loss to common shareholders of $16,785,583 for the year ended December 31, 2010.

From inception through December 31, 2009
 
General and administrative expense for the period ended December 31, 2009 totaled $1,057,306, including non-cash expense $684,778 in compensation expense for outstanding restricted common stock grants issued to executive officers and board members.
 
Our expense for impairment of equipment held for sale was $2,750,000 for the period ended December 31, 2009.
 
Non-cash expenses related to the fair value of common stock issued in an attempted property transaction for the period ended December 31, 2009 totaled $5,075,000.  Additional non-cash expenses for the period ended December 31, 2009 included $3,329,106 in fair value for warrants issued to third parties for a commitment to finance a property transaction which did not close, $200,000 related to 85,000 shares issued in conjunction with the merger and $17,500,000 related to 5 million shares acquired by our controlling shareholder group subsquent to the reverse merger.
 
Income for the period ended December 31, 2009 totaled $31 and was comprised of interest income. 
 
We incurred a net loss to common shareholders of $29,911,381 for the period ended December 31, 2009.

Plan of Operations
 
Our plan of operations 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.
 
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
 
As of the date of this report, we estimate our capital budget for the remainder of 2011 to be approximately $8,600,000, to be deployed for drilling up to two wells within the State Line and Palm project areas, up to two wells in the Wilke project area, and two carried wells in the Chugwater joint venture project area. The 2011 budget does not include the impact of any potential future exploration projects, or ongoing exploration or development activities, or potential acquisitions. We expect to fund our 2011 capital expenditures with cash on our balance sheet as well as cash provided by operating activities. Additionally, we intend to raise additional funds through private placements or registered offerings of equity or debt and potential monetization of select assets.
 
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 $(16,785,583) 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 $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.
 
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.
 
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 Basin Acquisitions completed during 2010 (See Note 3 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISTIONS).
 
Impairment of Long-lived Assets
 
We record our property and equipment at cost. The cost of our unproved properties is withheld from the depletion base as described above, until such a time as the properties are either developed or abandoned. We review these properties quarterly for possible impairment. We provide an impairment allowance on unproved property when we determine that the property will not be developed or the carrying value will not be realized. We evaluate the reliability of our proved properties and other long-lived assets whenever events or changes in circumstances indicate that the recording of impairment may be appropriate. Our impairment test compares the expected undiscounted future net revenue from a property, using escalated pricing, with the related net capitalized costs of the property at the end of the applicable period. When the net capitalized costs exceed the undiscounted future net revenue of a property, the cost of the property is added to the full cost pool.
 
Derivative Instruments
 
During 2010, 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.
 
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.

 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 in  Internal 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 BEUNIER
Roger A. Parker
 
Jeffrey A Beunier
Chief Executive Officer
 
President and Chief Financial Officer
March 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.
 
Item 9B.  OTHER INFORMATION
 
None.
 
 
 
 
PART III

Except as set forth below, the information required by Items 10 through 14 is set forth under the captions “Election of Directors,” “Ratification of Independent Registered Public Accounting Firm,” “Management,” “Executive Compensation,” “Principal Stockholders” and “Related Party Transactions” in Recovery Energy Inc’s definitive proxy statement for its 2011 annual meeting of stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934, as amended, which sections are incorporated herein by reference as if set forth in full.
 
Item 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
 
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.
 
Item 11.  EXECUTIVE COMPENSATION
 
Information required by this item is incorporated by reference to the material appearing in the Company’s 2011 Proxy Statement.
 
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
 
Information required by this item is incorporated by reference to the material appearing in the Company’s 2011 Proxy Statement.
 
Item 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
See “Recent Developments and Related Transactions” in the Item 1. Additional information required by this Item is incorporated herein by reference to the Company’s 2011 proxy statement.
 
Item 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
Information required by this item is incorporated by reference to the material appearing in the Company’s 2011 Proxy Statement.  
 
 
 
PART IV
Item 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
 
INDEX TO FINANCIAL STATEMENTS
a)
 
Report of Independent Registered Public Accounting Firm
   
F-1
 
         
Consolidated Balance Sheets
   
F-2
 
         
Consolidated Statements of Operations
   
F-4
 
         
Consolidated Statements of Shareholders' Equity
   
F-5
 
         
Consolidated Statements of Cash Flows
   
F-6
 
         
Notes to Financial Statements
   
F-8
 

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

 
 
10.29
Employment Agreement with Roger A. Parker (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on December 23, 2010).
   
10.30
Employment Agreement with Jeffrey A. Beunier (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on December 23, 2010).
   
10.31
Director Appointment Agreement with James Miller (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on May 20, 2010).
   
10.32
Form of Warrant Issued in Private Placement (incorporated herein by reference to Exhibit 4.1 to the Company's current report filed on form 8-K filed on June 4, 2010).
   
10.33
Warrant issued to Hexagon Investments, LLC (incorporated herein by reference to Exhibit 4.2 to the Company's current report filed on form 8-K filed on June 4, 2010).
   
10.34
Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 4, 2010).
   
10.35
Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K fi
   
10.36
Form of Lockup Agreement (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on June 4, 2010).
   
10.37
Letter Agreement with Hexagon Investments, LLC (incorporated herein by reference to Exhibit 10.4 to the Company's current report filed on form 8-K filed on June 4, 2010).
   
10.38
Independent Director Appointment Agreement with Timothy N. Poster (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 7, 2010).
   
10.39
Independent Director Appointment Agreement with Conway J. Schatz (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on June 7, 2010).
   
10.40
Consulting Agreement with Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 18, 2010).
   
10.41
Five Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company's current report filed on form 8-K filed on June 18, 2010).
   
10.42
Three Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.3 to the Company's current report filed on form 8-K filed on June 18, 2010).
   
10.43
Warrant to Globe Media (incorporated herein by reference to Exhibit 10.4 to the Company's current report filed on form 8-K filed on June 18, 2010).
   
 
10.44
Registration Rights Agreement with Hexagon Investments, Inc. (incorporated herein by reference to Exhibit 10.5 to the Company's current report filed on form 8-K filed on June 18, 2010).
   
10.45
Stockholders Agreement with Hexagon Investments Incorporated (incorporated herein by reference to Exhibit 10.1 to the Company's current report filed on form 8-K filed on June 29, 2010).
   
10.46
Form of $2.20 Warrant Issued to Persons Exercising $1.50 Warrants (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on October 8, 2010).
 
 
 
   
10.47
Purchase Agreement with Edward Mike Davis, L.L.C. and Spottie, Inc. dated November 19, 2010 (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on November 26, 2010).
   
10.48
Put Option Agreement with Grandhaven Energy, LLC dated November 19, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company's current report on form 8-K filed on November 26, 2010).
   
10.49
Warrant Issued to Hexagon Investments, LLC on January 1, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on January 4, 2011).
   
10.50
Amendments to Hexagon Investments, LLC Promissory Notes (incorporated herein by reference to Exhibit 10.2 to the Company's current report on form 8-K filed on January 4, 2011).
   
10.51
Form of Convertible Debenture Securities Purchase Agreement dated February 2, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on February 3, 2011). 
   
10.52 
Form of Convertible Debenture (incorporated herein by reference to Exhibit 10.2 to the Company's current report on form 8-K filed on February 3, 2011).
   
10.53
Purchase Agreement with Wapiti Oil & Gas, L.L.C. (incorporated herein by reference to Exhibit 10.1 to the Company's current report on form 8-K filed on February 24, 2011). 
   
10.54
Termination Agreement dated as of December 15, 2009 with Edward Mike Davis, L.L.C.
   
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 2002
   
31.2
Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002
   
32.1
Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002
   
32.2
Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002
   
99.1
Report of RE Davis.
 
 
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 

 
 
To the Board of Directors and Shareholders
 
Recovery Energy, Inc.
 
We have audited the accompanying consolidated balance sheets of Recovery Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the year ended December 31, 2010 and for the period from March 6, 2009 (Inception) through December 31, 2009.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting  principles  used and significant estimates made by management, as well as evaluating the overall financing statement presentation.  We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Recovery Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for the year ended December 31, 2010 and for the period from March 6, 2009 (Inception) through December 31, 2009, in conformity with U.S. generally accepted accounting principles.
  
 
 
/s/ HEIN & ASSOCIATES LLP
 
Denver, Colorado
 
March 31, 2011 
 
 

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

 
RECOVERY ENERGY, INC.
CONSOLIDATED BALANCE SHEETS


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

 
The accompanying notes are an integral part of these financial statements. 
 
 
RECOVERY ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
 

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

The accompanying notes are an integral part of these financial statements.
 
  RECOVERY ENERGY, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
For the year ended December 31, 2010 and from March 6, 2009 (Inception) through December 31, 2009
 
         
Other Shareholders' Equity
 
                                     
                                     
   
Common Stock Subject
               
Additional
             
   
to Redemption
   
Common Stock
   
Paid-In
   
Accumulated
       
   
Shares
   
Amount
   
Shares
   
Amount
   
Capital
   
Deficit
   
Total
 
                                           
Balance, March 6, 2009 (Inception)
   
-
   
$
-
     
-
   
$
-
   
$
-
   
$
-
   
$
-
 
                                                         
Common stock issued in reverse merger
    -       -      
2,099,000
     
210
     
(33,957
    -      
(33,747
)
                                                         
Common stock issued in exchange of debt
      -         -      
2,100,000
     
210
     
3,249,790
      -      
3,250,000
 
                                                         
Common stock issued in lock-up agreement
   
85,000
     
172,516
        -         -         -       -      
           -
 
                                                         
Common stock issued in reorganization
      -         -      
5,000,000
     
500
     
17,499,500
        -      
17,500,000
 
                                                         
Common stock issued in attempted acquisition
      -         -      
1,700,000
     
170
     
5,824,830
        -      
5,825,000
 
                                                         
Common stock issued for cash
      -         -      
125,000
     
12
     
499,988
        -      
500,000
 
                                                         
Restricted stock and performance options issued to employees and directors
      -         -         -         -      
684,778
        -      
684,778
 
                                                         
Warrants issued for financing commitment
      -         -         -