Lilis Energy
Annual Report 2012

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K xx ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2012 or oo TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________to_________ Commission file number: 001-35330 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.)1900 Grant Street, Suite #720, Denver, CO 80203(Address of principal executive offices, including zip code)Registrant’s telephone number including area code: (303)-951-7920 Securities registered under Section 12(b) of the Act:NoneSecurities registered under Section 12(g) of the Act: Title of each class $0.0001 par value Common Stock Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes o No x Indicate by check mark if the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during thepast 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 thepast 90 days. Yes x No o Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required tobe submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period thatthe registrant was required to submit and post such files). Yes x No oIndicate 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 thebest 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 tothis 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 definedin Rule 12b-2 of the Act): Large accelerated filer oAccelerated fileroNon-accelerated filer oSmaller reporting companyx Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x State the aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equitywas last sold, or the average bid and asked price of such common equity, as of the last business day of the fiscal quarter ending June 29,2012: $21,411,978As of April 9, 2013, 18,498,601 shares of the registrant’s common stock were issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Registrant’s definitive proxy statement for the 2013 Annual Meeting of Stockholders, scheduled to be held in June 2013, which will be filedwith the Securities and Exchange Commission within 120 days after December 31, 2012, are incorporated by reference into Part III.  FORM 10-K ANNUAL REPORTFISCAL YEAR ENDED DECEMBER 31, 2012RECOVERY ENERGY, INC. PagePART I Items 1. And 2.Business and Properties6Item 1A.Risk Factors18Item 1B.Unresolved Staff Comments 32Item 3.Legal Proceedings 32Item 4.Mine Safety Disclosures33 PART II Item 5.Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities33Item 6.Selected Financial Data33Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations34Item 7A.Quantitative and Qualitative Disclosures About Market Risk47Item 8.Financial Statements and Supplementary Data47Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure47Item 9A.Controls and Procedures47Item 9B.Other Information 48 PART III Item 10.Directors, Executive Officers and Corporate Governance 48Item 11.Executive Compensation 48Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 48Item 13.Certain Relationships and Related Transactions, and Director Independence 48Item 14.Principal Accountant Fees and Services 48 PART IV Item 15.Exhibits and Financial Statement Schedules 49  FORWARD-LOOKING STATEMENTSThis annual report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements otherthan statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to, anyprojections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations; anystatements concerning future production, reserves or other resource development opportunities; any projected well performance or economics, or potential jointventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements regarding future capital-raisingactivities; any statements of belief; and any statements of assumptions underlying any of the foregoing.Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “expect” or“anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this presentation. Except asrequired by law, we do not intend, and undertake no obligation, to update any forward-looking statement.Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from thoseprojected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-lookingstatements, are subject to change and inherent risks and uncertainties. The factors impacting these risks and uncertainties include, but are not limited to:●availability of capital on an economic basis, or at all, to fund our capital needs; ●failure to meet requirements under our credit agreements or debentures, which could lead to foreclosure of significant assets; ●inability to address our negative working capital position;●the inability of management to effectively implement our strategies and business plans;●potential default under our secured obligations or material debt agreements;●estimated quantities and quality of oil and natural gas reserves;●exploration, exploitation and development results;●fluctuations in the price of oil and natural gas, including reductions in prices that would adversely affect our revenue, cash flow, liquidityand access to capital;●availability of, or delays related to, drilling, completion and production, personnel, supplies and equipment;●the timing and amount of future production of oil and gas;●the completion, timing and success of our drilling activity;●lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements;●declines in the values of our natural gas and oil properties resulting in write-downs;●inability to hire or retain sufficient qualified operating field personnel;●increases in interest rates or our cost of borrowing;●deterioration in general or regional (especially Rocky Mountain) economic conditions;●the strength and financial resources of our competitors;●the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations orcould impact the operations of companies or contractors we depend upon in our operations;●inability to acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts;●inability to successfully develop the acreage we currently hold; ●transportation capacity constraints or interruptions, curtailment of production, natural disasters, adverse weather conditions, or otherissues affecting the DJ Basin; ●technique risks inherent in drilling in existing or emerging unconventional shale plays using horizontal drilling and completion techniques;●delays, denials or other problems relating to our receipt of operational consents and approvals from governmental entities and otherparties;●unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids; 1 ●environmental liabilities;●operating hazards and uninsured risks;●loss of senior management or technical personnel;●adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect toexisting operations, including those related to climate change and hydraulic fracturing;●changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate; and●other factors, many of which are beyond our control.Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factorsthat may affect us.For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement,we urge you to carefully review and consider the disclosures made in the “Risk Factors” sections of our SEC filings, available free of charge at the SEC’swebsite (www.sec.gov). 2 GLOSSARY In this report, the following abbreviation and terms are used: Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude, condensate or natural gas liquids. 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. Installation of permanent equipment for production of natural gas or oil, or in the case of a dry hole, the reporting to the appropriate authoritythat the well has been abandoned. Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure but that, when produced, is in theliquid phase at surface pressure and temperature. 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. Ouractual 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 well. 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 a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in anotherreservoir. 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/orstratigraphic condition. Formation. An identifiable layer of rocks named after its geographical location and dominant rock type.Gross acres, gross wells, or gross reserves. A well, acre or reserve in which the Company owns a working interest. The number of gross wells is the totalnumber of wells in which the Company owns a working interest. Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on aparticular 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. 3 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 own 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 astandard lease providing for a basic royalty to the lesser or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil andnatural 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 operatorsubject 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 of3/4. Overriding royalty interest owners have no obligation or responsibility for developing and operating the property. The only expenses borne by theoverriding 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 intoanother 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 provedreserves, net of estimated production, future development costs and future plugging and abandonment costs, using the simple 12 month arithmetic of first ofmonth prices and current costs (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-propertyrelated expenses such as general and administrative expenses, debt service, future income tax expenses, depreciation, depletion and amortization orimpairment, discounted using an annual discount rate of 10%. While this non-GAAP measure does not include the effect of income taxes as it would in theuse of the standardized measure calculation, it does provide an indicative representation of the relative value of Recovery Energy on a comparative basis toother companies and from period to period. Production. Natural resources, such as oil or gas, taken out of the ground. Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certaintyto be economically producible – from a given date forward, from known reservoirs, under existing economic conditions , operating methods, and governanceregulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless ofwhether deterministic or probabilistic methods are used for the estimation. Proved developed oil and gas reserves. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existingwells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and(ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, orfrom existing wells where a relatively major expenditure is required for recompletion. Probable Reserves. Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likelyas not to be recovered. Possible Reserves. Those additional reserves that are less certain to be recoverable than probable reserves. 4 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 usingreasonably 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 toestablish or increase existing production. Reserves. Estimated remaining quantities of oil, natural gas and gas liquids anticipated to be economically producible, as of a given date, by application ofdevelopment projects to known accumulations. Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined byimpermeable rock or water barriers and is individual and 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, toproduce 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 towait 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 usedto 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. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities ofoil or 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 hydrocarbonrecovery. 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 ofproduction and requires the owner to pay a share of the costs of drilling and production operations. 5 PART IItems 1 and 2. BUSINESS AND PROPERTIESRecovery Energy, Inc. (NASDAQ: RECV), (“we,” “us,” “our,” “Recovery Energy,” “Recovery,” or the “Company”) is a Denver based independent oil andgas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. We were incorporated in August of 2007 inthe State of Nevada as Universal Holdings, Inc. In October 2009, we changed our name to Recovery Energy, Inc.Our executive offices are located at 1900 Grant Street, Suite #720, Denver, Colorado 80203, and our telephone number is (303) 951-7920. Our web site iswww.recoveryenergyco.com. Additional information which may be obtained through our web site does not constitute part of this annual report on Form 10-K.Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are accessible free of chargeat our website. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings atwww.sec.gov.Our current operating activities are focused on the Denver-Julesburg Basin (“DJ Basin”) in Colorado, Wyoming and Nebraska. Our business strategy isdesigned to maximize shareholder value by leveraging the knowledge, expertise and experience of our management team and via the future exploration anddevelopment of the approximate 129,000 net acres of developed and undeveloped acreage that are currently held by the Company, primarily in the northern DJBasin. The majority of our leases on which we have identified reserves and production are subject to security interests held by the lenders under our secured termloans or our 8% Senior Secured Convertible Debentures. As discussed below, we have recently amended the terms of both the secured term loans and the 8%Senior Convertible Debentures to among other things, extend the maturity dates under both the term loans and the debentures, and reduce the interest rate andthe level of minimum monthly payments under the term loans. We currently have $19.34 million outstanding under our term loans and $13.40 millionoutstanding under our debentures. In addition, we currently have a working capital deficit of approximately $1.04 million, and approximately $3.63 million incurrent liabilities. We believe that the amendments referenced above provide us with significantly more flexibility in meeting our obligations. In addition, asdiscussed below, we have entered into an agreement with one of our existing debenture holders to invest at least $1.5 million in additional debentures onsubstantially the same terms as our existing senior secured debentures, with the possibility of an additional investment by our existing debenture holders of upto $3.5 million. We are aggressively exploring a number of other capital raising transactions aimed at improving our liquidity position in the long and shortterm, including asset sales, joint ventures and similar industry partnerships, asset monetization transactions, possible equity transactions, and other potentialrefinancing transactions with terms more favorable to us than those under the term loans and debentures. Our ability to fund some of our ongoing overhead, tomeet our minimum principal and interest obligations and to fund our 2013 capital program is contingent on successfully raising additional capital via one ormore of the above referenced transactions. Recent DevelopmentsIn April 2013, we amended both our secured term loans and our 8% Senior Secured Convertible Debentures to extend their maturity dates to May 16, 2014. Inconsideration for the extended maturity date of both loans and the reduced interest rate and minimum loan payment under the secured term loans, theCompany will be required to provide both Hexagon and the holders of our debentures an additional security interest in 15,000 acres (or 30,000 acres inaggregate) of our undeveloped acreage. Additionally, pursuant to the amendment to our secured term loan, Hexagon has agreed to (i) reduce our interest ratefrom 15% to 10% beginning retroactively with March 2013, (ii) permit us to make interest-only payments for March, April, May, and June, after which timethe minimum secured term loan payment will be $0.23 million or $0.19 million, depending on our ability to consummate the sale of certain of our assets byJuly 1, 2013, and (iii) forbear from exercising its rights under the term loan credit agreements for any breach that may have occurred prior to the amendment.In addition, we are required under the amendment to use our reasonable best efforts to pursue certain transactions to improve our financial condition, includingthe aforementioned sale of certain of our assets, an equity offering or similar capital-raising transaction, one or more joint venture development agreements, andan engineering study of certain of our producing properties to ascertain possible operations to enhance production from those properties. Pursuant to thedebenture amendment, the Company and the debenture holders have agreed to waive any breach under the debentures that may have occurred prior to the dateof the amendment.On April 16, 2013, the Company entered into an agreement with one of its existing Debenture holders to issue up to an additional $5.0 million in additionaldebentures with substantially the same terms to the existing 8% Secured Convertible Debentures. Under the terms of this agreement, $1.5 million ofadditional debentures will be issued on or before July 16, 2013. The funds associated with the initial issuance of debentures will be used by the Company forthe drilling and development of certain properties, and for general corporate purposes (see Note 14). Copies of the amendments are filed as Exhibits 10.56 through 10.59 to this annual report on Form 10-K. Overview of Our Business and StrategyWe have developed and acquired an oil and natural gas base of proved reserves, as well as a portfolio of exploration and development prospects withconventional and non-conventional reservoir opportunities, with an emphasis on multiple producing horizons, in particular the Niobrara shale and Codellresource plays. We believe these prospects offer the possibility of repeatable success allowing for meaningful production and reserve growth. Our acquisition,development and exploration pursuits are principally directed at oil and natural gas properties in the DJ Basin in Colorado, Nebraska, and Wyoming. Sinceearly 2010, we have acquired and/or developed 29 producing wells. As of December 31, 2012 we owned interests in approximately 145,000 gross (129,000net) leasehold acres, of which 122,000 gross (107,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming andNebraska within the DJ Basin. We intend to continue to evaluate and invest in internally generated prospects. It is our long-term goal to maximize our DJBasin acreage position through development drilling of our conventional horizons as well as development of our Niobrara shale and Codell resource potential. 6 It is our belief that the exploration and production industry’s most significant value creation occurs through the drilling of successful development wells andthe enhancement of oil recovery in mature fields given appropriate economic conditions. Our goal is to create significant value while maintaining a low coststructure. To achieve this, our business strategy includes the following elements: Participation in development prospects in a known producing basin. We pursue prospects in the DJ Basin, where we can capitalize on our development andproduction 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 knowledge of pricing cycles of oil and natural gas and availableexploration 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 ourdevelopment 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 capitalexpenditures. We have continued to generally maintain high working interests in our DJ Basin undeveloped acreage, which maximizes our exposure togenerated cash flows and increases in value as the properties are developed. With operational control, we can also schedule our drilling program to satisfymost of our lease stipulations and continue to put our acreage into “held by production” status, thus eliminating leasehold expirations. The majority of ouracreage 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, wetake 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 drillingand development of the prospect acreage. Controlling Costs. We seek to maximize our returns on capital by minimizing our expenditures on general and administrative expenses. We also minimizeinitial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that havealready invested capital in such. We also outsource some of our technical functions in order to help reduce general and administrative and capitalrequirements. From time to time, we use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we haveadequate cash flow to fund our debt service costs and capital programs. From time to time, we will enter into futures contracts, collars and basis swapagreements, as well as fixed price physical delivery contracts. We intend to use hedging primarily to manage price risks and returns on certain acquisitionsand drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In the future wemay also be required by our lenders to hedge a portion of production as part of any financing. We do not currently have any commodity price hedging in place. Principal Oil and Gas InterestsAll references to production, sales volumes and reserves quantities are net to our interest unless otherwise indicated. As of December 31, 2012 we owned interests in approximately 145,000 gross (129,000 net) leasehold acres, of which 122,000 gross (107,000 net) acres areclassified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. Our primary targets within the DJBasin are the conventional Dakota and Muddy ‘J’ formations, and the developing unconventional Niobrara shale play. Additional horizons include theCodell, Greenhorn and other potential resource formations. During 2012, we made capital expenditures of approximately $5.07 million, which included $0.54 million related to undeveloped acreage and $4.53 millionrelated to drilling and completion operations where we drilled and completed 6 gross (4 net) wells. We sold undeveloped acreage for $1.4 million and leasedother undeveloped acreage to a third party for $1.5 million. We paid our lender, Hexagon, LLC (“Hexagon”), $0.75 million of these proceeds as a prepaymentof principal under our term loans.During 2011, we made capital expenditures of approximately $16.4 million, including $9.4 million for the purchase of undeveloped acreage and $7.4 millionrelated to drilling and completion operations where we drilled 4 gross (3.25 net) wells and completed 3 gross (2.25 net) wells; also, as of December 31, 2011we had 2 gross (1.75 net) wells in progress. 7 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, 2012. Prior toJanuary 2010, we did not own any reserves nor did we have any production. We engaged Ralph E. Davis Associates, Inc. (“RE Davis”) to audit internalengineering estimates for 100 percent of the PV-10 value of our proved reserves in 2012. The prices used in the calculation of proved reserve estimates as ofDecember 31, 2012 were $87.37 per Bbl. and $2.75 per MCF; as of December 31, 2011 were $88.16 per Bbl. and $3.96 per MCF; and as of December 31,2010, were $78.93 per Bbl. and $4.39 per MCF for oil and natural gas, respectively. The prices were adjusted for basis differentials, pipeline adjustments,and BTU content. We emphasize that reserve estimates are inherently imprecise and that estimates of all new discoveries and undeveloped locations are more imprecise thanestimates 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. Neitherprices nor costs have been escalated. The following table should be read along with the section entitled “Risk Factors — Risks Related to OurCompany”. The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated. No estimates of ourproved reserves have been filed with or included in reports to any federal authority or agency, other than the Securities and Exchange Commission ("SEC"),since the beginning of the last fiscal year. We did not have third party engineers review probable and possible reserves or resources as of December 31, 2012. As of December 31, 2012 2011 2010 Reserve data: Proved developed Oil (MBbl) 213 216 278 Gas (MMcf) 186 148 308 MBOE(1) 244 241 329 Proved undeveloped (2) Oil (MBbl) 138 392 415 Gas (MMcf) 221 - - MBOE (2) 175 392 415 Total Proved Oil (MBbl) 351 608 693 Gas (MMcf) 407 148 308 MBOE 419 633 744 Proved developed reserves % 58% 38% 44%Proved undeveloped reserves % 42% 62% 56% Reserve value data : Proved developed PV-10 $9,743,158 $10,204,160 $11,377,009 Proved undeveloped PV-10 (2) 5,678,972 9,809,885 12,217,798 Total proved PV-10 $15,422,130 $20,014,045 $23,594,807 Standardized measure of discounted future cash flows $15,422,130 $20,014,045 $23,594,807 Reserve life (years) 42.42 22.58 21.92 (1)Increase in MBOE of proved developed to 244 MBOE from 241 MBOE, an increase of 3 MBOE or 1.2% during the year ended December 31,2012 and 2011, respectively, was due to the Company purchasing reserves within the DJ Basin.(2)Decrease in 2012 MBOE of proved undeveloped reserves to 175 MBOE from 392 MBOE in 2011, a decrease of 217 MBOE or 55% reflects thecurrent uncertainty regarding whether the Company will have sufficient capital to support its current development plan. Proved undevelopedreserves therefore reflect the assumption that such reserves will be developed on a promoted basis of 25%, thereby reducing net PUD volumes thatwould otherwise by recoverable by 75% and also effecting a corresponding decrease in the PV10 value. The Company is working on alternativecapital infusion plans that could allow it to maintain a higher working interest position in the undeveloped acreage locations. With the exception ofa single well location, the Company currently holds a one hundred percent leasehold position in all the undrilled locations classified as provedundeveloped. A successful capital campaign could result in the Company increasing its proved undeveloped reserve position. On April 16, 2013, the Company entered into an agreement with one of its existing Debenture holders to issue up to an additional $5.0 million inadditional debentures with substantially the same terms to the existing 8% Secured Convertible Debentures. Under the terms of this agreement,$1.5 million of additional debentures will be issued on or before July 16, 2013. The funds associated with the initial issuance of debentures willbe used by the Company for the drilling and development of certain properties, and for general corporate purposes. 8 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 cashflows. Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the “Glossary.”Internal Controls Over Reserves EstimateOur policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserve quantities andvalues in compliance with the regulations of the SEC. Responsibility for compliance in reserve bookings is delegated to our president with assistance from oursenior geologist, principal accounting officer, and a senior reserve engineering consultant.Technical reviews are performed throughout the year by our senior reserve engineering consultants and our senior geologist who evaluate all available geologicaland engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of estimated provedreserve quantities. The 2012 reserve process was overseen by Kent Lina, our senior reserve engineer consultant. Mr. Lina joined the Company in October2010, and prior to that was employed by Delta Petroleum Company from March 2002 to September 2010 in various operations and reservoir engineeringcapacities culminating as the Senior V.P. of Corporate Engineering. Mr. Lina received a Bachelor of Science degree in Civil Engineering from University ofMissouri at Rolla in 1981. Mr. Lina left the Company in December 2012, and continues to serve the Company in a consulting capacity. Third-party Reserves StudyAn independent third party reserve study as of December 31, 2012 was performed by RE Davis using their engineering assumptions and other economic dataprovided by us. One-hundred percent of our total calculated proved reserve PV-10 value was audited by RE Davis. RE Davis is an independent petroleumengineering consulting firm that has been providing petroleum engineering consulting services for over 20 years. The technical person at RE Davis primarilyresponsible for overseeing our reserve audit is Allen C. Barron, the President and CEO, who received a Bachelor of Science degree in Chemical and PetroleumEngineering 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 PetroleumEngineers. The RE Davis report dated February 15, 2013 is filed as Exhibit 99.1 to this Annual Report.Oil and gas reserves and the estimates of the present value of future net revenues therefrom were determined based on prices and costs as prescribed by SECand FASB guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future netrevenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable anduncertain. Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates beprepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. For the yearended December 31, 2012, commodity prices over the prior 12-month period and year end costs were used in estimating net cash flows in accordance withSEC guidelines. In addition to a third party reserve study, our reserves and the corresponding report are reviewed by our president, chief executive officer, senior geologist andprincipal accounting officer and the audit committee of our board of directors. Our president is responsible for reviewing and verifying that the estimate ofproved reserves is reasonable, complete, and accurate. The audit committee reviews the final reserves estimate in conjunction with RE Davis’s audit letter. 9 Production The following table summarizes the average volumes and realized prices, excluding the effects of our economic hedges, of oil and gas produced from propertiesin which we held an interest during the periods indicated. Also presented is a production cost per BOE summary: For the Year Ended December 31, 2012 2011 2010 Product Oil (Bbl.) 68,207 81,433 133,709 Oil (Bbls)-average price (1) $86.48 $87.78 $71.09 Natural Gas (MCF)-volume 80,438 88,999 14,911 Natural Gas Liquids (NGL) - BOE 16,953 26,584 3 Natural Gas (MCF)-average price (2) $5.05 $6.15 $4.56 Barrels of oil equivalent (BOE) 98,567 122,850 136,198 Average daily net production (BOE) 270 337 373 Average Price per BOE (1) 63.96 $62.64 $70.29 (1) Does not include the realized price effects of hedges (2) Includes proceeds from the sale of NGL's Oil and gas production costs, production taxes, depreciation, depletion, and amortization Average Price per BOE(1) $63.96 $62.64 $70.29 Production costs per BOE 14.42 12.33 6.31 Production taxes per BOE 2.31 6.83 7.76 Depreciation, depletion, and amortization per BOE 46.15 35.39 36.98 Total operating costs per BOE $62.88 $54.55 $51.05 Gross margin per BOE $1.08 $8.09 $19.24 Gross margin percentage 2% 13% 27% (1) Does not include the realized price effects of hedges 10 Productive Wells As of December 31, 2012, we had working interests in 31 gross (29 net) productive oil wells, and 1 gross (1 net) productive gas well. Productive wells areeither wells producing in commercial quantities or wells capable of commercial production although currently shut-in. Multiple completions in the samewellbore 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 producedwhen it first commenced production, and such designation may not be indicative of current production. Acreage As of December 31, 2012 we owned 29 producing wells in the Wyoming, Nebraska and Colorado portion within the DJ Basin, as well as approximately145,000 gross (129,000 net) acres, of which 123,000 gross (107,000 net) acres were classified as undeveloped acreage.As of December 31, 2012 our primary assets included acreage located in Laramie and Goshen Counties in Wyoming; Banner, Kimball, and Scotts BluffCounties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado. The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 2012. Undeveloped Developed Gross Net Gross Net DJ Basin 122,200 107,200 21,800 21,800 Total 122,200 107,200 21,800 21,800 Drilling Activity The following table describes the development and exploratory wells we drilled during the years ended December 31, 2012, 2011, and 2010. For the Year Ended December 31, 2012 2011 2010 Gross Net Gross Net Gross Net Development: - - Productive wells 5 3 3 2.25 2 1.4 Dry wells 1 1 1 1 1 0.7 6 4 4 3.25 3 2.1 Exploratory: Productive wells - - - - - - Dry wells - - - - - - Total 6 4 4 3.25 3 2.1 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. As ofDecember 31, 2012 we had no wells in progress. 11 Title to Properties Substantially all of our interests are held pursuant to leases from third parties. The majorities of our producing properties are subject to mortgages securingindebtedness under our credit facility that we believe do not materially interfere with the use of or affects the value of such properties. We typically performonly minimal title due diligence before acquiring undeveloped acreage. 2013 Capital BudgetOur entire 2013 capital budget is subject to the securing of adequate financing. Our 2013 capital budget is currently projected to be approximately $15million, but is subject to securing sufficient capital to support planned drilling and development expenses. We anticipate that approximately 50% of thisbudget will be allocated toward the development of two of our unconventional prospects located in the Wattenberg field within the DJ Basin that will targethorizontal drilling and development of the Niobrara shale and Codell formations. The remainder of our 2013 budget is anticipated to be directed principallytoward the conventional development of certain lower risk offset wells to existing production. We also anticipate the allocation of approximately 10% of our2013 capital budget toward higher risk exploration activities, including the procurement of seismic data and the drilling of one conventional exploratory well.Our 2013 capital program is subject to securing sufficient capital, principally via the issuance of additional equity and debt We may also secure additionalcapital by pursuing sales of certain assets and seek to finance certain projects via joint venture agreements or other arrangements with strategic or industrypartners. Our 2013 capital budget is subject to various factors, including availability of capital, market conditions, oilfield services and equipment availability,commodity prices and drilling results. Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget as thecash flow from the wells could provide additional capital which we may use to increase our capital budget. We do not anticipate any significant expansion ofour current DJ Basin acreage position.Other factors that could cause us to further increase our level of activity and adjust our capital expenditure budget include a reduction in service and materialcosts, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, a further improvement incommodity prices or well performance that exceeds our forecasts, any of which could positively impact our operating cash flow. Factors that could cause us toreduce our level of activity and adjust our capital budget include, but are not limited to, increases in service and materials costs, reductions in commodityprices or under-performance of wells relative to our forecasts, any of which could negatively impact our operating cash flow. 12 Marketing and Pricing We derive revenue and cash flow principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailingprices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Themarket 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 andnatural gas. Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may alsoaffect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adverselyaffect the value of our reserves and make it uneconomical for us to commence or continue production levels of natural gas and crude oil. Historically, theprices 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. Furthermore, regional natural gas, condensate, oil and NGLs prices may move independently of broad industry price trends. Because some of our operationsare located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricingFrom time to time, we enter into derivative contracts. These contracts economically hedge our exposure to decreases in the prices of oil and natural gas. Hedgingarrangements may expose us to risk of significant financial loss in some circumstances including circumstances where: ●our production and/or sales of natural gas are less than expected;●payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or●the counterparty to the hedging contract defaults on its contract obligations. In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that anyhedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas.As of December 31, 2012, we did not have any hedging arrangements in place, and therefore may be more adversely affected by changes in oil and natural gasprices than our competitors who engage in hedging transactions.Major Customers During the year ended December 31, 2012 and 2011, the Company had one customer, Shell Trading (US), which accounted for approximately 67 percentand 76 percent, respectively, of our revenues. 13 Seasonality Generally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summer months. Tolessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forwardpurchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity has placed increaseddemand on storage volumes. Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season — although oil pricesare much more driven by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. The impact ofseasonality on crude oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of production capacity inexcess 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 leaseholdposition 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, andproduction expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teamsenable us to compete effectively in our core operating areas. However, we face intense competition from a substantial number of major and independent oil andgas companies, which have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in theacquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drillingrigs, 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 facescompetition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may also beaffected 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 oiland 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 notinsulated from this resource constraint, and we must compete effectively in this market in order to be successful.Employees As of December 31, 2012 we had 7 full-time employees and no part-time employees. For the foreseeable future, we intend to only add additional personnel asour operational requirements grow. In the interim, we plan to continue to use the services of independent consultants and contractors to perform variousprofessional services, including land, legal, environmental and tax services. We believe that by limiting our management and employee costs, we are able tobetter control total costs and retain flexibility in terms of project management.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 andregulations. The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impact ouroperations and can affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different than ourcompetitors. Matters regulated include permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wellsand unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements for the operation of wells, andtaxation of production. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oiland natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity, generally prohibit the venting orflaring 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 inconnection with oil and natural gas operations. While we believe we will be able to substantially comply with all applicable laws and regulations, therequirements of such laws and regulations are frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect onour actual operations. 14 Federal Income Tax. Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject tocertain limitations, to deduct as incurred, rather than to capitalize and amortize, our domestic “intangible drilling and development costs” and to claimdepletion 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 anaggregate 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 protectionof the environment and human health and safety. Environmental laws and regulations may require that permits be obtained before drilling commences, restrictthe 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 otherprotected areas, including areas containing endangered animal species. As a result, these laws and regulations may substantially increase the costs ofexploring for, developing, or producing oil and gas and may prevent or delay the commencement or continuation of certain projects. In addition, these lawsand regulations may impose substantial clean-up, remediation, and other obligations in the event of any discharges or emissions in violation of these laws andregulations. Further, legislative and regulatory initiatives related to global warming or climate change could have an adverse effect on our operations and thedemand for oil and natural gas. See “Risk Factors — Risks Related to the Oil and Gas Industry — Legislative and regulatory initiatives related to globalwarming 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 tightformations. For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors— Risks Relating to the Oil and GasIndustry.” Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additional operatingrestrictions or delays in the completion of oil and gas wells.Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, or producedin our operations. Some of this information must be provided to our employees, state and local governmental authorities, and local citizens. We are alsosubject 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 incurcosts to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well ordrilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden dischargesfrom damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoiningproperty, 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 othernoncompliance 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 therequirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanentcurtailment or cessation of all or a portion of our operations. 15 The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability,regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardoussubstance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that disposeor arrange for disposal of the hazardous substances found at the time. Persons who are or were responsible for releases of hazardous substances underCERCLA may be subject to joint and severable liability for the costs of cleaning up the hazardous substances that have been released into the environment andfor damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and propertydamage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA because our jointlyowned drilling and production activities generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardoussubstances under CERCLA. The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”) is the principal federal statute governing the treatment, storage and disposal ofhazardous 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 astatutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption iscontained 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 becauseour operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind theexemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption byadministrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous wastewe are required to manage and dispose of and would cause us to incur increased operating expenses. The Oil Pollution Act of 1990 (“OPA”), and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oilspills and liability for damages resulting from such spills in United States waters. The OPA assigns liability to each responsible party for oil removal costsand a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spillwas caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist tothe 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 stateand local clean-up requirements or incur liability under state and local laws. OPA also imposes ongoing requirements on responsible parties, including proofof financial responsibility to cover at least some costs in a potential spill. We cannot predict whether the financial responsibility requirements under the OPAamendments will adversely restrict our proposed operations or impose substantial additional annual costs to us or otherwise materially adversely affectus. 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 (the “Clean Water Act”), imposes restrictions and controls on the discharge ofproduced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conductconstruction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant DischargeElimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to thecrude oil and natural gas industry into certain coastal and offshore waters. Further, the Environmental Protection Agency (“EPA”), has adopted regulationsrequiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with thetreatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes providefor civil, criminal and administrative penalties for unauthorized discharges of crude oil and other pollutants and impose liability on parties responsible forthose discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. Webelieve that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution. 16 Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from crude oil and naturalgas production. The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for underground injection, with the main goal beingthe protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatusand to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictlycontrolled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. Failure to abide by our permits could subjectus to civil or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state undergroundinjection control programs and our permits. The Clean Air Act of 1963 and subsequent extensions and amendments (collectively, the “Clean Air Act”) and state air pollution laws adopted to fulfill itsmandate provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which maybe subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissionslimitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modifiedequipment. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws. Overthe next several years, we may be required to incur capital expenditures for air pollution control equipment or other air emissions-related issues. These NewSource Performance Standards (“NSPS 0000”) became effective in 2012, adding administrative and operational costs. Colorado partially adopted therequirements of NSPS 0000 in 2012 and will consider full adoption in 2013.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 andregulations generally relate to requirements to remediate spills of deleterious substances associated with oil and gas activities, the conduct of salt water disposaloperations, and the methods of plugging and abandonment of oil and gas wells which have been unproductive. Numerous state laws and regulations alsorelate 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 ourpresent activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you thatenvironmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwiseadversely 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 environmentaldamage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations orcontamination not discovered during our assessment of the acquired properties. Federal Leases. For those operations on federal oil and gas leases, such operations must comply with numerous regulatory restrictions, including variousnon-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued byvarious federal agencies. In addition, on federal lands in the United States, the Minerals Management Service, or MMS, prescribes or severely limits the typesof costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, MMS prohibits deduction ofcosts associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the MMS has been engaged in aprocess of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculating royaltiesowed to the government. The natural gas and crude oil industry as a whole has resisted the proposed rules under an assumption that royalty burdens willsubstantially 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 (“BLM”). These leasescontain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. In addition to permits requiredfrom 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 offacilities, and the posting of bonds to ensure that lessee obligations are met. Under certain circumstances, the BLM may require our operations on federalleases to be suspended or terminated. 17 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 leasingoil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensivenew oil and gas development is anticipated, and a comprehensive parcel review process. These changes have increased the amount of time and regulatorycosts necessary to obtain oil and gas leases administered by the BLM. Other Laws and Regulations. Various laws and regulations require permits for drilling wells and also cover spacing of wells, the prevention of waste ofnatural 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 asother 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 onour 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 material 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 continuedcompliance with existing requirements will not have a materially adverse impact on us.Item 1A. RISK FACTORSInvesting in our shares involves significant risks, including the potential loss of all or part of your investment. These risks could materially affect ourbusiness, financial condition and results of operations and cause a decline in the market price of our shares. You should carefully consider all of therisks described in this annual report, in addition to the other information contained in this annual report, before you make an investment in ourshares. In addition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors thatcould cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflectedfrom 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 Our current liquidity position presents a substantial risk that we will be unable to satisfy our current debt obligations. We currently have $19.34million outstanding under our term loans and $13.40 million outstanding under our 8% Senior Secured Convertible Debentures due May 16, 2014. Under theterms of the recent amendments to our secured term loans, beginning in July 2013 we will be required to make monthly payments of up to $0.23 million to ourlender, Hexagon, and failure to make such payments could result in immediate acceleration of both the term loans and the debentures. The majority of ourleases on which we have identified reserves are subject to security interests held by the lenders under our secured term loans or our debentures. As discussedbelow and in “Management’s Discussion & Analysis of Financial Position and Results of Operations,” we currently have a working capital deficit ofapproximately $1.04 million, and approximately $3.63 in current liabilities, and therefore we will need to access additional capital in order to fund ouroperating costs for the year ending December 31, 2013. On April 16, 2013, the Company entered into an agreement with one of its existing Debenture holders toissue up to an additional $5.0 million in additional debentures with substantially the same terms to the existing 8% Secured Convertible Debentures. Underthe terms of this agreement, $1.5 million of additional debentures will be issued on or before July 16, 2013. The funds associated with the initial issuance ofdebentures will be used by the Company for the drilling and development of certain properties, and for general corporate purposes. We are pursuing a numberof other capital raising transactions aimed at improving our liquidity position in the long and short term. 18 Our credit agreements mature on May 16, 2014, and our lender can foreclose on several of our properties if we do not pay off or refinance our$19.34 million of loans. Our credit agreements, which mature on May 16, 2014, require us to make a minimum monthly payment of up to $0.23 million toHexagon, our lender. Several of our oil and gas properties, including many of our producing properties, are pledged as collateral for our creditagreements. Failure to make a monthly payment, or to repay these loans at maturity, could cause a default under all three of the credit agreements, allowingHexagon to foreclose on these properties.Our 8% Senior Secured Debentures mature on May 16, 2014 and require monthly interest payments, and the debenture holders can foreclose onseveral of our properties if we default. Some of our oil and gas properties, including producing properties, are pledged as collateral for our 8% SeniorSecured Debentures. An event of default under the debentures or under our term loan agreements with Hexagon would allow the lenders to foreclose on theseproperties.Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes inthe economy or our industry and prevent us from meeting our obligations under our indebtedness. As of December 31, 2012, our total outstandingdebt under our credit agreements and convertible debentures equaled $32.7 million, including $19.34 million outstanding under our credit agreements withHexagon. Our degree of leverage could have important consequences, including the following:●it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt servicerequirements, acquisitions and general corporate or other purposes;●a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will notbe available for other purposes, including our operations, capital expenditures and future business opportunities;●the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations;●certain of our borrowings, including borrowings under our credit facility, are at variable rates of interest, exposing us to the risk of increasedinterest rates;●as we have pledged most of our oil and natural gas properties and the related equipment, inventory, accounts and proceeds as collateral for theborrowings under our credit facility, they may not be pledged as collateral for other borrowings and would be at risk in the event of a defaultthereunder;●it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that haveless debt;●we are vulnerable in the present downturn in general economic conditions and in our business, and we will likely be unable to carry out capitalspending and exploration activities in excess of those that are currently planned; and●we may from time to time be out of compliance with covenants under our term loan agreements, which will require us to seek waivers from ourlenders, which may be difficult to obtain.We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop our properties tothe extent desired. A higher level of indebtedness and/or preferred stock increases the risk that we may default on our obligations. Our ability to meet our debtobligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and financial,business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors that will affect our ability toraise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets, the number ofshares of capital stock we have authorized, unissued and unreserved and our performance at the time we need capital. 19 Currently, a significant portion of our revenue after field level operating expenses is required to be paid to Hexagon as debt service. The terms ofour term loan agreements with Hexagon require us to pay a significant portion of our operating cash flow as debt service, and also include a minimum monthlydebt service payment of up to $0.23 million. The existence of the minimum debt service requirement results in consistent negative cash flow, and threatens theCompany’s ability to remain in business. If we fail to make any such minimum payments, Hexagon may declare a default and accelerate the amounts due. Inthat event, all of our debt, including the convertible debentures, would be in default. In addition, failure to make the required monthly payment could result inthe acceleration of all amounts under the credit agreements, and foreclosure on a significant number of our properties. During the years ended December 31,2012 and 2011, we paid $1.63 million and $0.84 million in principal and $3.21 million and $3.20 million in interest representing approximately 171% and700% of our free cash flow from operations, respectively. In 2011, Hexagon deferred the payment of approximately $2 million of revenue toward debt service. In February 2012, we completed the sale of certain rights in our Grover Field property for $4.5 million, and in December 2012 we granted a four-year lease forthe deep rights on approximately 6,300 net acres of our undeveloped acreage in the DJ Basin for approximately $1.5 million, of which $0.75 million was paidto Hexagon for an additional debt principal payment. As of December 31, 2012, we had working capital of negative $1.04 million. In April 2013, weamended our term loan agreements with Hexagon, reducing the interest rate from 15% to 10%, reducing the minimum monthly payments from $0.33 million toeither $0.23 million or $0.19 million, depending on our ability to complete the sale of certain of our assets by July 1, 2013, and providing for interest-onlypayments for March through June 2013. Additionally, we will seek to obtain additional capital through the sale of our equity or debt securities, the successfuldeployment 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 obtaincontinued 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 areunable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeitour interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price could be materially adverselyaffected. Our largest stockholder and primary lender has the power to significantly influence the future of our Company. Our largest stockholder, Hexagon,is also our primary lender. As of December 31, 2012, Hexagon beneficially owned approximately 2,675,000 shares of our common stock, or approximately13.82% of our outstanding shares. Pursuant to our credit agreements with Hexagon and certain amendments thereto, Hexagon has certain rights, including theright to designate a member of our Board of Directors and consent rights over certain types of actions. Consequently, Hexagon has the power to influencematters requiring approval by our stockholders, including the election of directors, and the approval of mergers and other significant corporate transactions.This concentration of ownership, along with the restrictive covenants contained in our credit agreements with Hexagon, may make it more difficult for otherstockholders to effect substantial changes in our Company, may have the effect of delaying, preventing or expediting, as the case may be, a change in controlof our Company, and may make it difficult for other significant investors to make the capital contributions we require in order to resolve our current liquidityissues. Hexagon also has the right to sell its Company stock if it chooses to do so and, as required by the terms of certain amendments to the creditagreements, all of its shares are currently registered for resale. In the event that Hexagon sells all or a substantial portion of its shares, it is possible that themarket price of our stock could be adversely affected.We have historically incurred losses and cannot assure investors as to future profitability. We have historically incurred losses from operations duringour history in the oil and natural gas business. We had a cumulative deficit of approximately $106.22 million and $68.48 million as of December 31, 2012and 2011, respectively. Many of our properties are in the exploration stage, and to date we have established a limited volume of proved reserves on ourproperties. Our ability to be profitable in the future will depend on successfully addressing our near-term capital need to refinance our term loan indebtednessand fund our 2013 capital budget, and implementing our acquisition, exploration, development and production activities, all of which are subject to manyrisks beyond our control. Even if we become profitable on an annual basis, we cannot assure you that our profitability will be sustainable or increase on aperiodic basis. 20 We will require additional capital in order to achieve commercial success and, if necessary, to finance future losses from operations as weendeavor 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 obtainadequate capital as and when required. The business of oil and gas acquisition, drilling and development is capital intensive and the level of operationsattainable 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 commercialsuccess and our continued growth will be dependent on our continued access to capital either through the additional sale of our equity or debt securities, banklines of credit, project financing, joint ventures, sale or lease of undeveloped acreage, or cash generated from oil and gas operations.We do not have a significant operating history and, as a result, there is a limited amount of information about us on which to make an investmentdecision. In January 2010, we acquired our first oil and gas prospects and received our first revenues from oil and gas production in February 2010. InNovember 2012, our chairman and chief executive officer retired, and we appointed W. Phillip Marcum to the position of chairman and chief executive officer,and appointed A. Bradley Gabbard to the position of president (in addition to his existing position as chief financial officer). Accordingly, there is littleoperating history upon which to judge our business strategy, our management team or our current operations. We have limited management and staff and will be dependent upon partnering arrangements. We had seven employees at the end of December 31,2012. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, oil and gaswell supervision, land, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services andprospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, includingbut 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 pricecould be materially adversely affected. The loss of our chief executive officer or our president and chief financial officer could adversely affect us. We are dependent on the experience of ourexecutive officers to implement our operational objectives and growth strategy. The loss of the services of either of these individuals could have a negativeimpact on our operations and our ability to implement our strategy. In addition to acquiring producing properties, we may also grow our business through the acquisition and development of exploratory oil and gasprospects, which is the riskiest method of establishing oil and gas reserves. In addition to acquiring producing properties, we may acquire, drill anddevelop exploratory oil and gas prospects that are profitable to produce. Developing exploratory oil and gas properties requires significant capital expendituresand involves a high degree of financial risk. The budgeted costs of drilling, completing, and operating exploratory wells are often exceeded and can increasesignificantly 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 oninvestment. Exploratory wells bear a much greater risk of loss than development wells. We cannot assure you that our exploration, exploitation anddevelopment activities will result in profitable operations. If we are unable to successfully acquire and develop exploratory oil and gas prospects, our results ofoperations, financial condition and stock price may be materially adversely affected. 21 If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, wells in progress are deemed unsuccessful, ormajor tracts of undeveloped acreage expire, or other similar adverse events occur, we may be required to write-down the carrying value of ourdeveloped properties. We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas propertiesare capitalized into a single cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carryingcharges on non-producing properties, costs of drilling wells, completing productive wells, or plugging and abandoning non-productive wells, costs related toexpired leases, or leases underlying producing and non-producing wells, and overhead charges directly related to acquisition and exploration activities. Underthe full cost method of accounting, capitalized oil and natural gas property that comprise the full cost pool, less accumulated depletion and net of deferredincome taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gasreserves. This ceiling test is performed at least quarterly. Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize impairmentexpense. During the year ended December 31, 2012, we recognized impairment expenses in the amount of approximately $26.66 million related to impairmentof the carrying value of the developed properties that comprised the full cost pool. Future write-downs could occur for numerous reasons, including, but notlimited to reductions in oil and gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserve estimates,or from the addition of non-productive capitalized costs to the full cost pool that do not result in corresponding increase in oil and gas reserves. Impairments ofundeveloped acreage and plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full cost pool, without anycorresponding increase in reserve values; as such, these situations could result in future additional impairment expenses.Hedging transactions may limit our potential gains or result in losses. In order to manage our exposure to price risks in the marketing of our oil andnatural 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. Thesecontracts may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, suchtransactions 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. In addition, the counterparties underour derivatives contracts may fail to fulfill their contractual obligations to us.As of December 31, 2012, we did not have any hedging arrangements in place, and therefore may be more adversely affected by changes in oil and natural gasprices than our competitors who engage in hedging transactions.Our large inventory of undeveloped acreage and large percentage of undeveloped proved reserves may create additional economic risk. Oursuccess is largely dependent upon our ability to develop our large inventory of future drilling locations, undeveloped acreage and undeveloped reserves. As ofDecember 31, 2012, approximately 42% of our total proved reserves and 83% of our total acreage were undeveloped. To the extent our drilling results are not assuccessful 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 theexpected or projected value of these properties. In addition, delays in the development of our reserves or increases in costs to drill and develop such reserveswill reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projectsbecoming uneconomic. We may have difficulty managing growth in our business, which could adversely affect our financial condition and results ofoperations. Significant growth in the size and scope of our operations would place a strain on our financial, technical, operational and managementresources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansiondifficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry couldhave a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan. 22 The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, the present value of future netrevenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gasreserves. This annual report contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves containedin our filings with the SEC. This December 31, 2012 annual report, reserve estimate was prepared by our current reserve engineer consultant reviewed by ourpresident, senior geologist, and principal accounting officer, and audited by RE Davis. The process of estimating oil and natural gas reserves is complex andrequires 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 operatingexpenses, and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may besignificant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of provedreserves to reflect production history, results of exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil andnatural 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 willlead to greater overall production over the life of the wells, or that early results suggesting lack of reservoir continuity will prove to be accurate. You should not assume that the present value of future net revenues referred to in this prospectus is the current market value of our estimated oil and naturalgas 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 year preceding the end of the fiscal year. Actual future prices and costs may bematerially 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 ingovernmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the developmentand 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. Inaddition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is notnecessarily 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 liabilitiesassociated with the properties or obtain protection from sellers against them, which could cause us to incur losses. One of our growth strategies is topursue selective acquisitions of undeveloped acreage oil and natural gas reserves. If we choose to pursue an acquisition, we will perform a review of the targetproperties; however, these reviews are inherently incomplete. Generally, it is not feasible to review in depth every individual property involved in eachacquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to becomesufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform an inspection on every well, and environmentalproblems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, wemay not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks andliabilities in connection with the acquired properties. All of our producing properties and operations are located in the DJ Basin region, making us vulnerable to risks associated with operating in onemajor geographic area. All of our estimated proved reserves at December 31, 2012, and all of our 2012, 2011 and 2010 sales were generated in the DJBasin in southeastern Wyoming, northeastern Colorado and southwestern Nebraska. As a result, we may be disproportionately exposed to the impact ofdelays 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 maintenanceor 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 maybecome more pronounced within specific geographic oil and gas producing areas such as the DJ Basin, which may cause these conditions to occur with greaterfrequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experienceany 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 thathave a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results ofoperations. 23 The marketability of our production is dependent upon transportation and processing facilities over which we may have no control. Themarketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, rail service, andprocessing facilities. We deliver crude oil and natural gas produced from these areas through gathering systems and pipelines, some of which we do not own.The lack of availability of capacity on third-party systems and facilities could reduce the price offered for our production or result in the shut-in of producingwells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our productionthrough firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical reliabilityor other reasons, including adverse weather conditions. Activist or other efforts may delay or halt the construction of additional pipelines or facilities. Third-party systems and facilities may not be available to us in the future at a price that is acceptable to us. Any significant change in market factors or otherconditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delayproduction, thereby harming our business and, in turn, our results of operations, cash flows, and financial condition.Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquireadequate supplies of water for our drilling operations. Drilling activities require the use of water. For example, the hydraulic fracturing process require theuse and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drillingactivities. Water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of orrecycle the water used in our operations, could adversely impact our operations in certain areas.Our success is influenced by oil, natural gas, and NGL prices in the specific areas where we operate, and these prices may be lower than prices atmajor markets. Regional natural gas, condensate, oil and NGLs prices may move independently of broad industry price trends. Because some of ouroperations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing.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 varydepending upon reservoir characteristics and other factors. Thus, our future oil and gas reserves and production and, therefore, our cash flow and revenue arehighly dependent on our success in efficiently obtaining reserves and acquiring additional recoverable reserves. We may not be able to develop, find or acquirereserves 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 andresults of operations would be materially and adversely affected. Part of our strategy involves drilling in existing or emerging unconventional shale plays using available horizontal drilling and completiontechniques. The results of our planned exploratory and development drilling in these plays are subject to drilling and completion technique risksand drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of ourundeveloped acreage could decline if drilling results are unsuccessful. Unconventional operations involve utilizing drilling and completion techniquesas developed by ourselves and our service providers. Risks that we face while drilling include, but are not limited to, landing our wellbore in the desireddrilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the wellbore andbeing able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are notlimited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the wellbore during completion operationsand successfully cleaning out the wellbore after completion of the final fracture stimulation stage. 24 Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Niobrara is limited. Ultimately, the success ofthese drilling and completion techniques can only be developed over time as more wells are drilled and production profiles are established over a sufficientlylong time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, leaseexpirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment inthese areas may not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and the value of our undevelopedacreage 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 anddevelopment plans. The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualifiedpersonnel. During these periods, the costs of rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, thedemand 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 oiland gas during the last several years have resulted in shortages of drilling rigs, equipment and personnel, which have resulted in increased costs and shortagesof equipment in the areas where we operate. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demandor otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our financial conditionand 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 ofcovenants imposing significant restrictions on us, including the maximum monthly payment requirement restrictions on our repurchase of, and payment ofdividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sellassets and create liens on our assets. These restrictions may affect our ability to operate our business, to take advantage of potential business opportunities asthey arise and, in turn, may materially and adversely affect our business, financial conditions and results of operations. We could be required to pay liquidated damages to some of our investors if we fail to maintain the effectiveness of a prior registrationstatement. We could default and accrue liquidated damages under registration rights agreements covering approximately 3.2 million shares of our commonstock 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 monthlyliquidated damages of up to $0.23 million. The maximum aggregate liquidated damages are capped at $1.37 million. If we do not make a monthly paymentwithin 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 registrationrights 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, includingthe 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 (includinggroundwater 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. 25 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 orliabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverseeffect 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 mechanicalfailures, contract terms, pipeline and processing plant interruptions, market conditions and weather conditions. These curtailments can last from a few daysto many months. We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult. We periodically evaluateacquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. Thesuccessful acquisition of producing properties requires an assessment of several factors, including: ●recoverable reserves;●future oil and natural gas prices and their appropriate differentials;●development and operating costs; and●potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties. Our reviewwill not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies andpotential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even whenan inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all orpart 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 ourswhile 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 benefitsanticipated 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 seniormanagement may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage ourbusiness. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a resultof 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 meetour 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 geologicalinformation, 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 aprospect that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testingwhether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion cost or to be economically viable. The useof 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 ornatural 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 weperform using data from other wells, more fully explored prospects or producing fields will be useful in predicting the characteristics and potential reservesassociated with our drilling prospects. 26 Our reserve estimates will depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates orunderlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves iscomplex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significantinaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of reserves shownin these reports. In order to prepare reserve estimates in its reports, our independent petroleum consultant projected production rates and timing of developmentexpenditures. Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data. The extent, quality andreliability 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 gasprices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherentlyimprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil andnatural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value ofour reserves. In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results,prevailing oil and natural gas prices and other factors, many of which are beyond our control. Risks Relating to the Oil and Gas Industry Oil and natural gas prices are highly volatile, and our revenue, profitability, cash flow, future growth and ability to borrow funds or obtainadditional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and naturalgas. 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 receivefor 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 (“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 oiland natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for andproject 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 gasthat we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Inaddition, 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 affectour financial position, financial results, cash flows, access to capital and ability to grow. 27 Our industry is highly competitive, which may adversely affect our performance, including our ability to participate in ready to drill prospects inour core areas. We operate in a highly competitive environment. In addition to capital, the principle resources necessary for the exploration and production ofoil 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 havefinancial and other resources substantially greater than ours. We cannot assure you that such materials and resources will be available when needed. If we areunable to access material and resources when needed, we risk suffering a number of adverse consequences, including: ●the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests;●loss of reputation in the oil and gas community;●a general slowdown in our operations and decline in revenue; and●decline in market price of our common shares. Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demandfor oil and natural gas. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present anendangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’satmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions ofgreenhouse gases under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, oneof which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases fromcertain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gasemission sources in the United States on an annual basis, including petroleum refineries, as well as certain onshore oil and natural gas production facilities. In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half ofthe states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissioninventories 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. Thenumber 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 topurchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any suchlegislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs, and natural gas weproduce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financialcondition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in theEarth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, andfloods 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. 28 Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operatingrestrictions or delays in the completion of oil and natural gas wells. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rockformations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulateproduction. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oiland natural gas commissions, but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under thefederal Safe Drinking Water Act. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing underthe Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Under the proposed legislation, thisinformation would be available to the public via the internet, which could make it easier for third parties opposing the hydraulic fracturing process to initiatelegal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. At the state level, some stateshave adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well constructionrequirements on hydraulic fracturing activities. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process areadopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in thepursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and a committee of theU.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, orhave been requested to review, environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmentaleffects of hydraulic fracturing on drinking water and groundwater, with final results expected by 2014. In addition, the U.S. Department of Energy isconducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completionmethods. The U.S. Department of the Interior is conducting a rule making, likely to result in new disclosure requirements and other mandates for hydraulicfracturing on federal lands. These ongoing studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to furtherregulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms. We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business. Our operations aresubject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, and operatingsafety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legalrequirements may result in substantial penalties and harm to our business, results of operations and financial condition. We may be required to make largeand 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 orrestrictions. 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 portionof our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated.See “Business and Properties—Government Regulations” for a more detailed description of our regulatory risks. 29 Our operations may incur substantial expenses and resulting liabilities from compliance with environmental laws and regulations. Our oil andnatural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment orotherwise 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 productionactivities, including new environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulicfracturing of wells;●limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and●impose substantial liabilities for pollution resulting from our operations. 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 materialadverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental lawsand regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whetherwe were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Our permitsrequire that we report any incidents that cause or could cause environmental damages. See “Business and Properties—Government Regulations” for a moredetailed description of our environmental risks. Risks Relating to Our Common Stock There is a limited public market for our shares and we cannot assure you that an active trading market or a specific share price will be establishedor maintained. Our common stock trades on the Nasdaq Global Market, generally in small volumes each day. The value of our common stock could beaffected by: ●actual or anticipated variations in our operating results;●changes in the market valuations of other oil and gas companies;●announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;●adoption of new accounting standards affecting our industry;●additions or departures of key personnel;●sales of our common stock or other securities in the open market;●actions taken by our lenders or the holders of our convertible debentures;●changes in financial estimates by securities analysts;●conditions or trends in the market in which we operate;●changes in earnings estimates and recommendations by financial analysts;●our failure to meet financial analysts’ performance expectations; and●other events or factors, many of which are beyond our control. In a volatile market, you may experience wide fluctuations in the market price of our securities. These fluctuations may have an extremely negative effect onthe market price of our common stock and may prevent you from obtaining a market price equal to your purchase price when you attempt to sell our commonstock in the open market. In these situations, you may be required either to sell at a market price which is lower than your purchase price, or to hold ourcommon stock for a longer period of time than you planned. An inactive market may also impair our ability to raise capital by selling shares of capital stockand may impair our ability to acquire other companies or oil and gas properties by using common stock as consideration. 30 Our common stock is subject to penny stock rules which limit the market for our common stock. The SEC has adopted Rule 15g-9 which establishesthe definition of a “penny stock,” for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with anexercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require: ●that a broker or dealer approve a person’s account for transactions in penny stocks; and●that broker or dealer receives from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to bepurchased.In order to approve a person’s account for transactions in penny stocks, the broker or dealer must: ●obtain financial information and investment experience objectives of the person; and●make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge andexperience in financial matters to be capable of evaluating the risks of transactions in penny stocks.The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stockmarket, which, in highlight form: ●sets forth the basis on which the broker or dealer made the suitability determination; and●that the broker or dealer received a signed, written agreement from the investor prior to the transaction.Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissionspayable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor incases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in theaccount and information on the limited market in penny stocks. Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors todispose of our common stock and cause a decline in the market value of our stock. Sales of a substantial number of shares of our common stock, or the perception that such sales might occur, could have an adverse effect on theprice of our common stock. As of December 31, 2012, approximately 13.82% of our common stock was held by Hexagon, and two other investors holdmore than 5%. Sales by Hexagon or our other large investors of a substantial number of shares of our common stock into the public market, or the perceptionthat such sales might occur, could have an adverse effect on the price of our common stock.We may issue shares of preferred stock with greater rights than our common stock. Our articles of incorporation authorize our board of directors toissue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferredstock that is issued may rank ahead of our common stock, in terms of dividends, liquidation rights and voting rights.There may be future dilution of our common stock. To the extent options to purchase common stock under our employee and director stock option plans,outstanding warrants to purchase common stock are exercised or the price vesting triggers under the performance shares granted to our executive officers aresatisfied, or additional shares of restricted stock are issued to our employees, holders of our common stock will experience dilution. As of December 31, 2012,we had outstanding options and warrants to purchase 5,638,900 shares of common stock at a weighted average exercise price of $7.00. If we sell additionalequity or convertible debt securities, such sales could result in increased dilution to our existing stockholders and cause the price of our outstanding securitiesto decline. Further, our convertible debentures, currently convertible into 3,152,941 shares of our common stock, include a full-ratchet anti-dilution provisionthat provides for the adjustment of the conversion price in the event we sell additional equity or convertible securities at a price that is below the $4.25conversion price of the debentures. 31 We do not expect to pay dividends on our common stock. We have never paid dividends with respect to our common stock, and we do not expect to payany dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, the credit agreementrelating to our credit facility prohibits us from paying any dividends and the indenture governing our senior notes restricts our ability to pay dividends. In thefuture, we may agree to further restrictions.Our common stock is an unsecured equity interest in our Company. As an equity interest, our common stock is not secured by any of our assets.Therefore, in the event we are liquidated, the holders of the common stock will receive a distribution only after all of our secured and unsecured creditors havebeen paid in full. There can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution tothe holders of the common stock.Securities analysts may not initiate coverage of our shares or may issue negative reports, which may adversely affect the trading price of theshares. We cannot assure you that securities analysts will cover our company. If securities analysts do not cover our company, this lack of coverage mayadversely 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 publishabout 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 oneor 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 sharesto decline. Further, because of our small market capitalization, it may be difficult for us to attract securities analysts to cover our company, which couldsignificantly and adversely affect the trading price of our shares. Failure to maintain an effective system of internal control over financial reporting may have an adverse effect on our stock price. Pursuant toSection 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the Securities and Exchange Commission, or the SEC, toimplement Section 404, we are required to furnish a report by our management to include in our annual report on Form 10-K regarding the effectiveness of ourinternal control over financial reporting. The report includes, among other things, an assessment of the effectiveness of our internal control over financialreporting as of the end of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessmentmust include disclosure of any material weaknesses in our internal control over financial reporting identified by management. We may discover areas of our internal control over financial reporting which may require improvement. If we are unable to assert that our internalcontrol over financial reporting is effective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internalcontrols, we could lose investor confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price. Item 1B.UNRESOLVED STAFF COMMENTSNot applicable.Item 3.LEGAL PROCEEDINGSParker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene ingarnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant has served various writs ofgarnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested, restricted stock. The Company hasasserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. As a result ofbankruptcy proceedings filed by Mr. Parker, the garnishment proceedings have been stayed. At this stage, we cannot express an opinion as to the probableoutcome of this matter.There are no other material pending legal proceedings to which we or our properties are subject. 32 Item 4.MINE SAFETY DISCLOSURES Not applicable.PART II Item 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITYSECURITIES Recent Market Prices On November 2, 2011 our common stock began trading on the Nasdaq Global Market under the symbol "RECV." Between September 25, 2009 andNovember 1, 2011 our stock traded on the OTC Bulletin Board under the symbol "RECV.OB." The following table shows the high and low reported sales prices of our common stock for the periods indicated. Effective October 19, 2011 we completed a1:4 reverse stock split, and stock prices prior to such date have been adjusted to reflect the effect of the stock split. High Low 2012 Fourth Quarter $4.95 $1.40 Third Quarter $4.75 $1.64 Second Quarter $3.99 $2.25 First Quarter $4.90 $2.31 2011 Fourth Quarter $7.00 $2.99 Third Quarter $11.00 $4.88 Second Quarter $13.00 $8.80 First Quarter $15.56 $7.80 On March 29, 2013, there were approximately 30 owners of record of our common stock. Dividend Policy We have never paid any cash dividends on our common stock and do not anticipate paying any dividends in the foreseeable future. Our current business planis to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at thediscretion of our board of directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as ourboard 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 ourunregistered securities during 2012.Item 6. SELECTED FINANCIAL DATA Not applicable. 33 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 in Part IV in this annual report. This discussioncontains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in theseforward-looking statements as a result of various factors including those set forth under Item “1A. Risk Factors”. 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 DJBasin. Our business strategy is designed to create shareholder value by developing our undeveloped acreage and leveraging the knowledge, expertise andexperience of our management team. We principally target low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningfulproduction and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Colorado, Nebraska, andWyoming within the DJ Basin. The majority of our leases on which we have identified reserves and production are subject to security interests held by the lenders under our secured termloans or our 8% Senior Secured Convertible Debentures. As discussed below, we have recently amended the terms of both the secured term loans and the 8%Senior Convertible Debentures to among other things, extend the maturity dates under both the term loans and the debentures, and reduce the interest rate andthe level of minimum monthly payments under the term loans. We currently have $19.34 million outstanding under our term loans and $13.40 millionoutstanding under our debentures. In addition, we currently have a working capital deficit of approximately $1.04 million, and approximately $3.63 million incurrent liabilities. We believe that the amendments referenced above provide us with significantly more flexibility in meeting our obligations. In the immediateterm, the Company expects that additional capital will be required to fund its capital budget for 2013, partially to fund some of its ongoing overhead, providefor payment of minimum interest and principal payments required by term notes, and to provide additional capital to generally improve its working capitalposition. In addition, as discussed below, we have entered into an agreement with one of our existing debenture holders to invest at least $1.5 million inadditional debentures on substantially the same terms as our existing senior secured debentures, with the possibility of an additional investment by ourexisting debenture holders of up to $3.5 million. We are aggressively exploring a number of other capital raising transactions aimed at improving our liquidityposition in the long and short term, including asset sales, joint ventures and similar industry partnerships, asset monetization transactions, possible equitytransactions, and other potential refinancing transactions with terms more favorable to us than those under the term loans and debentures. Our ability to fundsome of our ongoing overhead, to meet our minimum principal and interest obligations and to fund our 2013 capital program is contingent on successfullyraising additional capital via one or more of the above described transactions. On a longer term basis, the Company will require capital to retire our term notes and our 8% Senior Secured Convertible Debentures when such debts maturein May 2014. Pursuant to our credit agreements with Hexagon, a substantial portion of our monthly net revenues derived from our producing properties is required to be usedfor debt and interest payments. In addition, our debt instruments contain provisions that, absent consent of Hexagon, may restrict our ability to raiseadditional capital. Financial Condition and Liquidity We have incurred a cumulative net loss of approximately $106.22 million, negative working capital of $1.04 million and current liabilities of $3.63 millionfor the year ended December 31, 2012. Information about our financial position is presented in the following table: Year ended December 31, 2012 2011 Financial Position Summary Cash and cash equivalents $970,035 $2,707,722 Working capital $(1,041,491) $1,294,706 Balance outstanding on term loans and convertible debentures payable $32,736,341 $29,680,636 Shareholders’ equity $12,082,212 $49,668,225 34 During the year ended December 31, 2012, our working capital decreased to negative $1.04 million compared to positive working capital of $1.29 million atDecember 31, 2011. This lower level of working capital is primarily the result of cash used in operations and cash investing activities that exceeded cashprovided by financing activities. In view of the maturity of our secured indebtedness in 2014, we will be required to complete a capital-raising transaction,such as a sale of assets, an offering of our securities, or a refinancing transaction with terms more favorable to us, before our secured debt matures. If wedefault under our secured debt, our lenders will be entitled to exercise their rights to foreclose on the properties held as security for the term loans and thedebentures, and may be entitled to collect any amounts remaining under the loans and debentures that is not satisfied through sale of such properties. Pursuant to our credit agreements with Hexagon, a substantial portion of our monthly net revenues derived from our producing properties is required to be usedfor debt and interest payments. In addition, our debt instruments contain provisions that, absent consent of the lenders, may restrict our ability to raiseadditional capital.Cash Flows Cash used in operating activities during the year ended December 31, 2012 was $3.39 million. This use of cash, coupled with the cash used in investingactivities, exceeded cash provided by financing activities by $1.74 million, and resulted in a corresponding decrease in cash. This net use of cash contributedto a $2.34 million decrease in working capital as of December 31, 2012, compared to working capital as of December 31, 2011. The following table compares cash flow items during the year ended December 31, 2012 to December 31, 2011: Year ended December 31, 2012 2011 Cash provided by (used in): Operating activities $(3,389,403) $(570,247)Investing activities (1,403,961) (13,308,468)Financing activities 3,055,677 11,057,693 Net change in cash $(1,737,687) $(2,821,022) During the year ended December 31, 2012, net cash used in operating activities was $3.39 million, compared to a net cash used in operating activities of$0.57 million during the year ended December 31, 2011, an increase of $2.82 million or 494%. The primary changes in operating cash during the year endedDecember 31 2012 was $37.74 million of net loss, adjusted for non-cash charges of $6.87 million of depreciation, depletion, amortization and accretionexpenses, $26.66 million of impairment of developed acreage, $1.60 million of amortization of deferred financing costs and issuance of stock for convertibledebentures interest, and offset by a non-cash change in fair value of convertible debentures conversion option of $0.32 million, $0.97 million of an increase instock-based compensation expense, and offset by a non-cash charge for the change in commodity price derivatives of $0.86 million.During the year ended December 31, 2012, net cash used in investing activities was $1.40 million, compared to net cash used in investing activity of $13.31million during the year ended December 31, 2011, an increase of $11.91 million or 89%. The primary changes in investing cash during the year endedDecember 31, 2012 were $0.54 million related to our acquisitions of undeveloped acreage and drilling capital expenditures of $4.53 million offset by theproceeds from the sale of undeveloped acreage of $2.92 million and proceeds from hedge settlements of $0.78 million. 35 During the year ended December 31, 2012, net cash provided by financing activities was $3.06 million, compared to net cash provided by financing activitiesof $11.06 million during the year ended December 31, 2011, a decrease of $8 million, or 72%. The changes in financing cash during the year endedDecember 31, 2012 were due to net proceeds from the issuance of new convertible debentures of $5.00 million, offset by the net repayments of debt of $1.94million.As of December 31, 2012 our balances outstanding on term loans and convertible debentures was $32.74 million, compared to $29.68 million as ofDecember 31, 2011. The primary changes in the balances outstanding relate to an increase of $5.0 million in 2012 in our convertible debentures, offset byprincipal payments on our secured debts of $1.94 million.In April 2013, we amended both our secured term loans and our 8% Senior Secured Convertible Debentures to extend their maturity dates to May 16, 2014. Inconsideration for the extended maturity date of both loans and the reduced interest rate and minimum loan payment under the secured term loans, theCompany will be required to provide both Hexagon and the holders of our debentures an additional security interest in 15,000 acres (or 30,000 acres inaggregate) of our undeveloped acreage. Additionally, pursuant to the amendment to our secured term loan, Hexagon has agreed to (i) reduce our interest ratefrom 15% to 10% beginning retroactively with March 2013, (ii) permit us to make interest-only payments for March, April, May, and June, after which timethe minimum secured term loan payment will be $0.23 million or $0.19 million, depending on our ability to consummate the sale of certain of our assets byJuly 1, 2013, and (iii) forbear from exercising its rights under the term loan credit agreements for any breach that may have occurred prior to the amendment.In addition, we are required under the amendment to use our reasonable best efforts to pursue certain transactions to improve our financial condition, includingthe aforementioned sale of certain of our assets, an equity offering or similar capital-raising transaction, one or more joint venture development agreements, andan engineering study of certain of our producing properties to ascertain possible operations to enhance production from those properties. Pursuant to thedebenture amendment, the Company and the debenture holders have agreed to waive any breach under the debentures that may have occurred prior to the dateof the amendment. On April 16, 2013, the Company entered into an agreement with one of its existing Debenture holders to issue up to an additional $5.0 million in additionaldebentures with substantially the same terms to the existing 8% Secured Convertible Debentures. Under the terms of this agreement, $1.5 million ofadditional debentures will be issued on or before July 16, 2013. The funds associated with the initial issuance of debentures will be used by the Company forthe drilling and development of certain properties, and for general corporate purposes. We currently have $19.34 million outstanding under our secured term loans and $13.40 million outstanding under our 8% Senior Convertible Debentures. Inaddition, we currently have a working capital deficit of approximately $1.04 million, and approximately $3.63 million in current liabilities. We believe that theamendments discussed above provide us with significantly more flexibility in meeting our obligations. We are aggressively seeking to obtain this additionalcapital through a combination of the issuance of additional equity or debt securities, use of existing working capital and operating cash flows, and from cashprovided by potential joint venture participants. We may also choose to sell certain assets in order to partially repay our secured debt and supplement thefunding of our 2013 capital budget. Currently, we have no agreements or understandings with any third parties for additional capital. Further, under the terms of our term loan agreements, we areprohibited from incurring any additional debt from third parties without prior consent from Hexagon. Our ability to obtain additional working capital throughbank lines of credit and project financing would likely be subject to the repayment of the approximately $19.34 million debt related to our primary creditfacility. 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 anyavailable financing will be subject to commercially reasonable terms. If we are unable to access additional capital in significant amounts as needed, we maynot 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 ourbusiness. In such an event, our stock price will be materially adversely affected.Notable Financing TransactionsIn December 2011, we sold certain undeveloped acreage for total proceeds of $4.5 million. In February 2012, we completed the sale of our Grover Prospect acreage, under which we agreed to sell all of our oil and gas leases in the Grover Field in WeldCounty, Colorado to Bill Barrett Corporation for approximately $4.54 million. On March 19, 2012, we entered into agreements with our existing convertible debenture holders to issue up to an additional $5.0 million in convertibledebentures (the “Supplemental Debentures”). All terms of the new convertible debentures are substantively identical to the existing convertible debentures. Thisfinancing was completed in August 2012. In August 2012, the Company restructured the terms of the Supplemental Debenture offering and concluded the offering by issuing an additional $1.96million of convertible debentures. On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLCfor acting as a placement agent of the Supplemental Debentures. On November 5, 2012, the Company liquidated all of its price derivatives (commodity hedges) for proceeds of $0.61 million. As of December 31, 2012, theCompany did not have any derivative instruments.In December 2012, the Company leased certain deep rights to 6,300 undeveloped acres to a private company for proceeds of approximately $1.50 million, ofwhich $0.75 million was paid toward principal on our long-term debt. As discussed above, in April 2013 we amended both our senior secured debentures, including the Supplemental Debentures, and our secured term loans. See“Cash Flows” above.  36 Term LoansThe Company entered into three separate loan agreements with Hexagon in January, March and April 2010, each with an original maturity date of December 1,2010. All three loans originally bore annual interest of 15% (which has been reduced, as discussed below), currently mature on May 16, 2014, have similarterms, including customary representations and warranties and indemnification, and require the Company to repay the loans with the proceeds of the monthlynet revenues from the production of the acquired properties. The loans contain cross collateralization and cross default provisions and are collateralized bymortgages against a portion of the Company’s developed and undeveloped leasehold acreage.We entered into a loan modification agreement on May 28, 2010, which extended the maturity date of the loans to December 1, 2011. In consideration forextending the maturity of the loans, Hexagon received 250,000 warrants with an exercise price of $6.00 per share. The loan modification agreement alsorequired the Company to issue 250,000 five year warrants to purchase common stock at $6.00 per share to Hexagon if the Company did not repay the loans infull by January 1, 2011. Since the loans were not paid in full by January 1, 2011, the Company issued 250,000 additional warrants with an exercise price of$6.00 per share to Hexagon which was valued at approximately $1.60 million. This amount was recorded as a deferred financing cost and is being amortizedover the remaining term of the loan. In December 2010, Hexagon extended the maturity date of the loans to September 1, 2012. During the last six months of 2011, Hexagon agreed to temporarilysuspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2.00 million as payment on the loans. InNovember 2011, Hexagon extended the maturity to January 1, 2013. In November 2011, Hexagon also temporarily advanced the Company an additionalamount of $0.31 million, which was repaid in full in February 2012. In March 2012, Hexagon extended the maturity of the loans to June 30, 2013, and inconnection there with, the Company agreed to make minimum monthly note payments of $0.33 million, effective immediately. In July 2012, Hexagonextended the maturity date to September 30, 2013. In November 2012, Hexagon extended the maturity date of the loans to December 31, 2013. On December 27, 2012, in connection with the Company’s lease of deep rights on approximately 6,300 net acres to a third party for total consideration of$1.5 million, the Company paid Hexagon $0.75 million, which reduced the long-term debt principal amount. As discussed above, we reached agreement in April 2013 with Hexagon to amend all three loan agreements . See “Cash Flows” above. The Company is subject to certain non-financial covenants with respect to the Hexagon loan agreements. As of December 31, 2012, the Company was incompliance with all covenants under the facilities. However, we do not currently have sufficient liquidity available to continue to make the monthly paymentsas they come due. Unless we complete a capital-raising transaction, such as a sale of assets (either to our lenders in exchange for loan forgiveness or to a thirdparty, enabling us to pay down our outstanding debt), an offering of our securities, or a refinancing transaction with terms more favorable to us, our lenderswill be entitled to exercise their rights to foreclose on the properties held as security for the term loans and the debentures (as discussed below), and may beentitled to collect any amounts remaining under the loans and debentures that is not satisfied through sale of such properties.Convertible Debentures Payable In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of 8% Senior Secured Debentures (the“Debentures”), secured by mortgages on several of our properties. Initially, the Debentures were convertible at any time at the holders' option into shares of ourcommon stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equityoffering at a lower price per share amount. Interest at an annualized rate of 8% is payable quarterly on each May 15, August 15, November 15 and February15 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 10trading days prior to an interest payment date. The Company can redeem some or all of the Debentures at any time. The redemption price is 115% ofprincipal plus accrued interest. If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price willinclude a make-whole premium equal to the remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable incommon stock. T.R. Winston & Company LLC acted as placement agent for the private placement and received $0.40 million of Debentures equal to 5% ofthe gross proceeds from the sale. The Company is amortizing the $0.40 million over the life of the loan as deferred financing costs. The Company amortized$0.16 million of deferred financing costs into interest expense during the year ended December 31, 2012, and has $0.14 million of deferred financing costs tobe amortized through maturity. 37 In December 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share. This amendment was aninducement consideration to the Debenture holders for their agreement to release a mortgage on certain properties so the properties could be sold. The sale ofthese properties was effective December 31, 2011, and a final closing occurred during the three months ended March 31, 2012. On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to issue up to an additional $5.0 million in additionaldebentures (the “Supplemental Debentures”). Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of SupplementalDebentures were used principally for the development of certain of the Company's proved undeveloped properties and other undeveloped acreage currentlytargeted by the Company for exploration, as well as for other general corporate purposes. Any new producing properties developed from the proceeds ofSupplemental Debentures are to be pledged as collateral under a mortgage to secure future payment of the Debentures and Supplemental Debentures. All termsof the Supplemental Debentures are substantively identical to the Debentures. The Agreements also provided for the payment of additional consideration to thepurchasers of Supplemental Debentures in the form of a proportionately reduced 5% carried working interest in any properties developed with the proceeds ofthe Supplemental Debenture offering.Through July 2012, we received $3.04 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development ofsix new wells, resulting in a total investment of $3.69 million. Five of these wells resulted in commercial production, and one well was plugged andabandoned.In August 2012, the Company and holders of the Supplemental Debentures agreed to renegotiate the terms of the Supplemental Debenture offering. Thesenegotiations concluded with the issuance of an additional $1.96 million of Supplemental Debentures. The August 2012 modifications to the SupplementalDebenture agreements increased the carried working interest from 5% to 10% and also provided for a one-year, proportionately reduced net profits interest of15% in the properties developed with the proceeds of the Supplemental Debenture offering, as well as the next four properties to be drilled and developed by theCompany. As described above, in April 2013 the holders of our 8% Senior Secured Convertible Debentures agreed to extend their maturity date to May 16, 2014. OnApril 16, 2013, the Company entered into an agreement with one of its existing Debenture holders to issue up to an additional $5.0 million in additionaldebentures with substantially the same terms to the existing 8% Secured Convertible Debentures. Under the terms of this agreement, $1.5 million ofadditional debentures will be issued on or before July 16, 2013. The funds associated with the initial issuance of debentures will be used by the Company forthe drilling and development of certain properties, and for general corporate purposes. The Company has estimated the total value of consideration paid to Supplemental Debenture holders in the form of the modified net profits interest and carriedworking interest to be approximately $1.16 million, and recorded this amount as a debt discount to be amortized over the remaining life of the SupplementalDebentures. We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect toDecember 31, 2012, the Supplemental Debentures. This valuation resulted in an estimated derivative liability as of December 31, 2012 and December 31,2011 of $1.68 million and $1.30 million, respectively. The portion of the derivative liability that is associated with the Supplemental Debentures, in theapproximate amount of $0.70 million, has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.During the year ended December 31, 2012 and 2011, the Company amortized $2.36 million and $1.52 million, respectively, of debt discounts.On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of theSupplemental Debentures. The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs. The Company amortized $0.05million of deferred financing costs into interest expense during the year ended December 31, 2012, and has $0.18 million of deferred financing costs to beamortized through May 2014. 38 As of December 31, 2012 and December 31, 2011, the convertible debt is recorded as follows: As ofDecember 31,2012 As ofDecember 31,2011 Convertible debentures $13,400,000 $8,400,000 Debt discount (3,099,639) (3,470,932)Total convertible debentures, net $10,300,361 $4,929,068 Annual debt maturities as of December 31, 2012 are as follows:Year 1 $388,351 Year 2 32,347,963 Thereafter - Total $32,736,314 Failure to make periodic interest payments due under the Debentures (including the Supplemental Debentures) may result in acceleration of all principal andinterest then outstanding under the Debentures, and may entitle the holders of the Debentures to exercise their rights to foreclose under the mortgages securingthe Debentures. In addition, failure to make the required monthly payments under our term loans could result in immediate acceleration of both the term loansand the Debentures.Interest ExpenseFor the year ended December 31, 2012 and 2011, the Company incurred interest expense of approximately $8.06 million and $8.22 million, respectively, ofwhich approximately $4.85 million and $5.02 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretionof the convertible debentures payable discount, and convertible debentures interest paid in common stock. Capital ResourcesOur 2013 capital program is subject to securing sufficient capital, principally via the issuance of additional equity and debt both to fund our capital programand to refinance the Hexagon loans which are due on May 16, 2014. We are aggressively exploring a number of capital raising transactions aimed atimproving our liquidity position in the long and short term, including asset sales, joint ventures and similar industry partnerships, asset monetizationtransactions, possible equity transactions, and other potential refinancing transactions with terms more favorable to us than those under the term loans anddebentures. Currently, the majority of our cash flows from operations are applied to the payment of principal and interest of our loans. Due to the Company’s continuingoperating losses and the large amounts of capital expenditures, during 2011 and 2012, our liquidity and working capital have deteriorated. We will seekadditional capital to refinance our debts, partially fund our operations, and fund our 2013 Capital Budget. We will also require substantial additional capitalin order to fully test, develop and evaluate our 129,000 net undeveloped acres. We expect to obtain this capital through a variety of sources, including, but notlimited to, future debt and equity financings and potentially from future joint venture partners. Unless we are successful in competing a substantial debtand/or equity financing or other similar transaction in the near term, we may be required to sell certain assets in order to meet obligations as they arise. Wecannot provide assurance that we will secure a major financing, nor can we predict the terms of any future potential financing transactions.We cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings, equity offerings or other financings,or asset sales will be sufficient to fund our operations or our anticipated 2013 capital expenditures. 39 Results of Operations Year ended December 31, 2012 compared to the year ended December 31, 2011The following table compares operating data for the fiscal year ended December 31, 2012 to December 31, 2011: 2012 2011 Revenue Oil sales $5,898,459 $7,148,110 Gas sales 406,216 547,190 Operating fees 174,779 117,360 Realized gain on commodity price derivatives 780,135 625,043 Unrealized loss on commodity price derivatives - (75,609)Total revenues 7,259,589 8,362,094 Costs and expenses Production costs 1,421,177 1,514,784 Production taxes 227,455 838,714 General and administrative 4,331,328 10,544,347 Depreciation, depletion and amortization 4,549,303 4,347,117 Bad debt expense 77,957 - Impairment of developed properties 26,658,707 2,821,176 Total costs and expenses 37,265,927 20,066,138 Loss from operations (30,006,338) (11,704,044) Other income 5,896 71,253 Convertible notes conversion derivative gain 320,000 3,821,792 Debt inducement expense - (2,800,000)Interest expense (8,056,232) (8,218,225) Net Loss $(37,736,674) $(18,829,224)Total revenuesTotal revenues were $7.26 million for the year ended December 31, 2012, compared to $8.36 million for the year ended December 31, 2011, a decrease of$1.10 million, or 13%. The decrease in revenues was due primarily to a decrease in production volumes. During December 2012 and 2011, productionamounts were 98,567 and 112, 850 BOE, respectively, a decrease of 14,283, or 13%. The decrease was partially offset by an increase in overall averageprice per BOE to $63.96 in 2012 from $62.64 in 2011, an increase of $1.32 or 2%. Additionally, in 2012 the Company had increases in realized gains fromcommodity price hedges and operating fees.The following table shows a comparison of production volumes and average prices: For theYear Ended December 31, 2012 2011 Product Oil (Bbl.) 68,207 81,433 Oil (Bbls)-average price (1) $86.48 $87.78 Natural Gas (MCF)-volume 80,438 88,999 Natural Gas Liquids (NGL) - BOE 16,953 26,584 Natural Gas (MCF)-average price (2) $5.05 $6.15 Barrels of oil equivalent (BOE) 98,567 122,850 Average daily net production (BOE) 270 337 Average Price per BOE (1) 63.96 $62.64 (1) Does not include the realized price effects of hedges(2) Includes proceeds from the sale of NGL's Oil and gas production costs, production taxes, depreciation, depletion, and amortization Average Price per BOE(1) $63.96 $62.64 Production costs per BOE 14.42 12.33 Production costs per BOE 14.42 12.33 Production taxes per BOE 2.31 6.83 Depreciation, depletion, and amortization per BOE 46.15 35.39 Total operating costs per BOE $62.88 $54.55 Gross margin per BOE $1.08 $8.09 Gross margin percentage 2% 13% (1) Does not include the realized price effects of hedgesCommodity Price Derivative ActivitiesChanges in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivativeinstruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted exclusively of swaps. Theduration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operatingstrategy.Commodity price derivative net realized gain was $0.78 million during the year ended December 31, 2012, as compared to a realized gain of $0.63 million forthe year ended December 31, 2011, for a decrease in realized gain of $0.15 million, or 24%. We also recorded no unrealized gain on commodity pricederivatives for the year ended December 31, 2012 compared to a loss of $0.08 million during the year ended December 31, 2011, for an increase of $0.8million, or 100%. The Company had no commodity price derivatives at December 31, 2012.Production costsProduction costs were $1.42 million during the year ended December 31, 2012, compared to $1.51 million for the year ended December 31, 2011, a decreaseof $0.09 million, or 6%. Decrease in production costs in 2012 was from a decrease on the number of work overs, property improvements, and onsite workon productive wells. Production costs per BOE increased to $14.42 in 2012 from $12.33 in 2011, an increase of $2.09 per BOE, or 17%. The increase perBOE increased was from a decrease in BOE to 98,567 from 122,850, a decrease of 24,283 or 20% compared to a decrease of production costs of 6%, for theyears ended December 31, 2012 and 2011, respectively. 40 Production taxesProduction taxes was $0.23 million for the year ended December 31, 2012, compared to $0.84 million for the year ended December 31, 2011, a decrease of$0.61 million , or 73%. Decrease in production taxes was from a decrease in production and product mix per state. Currently, ad valorem, severance andconservation taxes range from 1% to 10% based on the state and county which production is derived. Production taxes per BOE decreased to $2.31 in 2012from $6.83 in 2011, a decrease of $4.52 or 66%.General and administrativeGeneral and administrative expenses were $4.33 million during the year ended December 31, 2012, compared to $10.54 million during the year endedDecember 31, 2011, a decrease of $6.21 million, or 59%. In 2012, general and administrative includes an adjustment to non-cash consulting fee and othernon-cash compensation expenses that resulted in income of $0.40 million compared to an expense of $6.70 million during the year ended December 31, 2011.The year ended December 31, 2012, also includes a non-cash income item related to the separation agreement of our former CEO. On November 15, 2012,Roger Parker retired from the Company as its chief executive officer. At the time of his retirement, Mr. Parker had 1,350,000 shares of unvested common stockoutstanding. As a result of his separation from the Company, it was deemed improbable that these shares would vest to Mr. Parker in his capacity as anemployee of the Company due to the termination of employment; however, it was deemed probable that these shares will vest under his separation agreement. As a result, the Company reversed all of the compensation expense, in the amount of $6.75 million, associated with stock grants to Mr. Parker during histenure as an employee. In conjunction with Mr. Parker’s retirement, the Company and Mr. Parker entered into a separation agreement that provided, in part,for the payment of severance equal to one year of Mr. Parker’s salary. Pursuant to the termination agreement, the 1,350,000 shares of unvested restricted stockthat would otherwise have been forfeited upon his termination will vest in two tranches, 675,000 on May 15, 2013, and the remaining 675,000 on November15, 2013, subject to Mr. Parker’s execution of a mutual release, and Mr. Parker’s availability to the Company for a minimum of 10 hours per week during theseverance period on a consulting basis. Thus, the Company recorded a consulting expense (in the amount of $3.59 million) related to the shares of stock thatare expected to vest during the severance period of the separation agreement. The net difference of these two amounts resulted in a reduction in 2012 generaland administrative expenses (non-cash compensation expense) of $3.16 million.Excluding the above referenced non-cash items, cash general and administrative for the year ended December 31, 2012 was $4.47 million compared to $3.9million during the year ending December 31, 2011, an increase of $0.57 million, or 12.8%. The increase in cash general and administrative expenses was dueto increases in professional and consulting fees, cash salary expense, and insurance expense.The separation agreement with Mr. Parker provided that Mr. Parker receive severance payments consisting of one year’s salary and health benefits for theyear. In return, the Company received a general release and certain non-compete terms from Mr. Parker, and also is entitled to receive no less than 10 hours perweek of Mr. Parker’s time as a consultant to the Company. As of December 31, 2012, the Company owes Mr. Parker $0.26 million in severance salary andhealth insurance, all of which was accrued as an expense during the year ended December 31, 2012.Depreciation, depletion, and amortizationDepreciation, depletion, and amortization were $4.55 million during the year ended December 31, 2012, compared to $4.35 million during the year endedDecember 31, 2011, an increase of $0.20 million, or 5%. Increase in depreciation, depletion, and amortization was from production amounts decreasing to98,567 from 122,850 for the years ended December 31, 2012 and 2011, respectively, a decrease of 24,283, or 19% and a decrease in reserves to $15.42million from $20.01 million of $4.59 million or 23%, respectively. Depreciation, depletion, and amortization per BOE increased to $46.15 from $35.59,respectively, for the years ended December 31, 2011 and 2012, an increase of $10.56, or 30%, from a decrease of reserves of 23%. 41 Impairment of developed propertiesImpairment of developed properties was $26.66 million during the year ended December 31, 2012, compared to $2.82 million during the year endedDecember 31, 2011, an increase of $23.84 million or 845%. The increase was a result of capitalized costs exceeding the standardized measure of reservevalues, and in particular was related to the impairment of undeveloped acreage and wells in progress related to the Company's Chugwater prospect, in the totalamount of $17.09 million, which were transferred to the full cost pool. As a result of the Company’s review for impairment in its undeveloped acreage, theCompany also transferred $5.94 million of undeveloped acreage costs relating principally to leases that have lease terms that expire throughout 2015 which theCompany is not intending to extend. Furthermore, the Company reduced the PV-10 of the proved undeveloped reserve acreage by utilizing a promoted basiswhich reduced the reserve production amounts to 25% of the Company’s 100% ownership. As a result, the ceiling test performed by the Company yielded anincreased impairment. The combination of these impairments and the respective transfers to the full cost pool resulted in total 2012 impairment expense of$26.66 million.Interest ExpenseInterest expense was $8.06 million during the year ended December 31, 2012, compared to $8.22 million during the year ended December 31, 2011, adecrease of $0.16 million, or 2%. Interest expense, during December 31, 2012, includes non-cash loan costs amortization and debt discount of $4.85 million,and cash interest expense of $3.2 million, compared to cash interest expense of $3.2 million, during the year ended December 31, 2011. Cash interestremained consistent due to the level of debt.Off-Balance Sheet Arrangements We do not have any off-balance sheet arrangements.2013 Capital BudgetOur 2013 Capital Budget is currently projected to be approximately $15 million, but is subject to securing sufficient capital to support planned drilling anddevelopment expenses. We anticipate that approximately 50% of this budget will be allocated toward the development of two of our unconventional prospectslocated in the Wattenberg field within the DJ Basin that will target horizontal drilling and development of the Niobrara shale and Codell formations. Theremainder of our 2013 budget is anticipated to be directed principally toward the conventional development of certain lower risk offset wells to existingproduction. We also anticipate the allocation of approximately 10% of our 2013 capital budget toward higher risk exploration activities, including theprocurement of seismic data and the drilling of one conventional exploratory well.Our 2013 capital expenditure budget was subject to various factors, including market conditions, availability of capital, oilfield services and equipmentavailability, commodity prices and drilling results. Results from the wells identified in the capital budget may lead to additional adjustments to the capitalbudget as the cash flow from the wells could provide additional capital which we may use to increase our capital budget. We do not anticipate any significantexpansion of our current acreage position.Other factors that could cause us to 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 commodityprices or well performance that exceeds our forecasts, any of which could positively impact our operating cash flow. Factors that could cause us to reduce levelof 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.Plan of Operations Our plan of operations is to identify and develop oil and natural gas prospects from our existing inventory of undeveloped acreage. We anticipate theinvestment of substantial capital during the next few years to evaluate, assess and develop this inventory. Currently, our inventory of developed andundeveloped acreage includes approximately 21,800 net acres that are held by production, approximately 12,900 net acres that expire in 2013, andapproximately 25,000 net acres, 59,000 net acres and 10,300 net acres that expire in the years 2014, 2015 and thereafter, respectively. Approximately 64% ofour inventory of undeveloped acreage provide for extension of lease terms from two to five years, at the option of the Company, via payment of varying, buttypically nominal, extension amounts. However, due to our current liquidity issues, we may enter into one or more transactions to sell a significant number ofleases, both developed and undeveloped to enable us to pay down our outstanding debt. 42 The business of oil and natural gas acquisition, exploration and development is capital intensive and the level of operations attainable by an oil and gascompany 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 additionalcapital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties. Asexplained under “Financial Condition and Liquidity”, based on our present working capital and current rate of cash flow from operations, we will need toraise additional capital to partially fund our overhead, and fund our exploration and development budget through, at least, December 31, 2013. We will seekadditional capital through the sale of our securities, through debt and project financing, and through sale of assets. However, under the terms of our term loanagreements and debentures, we are prohibited from incurring any additional debt from third parties or selling any properties held as collateral under the termloans or debentures without prior consent from the lenders. Thus our ability to obtain additional capital through new debt instruments, project financing andsale of assets may be subject to the repayment of our term loans and/or our debentures. 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 retainflexibility in terms of project management. Marketing and Pricing We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oiland natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. The market price foroil 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 alsoaffect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adverselyaffect the value of our reserves and make it uneconomical for us to commence or continue production levels of oil and natural gas. Historically, the pricesreceived for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are: ●changes in global supply and demand for oil and natural gas;●the actions of the Organization of Petroleum Exporting Countries, or OPEC;●the price and quantity of imports of foreign oil and natural gas;●acts of war or terrorism;●political conditions and events, including embargoes, affecting oil-producing activity;●the level of global oil and natural gas exploration and production activity;●the level of global oil and natural gas inventories;●weather conditions;●technological advances affecting energy consumption; and●the price and availability of alternative fuels. From time to time, we will enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas. Hedging arrangements mayexpose 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. 43 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 anyhedging 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 toengage 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 inhedging transactions. Obligations and Commitments We have the following contractual obligations and commitments as of December 31, 2012 (in thousands): Payments due by period Contractual obligations Total Within 1year 1-3 years 4-5 years More than5 years Secured debt $19,336,314 $388,351 $18,947,963 $- $- Interest on secured debt 2,309,767 1,603,761 706,006 - - Convertible debentures 13,400,000 - 13,400,000 - - Separation agreement with Roger Parker (2) 256,569 256,569 - - - Interest on convertible debentures 1,476,978 1,072,000 404,978 - - Operating leases 89,520 89,520 - - - Total contractual cash obligations (1) $36,869,148 $3,410,201 $33,458,947 $- $- (1) We could be liable for liquidated damages under registration rights agreements covering approximately 3.2 million shares of our common stock ifwe fail to maintain the effectiveness of a prior registration statement as required in the agreements. In such case, we would be required to paymonthly liquidated damages of up to $228,050. The maximum aggregate liquidated damages are capped at $1,368,300.(2) Includes $224,700 salary, $17,942 employer taxes, $13,927 health, dental, and vision insurance, in accordance with Mr. Parker’s separationagreement dated November 15, 2012. 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, requiresour management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure ofcontingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. Thefollowing is a summary of the significant accounting policies and related estimates that affect our financial disclosures. 44 Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial conditionand 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 timethe 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 ofoperations or financial condition. Use of Estimates The financial statements included herein were prepared from the records of Recovery in accordance with GAAP, and reflect all normal recurring adjustmentswhich are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods. Thepreparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts ofoil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts ofrevenues and expenses during the reporting period. We evaluate our estimates on an on-going basis and base our estimates on historical experience and onvarious other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under differentassumptions or conditions, we believe that our estimates are reasonable. Our most significant financial estimates are associated with our estimated proved oiland 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 assetheld 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 theacquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration anddevelopment costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gasreserves. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may notexceed 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 outflowsassociated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unprovedproperties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the SEC rules, we prepared our oil and gas reserve estimatesas of December 31, 2012, using the average, first-day-of-the-month price during the 12-month period ending December 31, 2012. Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies oninterpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. Theprocess 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; theinterpretation 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 andproduction company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used asthe basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation andimpairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and naturalgas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existingeconomic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark pricesand costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gasremaining 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 forwhich the reserve estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discount rate. Although reserveestimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producingoil 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 operatingand 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. Forpurposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions anddispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in theperiod in which the reserves or net cash flow estimate changes. 45 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 asingle 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 grossproved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit ofmeasure.Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. This undeveloped acreage is assessed quarterly toascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or theamount 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 rateof 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 anamount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleumengineers. The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the end ofthe applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financingcosts, future site restoration costs and income taxes. Under the full cost method of accounting, capitalized oil and natural gas property costs, lessaccumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future netrevenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed thisceiling, we would recognize impairment.Impairment of developed properties was $26.66 million during the year ended December 31, 2012, compared to $2.82 million during the year endedDecember 31, 2011, an increase of $23.84 million or 845%. The increase was a result of capitalized costs exceeding the standardized measure of reservevalues, and in particular was related to the impairment of undeveloped acreage and wells in progress related to the Company's Chugwater prospect, in the totalamount of $17.09 million, which were transferred to the full cost pool. As a result of the Company’s review for impairment in its undeveloped acreage, theCompany also transferred $5.94 million of undeveloped acreage costs relating principally to leases that have lease terms that expire throughout 2015 which theCompany is not intending to extend. Furthermore, the Company reduced the PV-10 of the proved undeveloped acreage by utilizing a promoted basis whichreduced the production amounts to 25% of the Company’s 100% ownership. As a result, the ceiling test performed by the Company yielded an increasedimpairment. The combination of these impairments and the respective transfers to the full cost pool resulted in total 2012 impairment expense of $26.66million.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 receivedbefore taking into account production taxes and transportation costs, which are reported as separate expenses and are included in oil and gas productionexpense 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 producthas transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price theCompany will receive. The Company uses its knowledge of its properties, their historical performance, NYMEX and local spot market prices, quality andtransportation differentials, and other factors as the basis for these estimates. 46 Share Based Compensation The Company accounts for share-based compensation by estimating the fair value of share-based payment awards made to employees and directors, includingrestricted stock grants, on the date of grant. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably overthe requisite service periods. Derivative Instruments Periodically, the Company entered into swaps to reduce the effect of price changes on a portion of our future oil production. We reflect the fair market value ofour derivative instruments on our balance sheet. Our estimates of fair value are determined by obtaining independent market quotes as well as utilizing avaluation model that is based upon underlying forward curve data and risk free interest rates. Changes in commodity prices will result in substantiallysimilar changes in the fair value of our commodity derivative agreements. We do not apply hedge accounting to any of our derivative contracts, therefore werecognize mark-to-market gains and losses in earnings currently.Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Not applicable. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Our financial statements appear immediately after the signature page of this report. See "Index to Financial Statements" included in this report. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURENone. Item 9A. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures As of the end of the year covered by this Annual Report, management performed, with the participation of our Chief Executive Officer, or CEO, and ChiefFinancial Officer, or CFO, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of theExchange Act of 1934, as amended, or Exchange Act. Our disclosure controls and procedures are designed to ensure that information required to be disclosedin the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rulesand forms, and that such information is accumulated and communicated to our management, including our CEO and CFO, to allow timely decisionsregarding required disclosures. Based on this evaluation, our CEO and CFO have concluded that the Company’s disclosure controls and procedures wereeffective as of December 31, 2012.Management’s Annual Report on Internal Control over Financial Reporting Management 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 Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements in accordance with generally accepted accounting principles in the United States, or GAAP. A company’sinternal 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 asnecessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of theCompany are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on theconsolidated financial statements. 47 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation ofeffectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate.Our management, with the participation of our CEO and CFO, assessed the effectiveness of our internal control over financial reporting as of December 31,2012. Management’s assessment of internal control over financial reporting was conducted using the criteria in Internal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. Management concluded that, as of December 31, 2012, theCompany’s internal control over financial reporting was effective.Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting during the quarter-ended December 31, 2012 that have materially affected, or arereasonably likely to materially affect, our internal control over financial reporting. Item 9B. OTHER INFORMATION None. PART III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2013 annual shareholders meeting and isincorporated by reference in this report.Item 11. EXECUTIVE COMPENSATION Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2013 annual shareholders meeting and isincorporated by reference in this report.Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERMATTERS Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2013 annual shareholders meeting and isincorporated by reference in this report. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2013 annual shareholders meeting and isincorporated by reference in this report. Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2013 annual shareholders meeting and isincorporated by reference in this report. 48 PART IVItem 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES INDEX TO FINANCIAL STATEMENTS a) Report of Independent Registered Public Accounting FirmF-1 Consolidated Balance SheetsF-2 Consolidated Statements of OperationsF-4 Consolidated Statements of Shareholders' EquityF-5 Consolidated Statements of Cash FlowsF-6 Notes to Financial StatementsF-7 b) Financial statement schedules Not applicable.c) Exhibits The information required by this Item is set forth on the exhibit index that follows the signature page to this Annual Report on Form 10-K. 49 SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalfby the undersigned, thereunto duly authorized. RECOVERY ENERGY INC. Date: April 17, 2013By:/s/ W. Phillip Marcum W. Phillip Marcum Chief Executive Officer and Chairman of the Board of Directors(Authorized Signatory) Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrantand the capacities and on the dates indicated.Signature Title Date /s/ W. Phillip Marcum Chief Executive Officer and Chairman of the Board of Directors April 17, 2013W. Phillip Marcum (Principal Executive Officer) /s/ A. Bradley Gabbard President, Chief Financial and Accounting Officer, Director April 17, 2013A. Bradley Gabbard (Principal Financial Officer) /s/ Eric Ulwelling Principal Accounting Officer April 17, 2013Eric Ulwelling /s/ Tim Poster Director April 17, 2013Tim Poster /s/ Kirk Edwards Director April 17, 2013Kirk Edwards /s/ Bruce White Director April 17, 2013Bruce White 50 Exhibit IndexThe following exhibits are either filed herewith or incorporated herein by reference: 2.1Membership 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 10.1 from our current report filed on Form 8-K filed on September 22, 2009).3.1Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Form S-1 filed on July 28, 2008).3.2Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s current report on Form 8-K filed on June 18, 2010).4.1Warrant to Purchase Common Stock dated December 11, 2009 (incorporated by reference to Exhibit 4.2 to the Company’s current report filed on Form8-K filed on December 17, 2009).4.2Recovery Energy, Inc. 2012 Equity Incentive Plan dated August 31, 2012 (incorporated by reference to Exhibit 4.1 to the Company’s current reportfiled on Form 8-K on September 5, 2012).10.1Cancellation agreements, dated September 21, 2009 between Universal Holdings, Inc. and two former shareholders (incorporated herein by reference toExhibit 10.1 to the Company’s annual report on Form 10-K for the year ended December 31, 2010).10.2Credit Agreement with Hexagon Investments, LLC dated effective as of January 29, 2010 (incorporated herein by reference to Exhibit 10.12 to theCompany’s current report filed on Form 8-K filed on March 4, 2010).10.3Promissory Note for financing with Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.13 to theCompany’s current report filed on Form 8-K filed on March 4, 2010).10.4Nebraska Mortgage to Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.14 to the Company’scurrent report filed on Form 8-K filed on March 4, 2010).10.5Colorado Mortgage to Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.15 to the Company’scurrent report filed on Form 8-K filed on March 4, 2010).10.6Purchase and Sale Agreement with Edward Mike Davis, L.L.C. dated effective as of April 1, 2010 (incorporated herein by reference to Exhibit 10.16to the Company’s current report filed on Form 8-K filed on March 25, 2010).10.7Credit Agreement with Hexagon Investments, LLC dated effective as of March 25, 2010 (incorporated herein by reference to Exhibit 10.17 to theCompany’s current report filed on Form 8-K filed on March 25, 2010).10.8Promissory Note for financing with Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.18 to theCompany’s current report filed on Form 8-K filed on March 25, 2010).10.9Nebraska Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.19 to the Company’scurrent report filed on Form 8-K filed on March 25, 2010).10.10Wyoming Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.20 to the Company’scurrent report filed on Form 8-K filed on March 25, 2010).10.11Purchase and Sale Agreement with Edward Mike Davis, L.L.C. for purchase of oil and gas properties dated as of April 1, 2010 (incorporated hereinby reference to Exhibit 10.1 to the Company’s current report filed on Form 8-K filed on April 20, 2010).10.12Credit Agreement with Hexagon Investments, LLC dated as of April 14, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company’scurrent report filed on Form 8-K filed on April 20, 2010). 51 10.13Promissory Note with Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company’s currentreport filed on Form 8-K filed on April 20, 2010).10.14Warrant to Purchase Common Stock by Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.4 to theCompany’s current report filed on Form 8-K filed on April 20, 2010).10.15Wyoming Mortgage to Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.5 to the Company’s currentreport filed on Form 8-K filed on April 20, 2010).10.16Securities Purchase Agreement dated as of April 26, 2020 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report filed onForm 8-K filed on April 30, 2010).10.17Agreement 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-Kfiled on May 4, 2010).10.18Purchase 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 onMay 12, 2010).10.19Promissory 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 May12, 2010).10.20Security 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 onMay 12, 2010).10.21Purchase Agreement with Edward Mike Davis, L.L.C. and Spottie, Inc. dated May 15, 2010 (incorporated herein by reference to Exhibit 10.1 to theCompany’s current report filed on Form 8-K filed on May 20, 2010).10.22Employment Agreement with Jeffrey A. Beunier (incorporated herein by reference to Exhibit 10.2 to the Company’s current report filed on Form 8-Kfiled on December 23, 2010).10.23Director Appointment Agreement with James Miller (incorporated herein by reference to Exhibit 10.3 to the Company’s current report filed on Form 8-Kfiled on May 20, 2010).10.24Form 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 filedon June 4, 2010).10.25Warrant issued to Hexagon Investments, LLC (incorporated herein by reference to Exhibit 4.2 to the Company’s current report filed on Form 8-K filedon June 4, 2010).10.26Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company’s current report filed on Form 8-K filed onJune 4, 2010).10.27Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s current report filed on Form 8-K.10.28Form 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).10.29Letter Agreement with Hexagon Investments, LLC (incorporated herein by reference to Exhibit 10.4 to the Company’s current report filed on Form 8-Kfiled on June 4, 2010).10.30Independent Director Appointment Agreement with Conway J. Schatz (incorporated herein by reference to Exhibit 10.2 to the Company’s current reportfiled on Form 8-K filed on June 7, 2010). 52 10.31Consulting Agreement with Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s currentreport filed on Form 8-K filed on June 18, 2010).10.32Five Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company’s current reportfiled on Form 8-K filed on June 18, 2010).10.33Three Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.3 to the Company’s current reportfiled on Form 8-K filed on June 18, 2010).10.34Warrant 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).10.35Registration Rights Agreement with Hexagon Investments, Inc. (incorporated herein by reference to Exhibit 10.5 to the Company’s current report filedon Form 8-K filed on June 18, 2010).10.36Stockholders Agreement with Hexagon Investments Incorporated (incorporated herein by reference to Exhibit 10.1 to the Company’s current report filedon Form 8-K filed on June 29, 2010).10.37Form of $2.20 Warrant Issued to Persons Exercising $1.50 Warrants (incorporated herein by reference to Exhibit 10.1 to the Company’s current reporton Form 8-K filed on October 8, 2010).10.38Purchase Agreement with Edward Mike Davis, L.L.C. and Spottie, Inc. dated November 19, 2010 (incorporated herein by reference to Exhibit 10.1 tothe Company’s current report on Form 8-K filed on November 26, 2010).10.39Put Option Agreement with Grandhaven Energy, LLC dated November 19, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company’scurrent report on Form 8-K filed on November 26, 2010).10.40Warrant Issued to Hexagon Investments, LLC on January 1, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report onForm 8-K filed on January 4, 2011).10.41Amendments to Hexagon Investments, LLC Promissory Notes (incorporated herein by reference to Exhibit 10.2 to the Company’s current report onForm 8-K filed on January 4, 2011).10.42Form of Convertible Debenture Securities Purchase Agreement dated February 2, 2011 (incorporated herein by reference to Exhibit 10.1 to theCompany’s current report on Form 8-K filed on February 3, 2011). 10.43 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).10.44Purchase 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-Kfiled on February 24, 2011). 10.45Amendments to three Credit Agreements with Hexagon, LLC, dated March 15, 2012 (incorporated herein by reference to Exhibit 10.55 to theCompany’s annual report filed on Form 10-K on March 21, 2012).10.46Second Amendment to 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.56 to theCompany’s annual report filed on Form 10-K on March 21, 2012).10.47Securities Purchase Agreement for additional 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference toExhibit 10.57 to the Company’s annual report filed on Form 10-K on March 21, 2012).10.48Form of 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.58 to the Company’sannual report filed on Form 10-K on March 21, 2012). 53 10.49Separation Agreement with Roger A. Parker dated as of November 15, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s currentreport on Form 8-K filed on December 4, 2012).10.50Amendment to Securities Purchase Agreement dated August 7, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current reporton Form 8-K filed on August 9, 2012).10.51Amendment to Securities Purchase Agreement dated August 7, 2012 (incorporated herein by reference to Exhibit 10.2 to the Company’s current reporton Form 8-K filed on August 9, 2012).10.52Second Amendments to three Credit Agreements with Hexagon, LLC, dated July 31, 2012 (incorporated herein by reference to Exhibit 10.1 to theCompany’s current report on Form 8-K filed on August 2, 2012).10.53Independent Director Appointment Agreement with W. Phillip Marcum dated April 27, 2012 (incorporated herein by reference to Exhibit 10.1 to theCompany’s current report on Form 8-K filed on May 2, 2012).10.54Independent Director Appointment Agreement with Bruce B. White dated April 27, 2012 (incorporated herein by reference to Exhibit 10.2 to theCompany’s current report on Form 8-K filed on May 2, 2012).10.55Amended and Restated Independent Director Appointment Agreement with Timothy N. Poster dated April 27, 2012 (incorporated herein by reference toExhibit 10.32 to the Company’s current report on Form 8-K filed on June 1, 2010).10.56Amendment to 8% Senior Secured Convertible Debentures due February 8, 2014, dated April 15, 2013.10.57Fourth Amendment to Credit Agreement (First Credit Agreement), dated April 15, 2013.10.58Fourth Amendment to Credit Agreement (Second Credit Agreement), dated April 15, 2013.10.59Fourth Amendment to Credit Agreement (Third Credit Agreement), dated April 15, 2013.14.1Code of Ethics (incorporated herein by reference to Exhibit 14.1 to the Company’s annual report on Form 10-K for the year ended December 31, 2009).16.1Letter from Jewett, Schwartz, Wolfe & Associates to the U.S. Securities and Exchange Commission dated January 19, 2010 (incorporated herein byreference to Exhibit 16.1 to the Company’s current report on Form 8-K dated January 21, 2010).21.1List 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).23.1Consent of Hein & Associates, LLP (included in their report on page F-1)23.2Consent of RE Davis.31.1Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.31.2Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.32.1Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.32.2Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.99.1Report of RE Davis. 54 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and ShareholdersRecovery Energy, Inc.We have audited the accompanying consolidated balance sheet of Recovery Energy, Inc. and subsidiaries (together, the “Company”) as of December 31, 2012and 2011, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the years then ended. These financial statements arethe 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 thatwe plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is notrequired to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal controlover financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion onthe effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on atest basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimatesmade by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Recovery Energy, Inc.and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for the years then ended, in conformity with U.S.generally accepted accounting principles.Hein & Associates LLPDenver, ColoradoApril 17, 2013 F-1 RECOVERY ENERGY, INC.CONSOLIDATED BALANCE SHEETS December 31 December 31, 2012 2011 Assets Current assets Cash $970,035 $2,707,722 Restricted cash 671,382 932,165 Accounts receivable (net of allowance of $50,000 and $0, at December 31, 2012 and 2011, respectively) 934,591 2,227,466 Prepaid assets 13,458 75,376 Total current assets 2,589,466 5,942,729 Oil and gas properties (full cost method), at cost: Developed properties 58,610,095 32,113,143 Undeveloped acreage, excluded from amortization 28,067,005 45,697,481 Wells in progress, excluded from amortization 193,515 6,425,509 Total oil and gas properties, at cost 86,870,615 84,236,133 Less accumulated depreciation, depletion , amortization, and impairment (43,187,962) (12,099,098)Net oil and gas properties, at cost 43,682,653 72,137,035 Other assets: Office equipment, net 90,630 106,286 Prepaid advisory fees - 574,160 Deferred financing costs, net 974,856 2,341,595 Restricted cash and deposits 215,435 186,055 Total other assets 1,280,921 3,208,096 Total Assets $47,553,040 $81,287,860 The accompanying notes are an integral part of these financial statements. F-2 RECOVERY ENERGY, INC.CONSOLIDATED BALANCE SHEETS December 31 December 31, 2012 2011 Liabilities and Shareholders' Equity Current liabilities Accounts payable $1,831,590 $2,050,768 Commodity price derivative liability - 75,609 Related party payable - 16,475 Accrued expenses 1,411,016 1,354,204 Short term notes payable 388,351 1,150,967 Total current liabilities 3,630,957 4,648,023 Long term liabilities Asset retirement obligation 911,546 612,874 Term notes payable 18,947,963 20,129,670 Convertible notes payable, net of discount 10,300,361 4,929,068 Convertible notes conversion derivative liability 1,680,000 1,300,000 Total long-term liabilities 31,839,870 26,971,612 Total liabilities 35,470,827 31,619,635 Commitments and contingencies – Note 3,6,8, and 9 Shareholders’ equity Preferred stock, 10,000,000 authorized, none issued and outstanding - - Common stock, $0.0001 par value: 100,000,000 shares authorized; 18,394,401 and 17,436,825 shares issued andoutstanding as of December 31, 2012 and December 31, 2011, respectively 1,839 1,744 Additional paid in capital 118,296,679 118,146,119 Accumulated deficit (106,216,305) (68,479,638)Total shareholders' equity 12,082,213 49,668,225 Total Liabilities and Shareholders’ Equity $47,553,040 $81,287,860 The accompanying notes are an integral part of these financial statements. F-3 RECOVERY ENERGY, INC.CONSOLIDATED STATEMENTS OF OPERATIONSYears Ended December 31, 2012 and 2011 2012 2011 Revenue Oil sales $5,898,459 $7,148,110 Gas sales 406,216 547,190 Operating fees 174,779 117,360 Realized gains on commodity price derivatives 780,135 625,043 Unrealized loss on commodity price derivatives - (75,609)Total revenue 7,259,589 8,362,094 Costs and expenses Production costs 1,421,177 1,514,784 Production taxes 227,455 838,714 General and administrative 4,331,328 10,544,347 Depreciation, depletion and amortization 4,549,303 4,347,117 Bad debt expense 77,957 - Impairment of developed properties 26,658,707 2,821,176 Total costs and expenses 37,265,927 20,066,138 Loss from operations (30,006,338) (11,704,044) Other income 5,896 71,253 Convertible notes conversion derivative gain 320,000 3,821,792 Debt inducement expense - (2,800,000)Interest expense (8,056,232) (8,218,225) Net Loss $(37,736,674) $(18,829,224)Net loss per common share Basic and diluted $(2.11) $(1.21)Weighted average shares outstanding: Basic and diluted 17,902,013 15,543,758 The accompanying notes are an integral part of these financial statements. F-4 RECOVERY ENERGY, INC.CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITYYears Ended December 31, 2012 and 2011 Common Stock Additional Subject to Redemption Common Stock Paid-In Accumulated Shares Amount Shares Amount Capital Deficit Total Balance, December 31, 2010 10,625 $86,258 14,453,593 $1,444 $93,819,314 $(49,650,407) $44,170,352 1:4 Reverse stock split - - - - 387 - 387 Common stock issued for propertyacquisitions - - 2,269,543 228 10,895,665 - 10,895,893 Common stock no longer subject toredemption (10,625) (86,258) 10,625 1 86,254 - 86,255 Common stock issued in connectionwith interest payment on convertibledebt - - 78,982 8 559,863 - 559,871 Common stock issued for services - - 10,000 1 81,996 - 81,997 Restricted stock issued to employeesand directors - - 238,750 24 6,161,041 - 6,161,065 Warrants issued for cash - - 375,333 38 2,129,801 - 2,129,839 Warrants issued for debt extension - - - - 1,611,797 1,611,797 Debt conversion expense - - - - 2,800,000 - 2,800,000 Net loss - - - - - (18,829,224) (18,829,224) Balance, December 31, 2011 - $- 17,436,825 $1,744 $118,146,119 $(68,479,631) $49,668,232 Common stock issued in connectionwith interest payment on convertibledebt - - 278,225 28 894,063 - 894,091 Common stock issued for deferredfinancing costs - - 50,000 5 229,995 230,000 Common stock issued for services - - 100,000 10 348,990 349,000 Common stock issued forcompensation (board and employees) - - 529,351 52 1,836,512 1,836,564 Modification for common stock issuedfor compensation (3,159,000) (3,159,000) Net Loss - - - - - (37,736,674) (37,736,674) Balance, December 31, 2012 - $- 18,394,401 $1,839 $118,296,678 $(106,216,305) $12,082,212 The accompanying notes are an integral part of these financial statements. F-5 RECOVERY ENERGY, INC.CONSOLIDATED STATEMENTS OF CASH FLOWSYears Ended December 31, 2012 and 2011 Year ended December 31, 2012 2011 Cash flows from operating activities: Net loss $(37,736,674) $(18,829,224)Adjustments to reconcile net loss to net cash used in operating activities: Impairment provision, proved leases 26,658,707 2,821,176 Debt inducement and warrant modification expense - 2,800,000 Common stock issued for convertible note interest 894,092 559,873 Bad debt 77,957 - Common stock for services and compensation (973,432) 6,566,152 Changes in the fair value of commodity price derivatives (855,744) (549,434)Amortization of deferred financing costs 1,596,739 4,446,911 Change in fair value of convertible notes conversion derivative (320,000) (3,821,792)Depreciation, depletion, amortization and accretion of asset retirement obligation 6,865,733 4,347,117 Changes in operating assets and liabilities: Accounts receivable (228,934) 73,940 Restricted cash 260,783 218,376 Other assets 636,078 39,451 Accounts payable and other accrued expenses (264,708) 757,207 Net cash used in operating activities (3,389,403) (570,247) Cash flows from investing activities: Acquisition of undeveloped acreage (536,249) (9,433,073)Drilling capital expenditures (4,533,954) (7,017,523)Sale of undeveloped acreage interests 2,918,414 3,000,000 Additions of office equipment (2,928) (83,727)Proceeds from hedge settlements 780,135 226,203 Investment in operating bonds (29,379) (348)Net cash used in investing activities (1,403,961) (13,308,468) Cash flows from financing activities: Proceeds from sale of common stock, units and excise of warrants - 2,129,870 Proceeds from debt 5,000,000 9,411,597 Repayment of debt (1,944,323) (483,774)Net cash provided by financing activities 3,055,677 11,057,693 Change in cash and cash equivalents (1,737,687) (2,821,022)Cash and cash equivalents at beginning of period 2,707,722 5,528,744 CASH AND CASH EQUIVALENTS AT END OF PERIOD $970,035 $2,707,722 Supplemental disclosure: Cash paid for interest $3,206,804 $3,201,312 Cash paid for income taxes $- $- Non-cash transactions: Sale of property for receivable $- $1,443,852 Debt issuance cost $- $400,000 Purchase of properties for common stock $- $10,895,893 Stock and warrants issued for deferred financing costs $230,000 $1,611,832 Stock and warrants issued for prepaid financial advisory fees $349,000 $- Stock and warrants issued for prepaid financial office rent $- $81,997 Property additions for asset retirement obligation $198,110 $61,469 Stock issued for payment on long-term debt $894,091 $559,872 The accompanying notes are an integral part of these financial statements. F-6 RECOVERY ENERGY, INC.NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 1 – ORGANIZATIONOn September 21, 2009, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC(“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to RecoveryEnergy, Inc. (“Recovery”, “Recovery Energy”, “we”, “our”, and the “Company”). The Agreement was accounted for as a reverse acquisition with Coronadobeing treated as the acquirer for accounting purposes. Accordingly, the financial statements of Coronado have been adopted as the historical financialstatements of Recovery.The Company is an independent oil and gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 129,000net acres. Recovery drills for, operates and produces oil and natural gas wells through the Company’s land holdings located in Wyoming, Colorado, andNebraska. All references to production, sales volumes and reserves quantities are net to our interest unless otherwise indicated. NOTE 2 – LIQUIDITY As discussed in “Note 14—Subsequent Events” the Company entered into amendments to both our term loans and our 8% Senior Secured ConvertibleDebentures agreements to extend the maturity dates of these debts to May 16, 2014. In addition, the amendments to our term loans also provided for thereduction of interest rate from 15% to 10% effective March 1, 2013; the payment of interest only for the months of March through June, 2013; a reduction inthe minimum monthly payments of principal and interest thereafter from $0.33 million per month to either $0.23 million or $0.19 million, depending on ourability to consummate the sale of certain of our assets by July 1, 2013; and forbearance by the secured lender from exercising its rights under the term loancredit agreements for any breach that may have occurred prior to the amendment. In consideration for the extended maturity date of both loans and the reduced interest rate and minimum loan payment under the secured term loans, theCompany will be required to provide both the secured lender and the holders of our debentures an additional security interest in 15,000 acres (or 30,000 acresin aggregate) of our undeveloped acreage. In addition, we are required under the amendment to use our reasonable best efforts to pursue certain transactions toimprove our financial condition, including the aforementioned sale of certain of our assets, an equity offering or similar capital-raising transaction, one ormore joint venture development agreements, and an engineering study of certain of our producing properties to ascertain possible operations to enhanceproduction from those properties. Pursuant to the debenture amendment, the Company and the debenture holders have agreed to waive any breach under thedebentures that may have occurred prior to the date of the amendment.We currently have $19.34 million outstanding under our term loans and $13.40 million outstanding under our debentures. We have a history of sustained losses and cash used by operating activities, including a loss in 2012 of $37.7 million and cash used by operating activities in2012 of $3.4 million. In addition, as of December 31, 2012, we had a net working capital deficit of $1.2 million. Commencing in late 2012, we implementeda number of cost reduction measures, including a substantial reduction in our staff. On April 16, 2013, we entered into an agreement with one of our existingDebenture holders to issue up to an additional $5.0 million in additional debentures with substantially the same terms to the existing 8% Secured ConvertibleDebentures. Under the terms of this agreement, $1.5 million of additional debentures will be issued on or before July 16, 2013. The funds associated withthe initial issuance of debentures will be used by the Company for the drilling and development of certain properties, and for general corporate purposes (seeNote 14). The combination of these measures coupled with the aforementioned debt modifications will provide substantial near term relief to our cash flow andliquidity. In the immediate term, the Company expects that additional capital will be required to fund its capital budget for 2013, partially to fund some of its ongoingoverhead, provide for payment of minimum interest and principal payments required by term notes, and to provide additional capital to generally improve itsworking capital position. A portion of this additional capital will be provided by the new convertible debentures as described above. We anticipate thatadditional funding will be provided by a combination of capital raising activities, including the selling of additional debt and/or equity securities, the sellingof certain assets and by the development of certain of our undeveloped properties via arrangements with joint venture partners. If we are not successful inobtaining sufficient cash sources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations,sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring portions of our 2013 capital budget. On a longer term basis, the Company will require capital to retire our term notes and our 8% Senior Secured Convertible Debentures when such debts maturein May 2014. Pursuant to our credit agreements with Hexagon, a substantial portion of our monthly net revenues derived from our producing properties is required to be usedfor debt and interest payments. In addition, our debt instruments contain provisions that, absent consent of Hexagon, may restrict our ability to raiseadditional capital. NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES Basis of Presentation The accompanying financial statements were prepared by Recovery in accordance with generally accepted accounting principles (“GAAP”) in the UnitedStates. The financial statements 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. All common stock share information is retroactively adjusted for the effect of a 4:1 reverse stock split that was effective October 19, 2011. F-7 ReclassificationCertain amounts in the December 31, 2011 consolidated financial statements have been reclassified to conform to the December 31, 2012 consolidatedfinancial statement presentation. Such reclassifications had no effect on net income.Principles of ConsolidationThe accompanying consolidated financial statements include Recovery Energy, Inc. and its wholly−owned subsidiaries Recovery Oil and Gas, LLC, andRecovery Energy Services, LLC. All intercompany accounts and transactions have been eliminated in consolidation. Both subsidiaries were inactive andwere dissolved in the fourth quarter of the year ended December 31, 2011. Use of Estimates The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reportedamounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reportedamounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis and base our estimates on historical experienceand on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under differentassumptions or conditions, we believe that our estimates are reasonable. Our most significant financial estimates are associated with our estimated proved oiland gas reserves, and the assessment of impairment related to our unproven properties, as well as valuation of common stock used in issuances of commonstock, warrants and the valuation of the conversion rights related to the convertible debentures payable. LiquidityCash used in operating activities during the year ended December 31, 2012 was $3.39 million and cash used in investing activities exceeded cash provided byfinancing activities by approximately $1.74 million. This net cash use contributed to a substantial decrease in our net working capital as of December 31,2012. Expenditures subsequent to December 31, 2012 have continued to exceed cash receipts, causing a further reduction of the Company’s working capitalposition. In the immediate term, the Company expects that additional capital will be required to fund its capital budget for 2013, partially to fund some of its ongoingoverhead, and to provide additional capital to generally improve its working capital position. We anticipate that these capital requirements will be funded by acombination of capital raising activities, including the selling of additional debt and/or equity securities and the selling of certain assets. If we are notsuccessful in obtaining sufficient cash sources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure ouroperations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring portions of our 2013capital budget.Pursuant to our credit agreements with Hexagon, a substantial portion of our monthly net revenues derived from our producing properties is required to be usedfor debt and interest payments. In addition, our debt instruments contain provisions that, absent consent of Hexagon, may restrict our ability to raiseadditional capital.In December 2011, the Company sold certain undeveloped acreage for total proceeds of $4.5 million. During 2011, Hexagon agreed to temporarily suspend forfive months the requirement to remit monthly net revenues of approximately $2.00 million in the aggregate as payment on the Hexagon debt. In November2011, Hexagon extended the maturity date of their notes to January 1, 2013, and also advanced an additional $0.31 million to the Company. The Companyrepaid the $0.31 million advance in February 2012. In March 2012, Hexagon extended the maturity date of their notes to June 30, 2013, and in connectiontherewith, the Company agreed to make minimum note payments of $0.33 million, effective immediately. The Company will continue to pursue alternatives toshore up its working capital position and to provide funding for its planned 2013 expenditures.In February 2012, we completed the sale of certain undeveloped acreage, under which we agreed to sell all of our oil and gas leases in the Grover Field in WeldCounty, Colorado for approximately $4.54 million. In August 2012, the Company restructured the terms of the Supplemental Debenture offering and concluded the offering by issuing an additional $1.96million of convertible debentures. On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLCfor acting as a placement agent of the Supplemental Debentures.On November 5, 2012, the Company liquidated all of its price derivatives (commodity hedges) for proceeds of $0.61 million. As of December 31, 2012, theCompany did not have any derivative instruments. F-8 In December 2012, the Company leased certain deep rights to 6,300 undeveloped acres to a private company for proceeds of approximately $1.50 millionwhich $0.75 million was paid toward principal on our long-term debt.In April 2013, the Company amended its secured term loans and 8% Senior Secured Convertible Debentures to extend their maturity dates to May 16,2014. In addition, pursuant to the amendment of its secured term loans, the Company’s interest rate has been reduced to 10% from 15% beginningretroactively with March 2013, and the Company is required to make only interest payments for March, April, May, and June, after which time the minimumsecured term loan payment will be $0.23 million or $0.19 million, depending on the Company’s ability to consummate the sale of certain of its assets by thattime. In consideration for the extended maturity date of both loans and the reduced interest rate and minimum loan payment under the secured term loans, theCompany will be required to provide both Hexagon and the holders of its debentures an additional security interest in 15,000 acres (or 30,000 acres inaggregate) of its undeveloped acreage (see Note 14).On April 16, 2013, the Company entered into an agreement with one of its existing Debenture holders to issue up to an additional $5.0 million in additionaldebentures with substantially the same terms to the existing 8% Secured Convertible Debentures. Under the terms of this agreement, $1.5 million ofadditional debentures will be issued on or before July 16, 2013. The funds associated with the initial issuance of debentures will be used by the Company forthe drilling and development of certain properties, and for general corporate purposes (see Note 14). Cash and Cash Equivalents Cash and cash equivalents include cash in banks and highly liquid debt securities which have original maturities of 90 days or less at the purchase date.Restricted CashRestricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities. As of December 31, 2012 and 2011, therestricted cash balance was $0.67 million and $0.93 million, respectively.Accounts ReceivableThe Company records actual and estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costsincurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability andrecords its allowance for uncollectible receivables under the specific identification method. The Company recorded allowance for uncollectible receivables of$50,000 during the year ended December 31, 2012. No allowance was recorded for December 31, 2011. Allowance for doubtful accounts are based primarilyon joint interest billings for expenses related to oil and natural gas wells. Receivables which derive from sales of certain oil and gas production are collateral forour Loan Agreements (see Note 8).During the year ended December 31, 2012, the Company wrote off accounts receivable for $0.03 million as bad debt expense. During the year ended December31, 2011 no receivable amounts were written off to bad debt expense.Assets Held For Sale Assets held for sale are recorded at the lower of cost or estimated net realizable value. As of December 31, 2012 and 2011, the Company did not have anyassets held for sale.Concentration of Credit Risk The Company's cash, cash equivalents and short-term investments are invested at major financial institutions primarily within the United States. AtDecember 31, 2012 and December 2011, the Company’s cash and cash equivalents were maintained in accounts that are insured up to the limit determined bythe federal governmental agency. The Company may at times have balances in excess of the federally insured limits. The Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited numberof entities. Therefore, the collectability is dependent upon the general economic conditions and financial health of a small number purchasers and joint interestowners. The receivables are not collateralized. However, to date the Company has had minimal bad debts. As of December 31, 2012, the Company recordedan allowance for doubtful accounts of $50,000.Significant Customers During the year ended December 31, 2012 and December 31, 2011, approximately 67% and 76%, respectively, of the Company's revenue was derived fromsales to one customer, Shell Trading (US). However, the Company does not believe that the loss of a single purchaser, including Shell Trading (US), wouldmaterially affect the Company's business because there are numerous other purchasers in the area in which the Company sells its production. F-9 ReservesAll of the reserves data included herein are estimates. Estimates of our crude oil and natural gas reserves are prepared in accordance with guidelinesestablished by the SEC, including rule revisions designed to modernize the oil and gas company reserves reporting requirements, which we implementedeffective December 31, 2010. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There arenumerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future productionrates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the quality of available data and ofengineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that areultimately recovered. In addition, economic producibility of reserves is dependent on the oil and gas prices used in the reserves estimate. Our reserves estimatesare based on 12-month average commodity prices, unless contractual arrangements otherwise designate the price to be used, in accordance with SECrules. However, oil and gas prices are volatile and, as a result, our reserves estimates will change in the future.Estimates of proved crude oil and natural gas reserves significantly affect our depreciation, depletion, and amortization “DD&A” expense. For example, ifestimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could alsoresult in an impairment charge, which would reduce earnings.Oil and Gas Producing Activities The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration, development and acquisition ofoil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costsdirectly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration anddevelopment costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the provedreserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based uponestimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized assetretirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing provedreserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that are not otherwise included in capitalized costs.The costs of undeveloped acreage are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to theproperties. The properties are reviewed quarterly for impairment. When proved reserves are assigned to such properties or one or more specific properties aredeemed to be impaired, the cost of such properties or the amount of the impairment is added to full cost pool which is subject to depletion calculations.Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed anamount equal to sum of i.) the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves, plus ii.) the cost ofunproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are notsubject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized.The present value of estimated future net revenues was computed by applying a twelve month average of the first day of the month price of oil and gas toestimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing theproved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. The Company recognized impairment charges of $26.66 million and $2.80 million, respectively, during the years ended December 31, 2012 and 2011 (seeNote 4). F-10 Wells in Progress Wells in progress represent wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oiland gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceilingtest until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves orabandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations. Duringthe year ended December 31, 2012, the Company transferred $17.09 million of costs from wells in progress and their respected undeveloped acreage into thefull cost pool (see Note 4).Deferred Financing CostsAs of December 31, 2012 and December 31, 2011, the Company recorded unamortized deferred financing costs of approximately $0.97 million and $2.3million, respectively, related to the closing of its loans and credit agreements (see Note 8). Deferred financing costs include origination (warrants issued andoverriding royalty interests assigned to Hexagon), legal and engineering fees incurred in connection with the Company's credit facility, which are beingamortized over the term of the credit facility. The Company recorded amortization expense of approximately $1.60 million and $5.0 million, respectively, inthe years ended December 31, 2012 and December 31, 2011.Prepaid Advisory Fees The Company accounts for prepaid advisory services with the total consideration amortized over the underlying service agreement period. As of December 31,2012 and 2011 prepaid financial and marketing advisory fees were approximately $0 and $0.57 million, respectively. The prepaid fees were paid with non-cash consideration (shares of our common stock and warrants exercisable for shares of our common stock issued to our financial advisors). Property and EquipmentProperty and equipment are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimateduseful lives of property and equipment range from one to seven years. The Company recorded $0.02 million and $0.03 million of depreciation for the yearsended December 31, 2012 and December 31, 2011, respectively.Impairment of Long-lived Assets The Company accounts for long-lived assets (other than oil and gas properties) at cost. Other long-lived assets include property and equipment, prepaidadvisory fees, and identifiable intangible assets with finite useful lives (subject to amortization, depletion, and depreciation). The Company may impair theseassets whenever events or changes in circumstances indicate that the carrying amount such assets may not be fully recoverable. Recoverability is measured bycomparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may notbe recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference. As of December 31, 2012 and 2011, no impairment has been recorded for long lived assets other than the impairment of capitalized oil and gas property costsduring December 31, 2012 and 2011 as discussed in undeveloped acreage and wells in progress (see Note 4).Fair Value of Financial InstrumentsAs of December 31, 2012 and 2011, the carrying value of cash and cash equivalents, short-term investments, accounts receivable, accounts payable, accruedexpenses, interest payable and customer deposits approximates fair value due to the short-term nature of such items. The carrying value of the Company’ssecured debt is carried at cost as the related interest rate, approximates rates currently available to the Company. Certain other assets and liabilities aremeasured at fair value (see Note 7). F-11 Commodity Derivative Instrument The Company utilizes swaps to reduce the effect of price changes on a portion of our future oil production. On a monthly basis, a swap requires us to pay thecounterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price.The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gasprices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements,such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivativecontracts to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts inorder to realize the current value of the Company's existing positions (see Note 6). The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. TheCompany's derivative contracts have typically been arranged with one counterparty. The Company has netting arrangements with this counterparty thatprovide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. Thederivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement (see Note 6). On November 5,2012, the Company liquidated all of its price derivatives (commodity hedges) for proceeds of $0.61 million. As of December 31, 2012, the Company did nothave any derivative instruments. Revenue Recognition We record revenues from the sales of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price, title hastransferred and collectability is reasonably assured.Asset Retirement Obligation The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded asliabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilitiesare accreted for the change in their present value.For purposes of depletion calculations, the Company also includes estimated dismantlement and abandonment costs, net of salvage values, associated withfuture development activities that have not yet been capitalized as asset retirement obligations.Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated tooperating expense using a systematic and rational method. As of December 31, 2012 and 2011, the Company recorded a related liability of $911,546 and$612,874, respectively (see Note 6). The information below reconciles the value of the asset retirement obligation for the periods presented: For the years ended December 31, 2012 2011 Balance, beginning of period $612,874 507,280 Liabilities incurred 198,111 61,469 Accretion expense 100,561 44,125 Change in estimate - - Balance, end of period $911,546 $612,874 F-12 Share Based Compensation The Company measures the fair value of share-based compensation expense awards made to employees and directors, including stock options, restrictedstock and employee stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. The value of the portion ofthe award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. The measurement of share-basedcompensation expense is based on several criteria, including but not limited to the valuation model used and associated input factors, such as expected term ofthe award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined usingmanagement’s judgment. If differences arise between the assumptions used in determining share-based compensation expense and the actual factors, whichbecome known over time, Recovery may change the input factors used in determining future share-based compensation expense.Recovery accounts for warrant grants to non-employees whereby the fair values of such warrants are determined using the Black-Scholes option pricing modelat the earlier of the date at which the non-employee’s performance is complete or a performance commitment is reached (Note 12).Warrant Modification Expense The Company accounts for the modification of warrants as an exchange of the old award for a new award. The incremental value is measured as the excess, ifany, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a periodexpense or amortized over the performance or vesting date. We estimate the incremental value of each warrant using the Black-Scholes option pricing model.The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree of subjective judgment isthe estimated volatility of our stock price (Note 11).Loss per Common Share Earnings (losses) per share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earnings(losses) per share are computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issuedassuming exercise or conversion of all potentially dilutive common shares. Potentially dilutive securities, such as conversion derivatives and stock purchasewarrants, are excluded from the calculation when their effect would be anti-dilutive. As of December 31, 2012, a total of 5,638,900 and 3,152,941,respectively of outstanding warrants and derivative shares related to convertible debentures payable have been excluded from the diluted share calculations asthey were anti-dilutive as a result of net losses incurred. Accordingly, basic shares equal diluted shares for all periods presented.Income Taxes Prior to December 31, 2011, the Company filed its tax returns on an April 30 fiscal year end. During the year ended December 31, 2012, the Companyreceived approval by the Internal Revenue Service (“IRS”) to move the Company’s tax year end to December 31 from April. The Company uses the asset liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differencesbetween 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 thedifferences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of achange 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 taxassets when uncertainty exists regarding their realization.We recognize tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized ismeasured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” isrecorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards. As of December 31, 2012 and 2011,the Company has determined that no liability is required to be recognized. F-13 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 penaltiesat December 31, 2012 and December 31, 2011, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest onunderpayments 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 ofunrecognized tax benefits will significantly increase or decrease during the next 12 months. The earliest years remaining subject to examination are December31, 2011, April 30, 2011 and April 30, 2010.Recently Issued Accounting Pronouncements In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-04: Fair Value Measurement (Topic 820):Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in US GAAP and IFRSs (ASU 2011-04). ASU 2011-04 clarifiesapplication of fair value measurement and disclosure requirements and is effective for annual and interim periods beginning after December 15, 2011. In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet (Topic 210): Disclosures about Offsetting Assets andLiabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financialstatements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on January 1, 2013.NOTE 4 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS AND DIVESTITURESDJ Basin Properties AcquisitionsIn December 2010, the Company entered into an acquisition and development agreement with TRW Exploration, LLC (a related party, see Note 9) wherebyTRW paid $2,000,000 for the purchases of an interest in approximately 2,000 net undeveloped acres and also agreed to carry the Company’s 40% interest intwo horizontal wells to be drilled on lands defined by the agreement. TRW subsequently funded the drilling and completion costs of two horizontal wells on thelands covered by the leases, at a total cost of approximately $7 million. This agreement was terminated in December, 2011 and TRW sold back its interest inthe wells along with all of its rights to the undeveloped acreage, in consideration for the issuance by the Company of 1,500,000 shares of unregistered commonstock valued at $4.88 million. Additional amounts were incurred in drilling the wells and were paid by the Company. The Company allocated $2 million ofthis purchase price to the undeveloped acreage, and the remainder to the purchase of the two wells.In February 2011, the Company purchased undeveloped oil and gas acreage from various private individuals for $1.25 million in cash and $0.65 million instock in the Grover Field and surrounding area in Weld County, Colorado, and Goshen County, Wyoming.In March 2011, the Company purchased undeveloped oil and gas acreage interests located in Laramie County, Wyoming. The purchase price was $6.47million cash and shares of common stock valued at $5.80 million in stock. The Company also closed on two acquisitions of undeveloped oil and gas acreagefrom various private individuals for a combined $0.55 million in cash in Goshen County, Wyoming.In February 2012, we completed the sale of our Grover Prospect acreage, under which we agreed to sell all of our oil and gas leases in the Grover Field in WeldCounty, Colorado to Bill Barrett Corporation for approximately $4.54 million. In April, 2012, we made the decision to abandon one of our unconventional Niobrara wells that was categorized as a well in progress as of December 31,2011. In conjunction with that decision, all capitalized drilling, completion and allocable lease costs related to this well in the amount of $4.8 million weretransferred to developed properties. This transfer of costs contributed to a $3.27 impairment charge of developed properties derived from the ceiling testcompleted as of March 31, 2012. In December 2012, the Company made a decision to abandon the one remaining unconventional Niobrara well. Inconjunction with the decision, all capitalized drilling, completion and allocable lease costs related to both wells-in-progress in the amount of $10.06 millionwere transferred to developed properties. Furthermore, the company analyzed all of their undeveloped acreage with expiration dates during the year endedDecember 31, 2015 and transferred $5.94 million to developed properties. Also, the Company reduced the PV-10 of the proved undeveloped reserve acreage byutilizing the assumption that its proven undeveloped reserves would be developed on a promoted basis, which reduced the production amounts to 25% of theCompany’s 100% ownership. As a result, the ceiling test performed by the Company yielded an increased impairment. The transfer of both of the costs to thedeveloped properties and a reduction of proved undeveloped reserve acreage resulted in an impairment of $23.39 million during December 2012, for a totalimpairment of $26.66 million for the year ended December 31, 2012. F-14 During 2012, the Company purchased $0.20 million of undeveloped oil and gas acreage interest located in the DJ Basin.DJ Basin Properties DivestituresEffective December 31, 2011 the Company sold 2,838 net acres of undeveloped acreage for consideration of approximately $4.5 million. A gain of $1.8million related to the sale of this acreage was applied as a credit to the carrying costs of developed oil and gas properties. On December 27, 2012, the Company leased undeveloped acreage for total proceeds of $1.5 million in the DJ Basin to a private company granting a four-yearlease for the deep rights on approximately 6,300 net acres. The Company paid Hexagon $0.75 million of the proceeds which reduced the long-term debtprincipal amount.Depreciation, depletion and amortization (“DD&A”) expenses related to the proved properties were approximately $4.55 million and $4.34 million for theyears ended December 31, 2012 and December 31, 2011, respectively. During the year ended December 31, 2012 and 2011, the company impaired thecarrying costs of its developed oil and gas properties by $26.66 million and $2.8 million, respectively, as a result of an excess of carrying costs above theapplicable ceiling threshold based on the fair market value of the proved developed and proved undeveloped acreage. The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized as of December 31, 2012 and 2011: As of December 31, 2012 2011 Undeveloped acreage Beginning Balance $45,697,481 $33,605,594 Acquisitions 203,596 14,981,153 Leased deep rights of undeveloped acreage (1,443,852) - Impairment and other reclassification to developed properties (16,390,220) (2,889,266)Total undeveloped acreage $28,067,005 $45,697,481 Wells in progress: Beginning Balance $6,425,509 $1,219,254 Acquisitions 3,824,172 8,904,818 Reclassification to developed properties (10,056,166) (3,698,563)Total wells in progress $193,515 $6,425,509 Total property not subject to DD&A $28,260,520 $52,122,990 As of December 31, 2012, the company analyzed all of its undeveloped acreage for impairment, and transferred $16.39 million to developed properties whichwere subject to DD&A and the ceiling test (see Note 4). F-15 NOTE 5 – WELLS IN PROGRESS The following table reflects the net changes in capitalized additions to wells in progress during 2012 and 2011: As of December 31, 2012 2011 Wells in progress: Beginning Balance $6,425,509 $1,219,254 Acquisitions 3,824,172 8,904,818 Reclassification to developed properties (10,056,166) (3,698,563)Total wells in progress $193,515 $6,425,509 In April, 2012, we made the decision to abandon one of our unconventional Niobrara wells that was categorized as a well in progress as of December 31,2011. In conjunction with that decision, all capitalized drilling, completion and allocable lease costs related to this well in the amount of $4.8 million weretransferred to developed properties. This transfer of costs contributed to a $3.27 impairment charge of developed properties derived from the ceiling testcompleted as of March 31, 2012. In December 2012, the Company made a decision to abandon the one remaining unconventional Niobrara well. Inconjunction with the decision, all capitalized drilling, completion and allocable lease costs related to both wells-in-progress in the amount of $10.06 millionwere transferred to developed properties. Furthermore, the company analyzed all of their undeveloped acreage with expiration dates during the year endedDecember 31, 2013 and transferred $1.31 million to developed properties. The transfer of both of the costs to the developed properties resulted in animpairment of $23.39 million during December 2012, for a total impairment of $26.66 million for the year ended December 31, 2012.NOTE 6 - FINANCIAL INSTRUMENTS AND DERIVATIVESPeriodically, the Company enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oilprices. During the year ended December 31, 2012 and 2011, the Company terminated and settled certain future commodity swaps resulting in a realized gainof approximately $0.61 million and $0.63 million, respectively.The Company had no active commodity swaps as of December 31, 2012. As of December 31, 2011, the Company maintained an active commodity swap for100 barrels per day through December 31, 2011, at a price of $96.25 per barrel. The amount of gain (loss) recognized in income related to our derivative financial instruments was as follows: For the Year EndedDecember 31, 2012 2011 Realized gain on oil price hedges $780,135 $570,233 Unrealized gain (loss) oil price hedges $- $(75,609) Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are recognized inthe unrealized gain (loss) on hedge contracts line on the consolidated statement of operations. Realized gains and losses resulting from the contract settlement ofderivatives are recorded in the realized gain (loss) line on the consolidated statement of income. F-16 NOTE 7 - FAIR VALUE OF FINANCIAL INSTRUMENTSThe Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs, used in the valuation methodologies inmeasuring fair value: ● Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.● Level 2 – Other inputs that are directly or indirectly observable in the marketplace.● Level 3 – Unobservable inputs which are supported by little or no market activity. The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fairvalue. The Company’s cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer depositsapproximate fair value due to the short-term nature or maturity of the instruments. The Company’s fixed rate 10% and 8% term loans and convertibledebentures are measured using Level 1 inputs. Derivative InstrumentsThe Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted marketprices in active markets, quotes from third parties, and the credit rating of its counterparty. The Company also performs an internal valuation to ensure thereasonableness of third-party quotes.The types of derivative instruments utilized by the Company included commodity swaps. The oil derivative markets are highly active. Although theCompany’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly tradedon an exchange. As such, the Company has classified these instruments as Level 2.In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make anycontractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources andwillingness to meet its potential repayment obligations associated with the derivative transactions. Asset Retirement ObligationThe income valuation technique is utilized to determine the fair value of its asset retirement obligation liability at the point of inception by taking into account:1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which are based on estimates from reserve engineers; 3) the inflation rate; and 4) the credit adjusted risk-freerate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement ofthe asset retirement obligation liability is deemed to use Level 3 inputs.Convertible Debentures Payable Conversion FeatureIn February 2011, the Company issued in a private placement $8.40 million aggregate principal amount of three year 8% Senior Secured ConvertibleDebentures (“Debentures”) with a group of accredited investors. During the year ended December 31, 2012, the Company issued an additional $5.00 millionof Debentures, resulting in a total of $13.40 million of Debentures outstanding as of December 31, 2012. As of December 31, 2012, the Debentures areconvertible at any time at the holders’ option into shares of our common stock at $4.25 per share, subject to certain adjustments, including the requirement toreset the conversion price based upon any subsequent equity offering at a lower price per share amount. The Company engaged a third party to complete avaluation of this conversion. F-17 The following table provides a summary of the fair values of assets and liabilities measured at fair value: December 31, 2012 Level 1 Level 2 Level 3 Total Assets Commodity derivative instruments $- $- $- $- Total assets, at fair value $- $- $- $- Liability Convertible debentures conversion derivative liability $ - $ - $ (1,680,000) $ (1,680,000)Total liability, at fair value $- $- $(1,680,000) $(1,680,000)December 31, 2011 Level 1 Level 2 Level 3 Total Liability Commodity derivative instruments $- $(75,609) $- $(75,609)Convertible debentures conversion derivative liability - - (1,300,000) (1,300,000)Total liability at fair value $- $(75,609) $(1,300,000) $(1,375,609) The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of December 31, 2012: Beginning balance, December 31, 2011 $(1,300,000)Convertible debentures conversion derivative gain 320,000 Additions to derivative liability from Supplemental Debenture (700,000)Ending balance, December 31, 2012 $(1,680,000) The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the yearending December 31, 2012 and 2011.NOTE 8 - LOAN AGREEMENTSTerm LoansThe Company entered into three separate loan agreements with Hexagon in January, March and April 2010, each with an original maturity date of December 1,2010. All three loans originally bore annual interest of 15% (which has been reduced, as discussed below), currently mature on May 16, 2014, and havesimilar terms, including customary representations and warranties and indemnification, and require the Company to repay the loans with the proceeds of themonthly net revenues from the production of the acquired properties. The loans contain cross collateralization and cross default provisions and arecollateralized by mortgages against a portion of the Company’s developed and undeveloped leasehold acreage.We entered into a loan modification agreement on May 28, 2010, which extended the maturity date of the loans to December 1, 2011. In consideration forextending the maturity of the loans, Hexagon received 250,000 warrants with an exercise price of $6.00 per share. The loan modification agreement alsorequired the Company to issue 250,000 five year warrants to purchase common stock at $6.00 per share to Hexagon if the Company did not repay the loans infull by January 1, 2011. Since the loans were not paid in full by January 1, 2011, the Company issued 250,000 additional warrants with an exercise price of$6.00 per share to Hexagon which was valued at approximately $1.60 million. This amount was recorded as a deferred financing cost and is being amortizedover the remaining term of the loan. In December 2010, Hexagon extended the maturity date of the loans to September 1, 2012. During the last six months of 2011, Hexagon agreed to temporarilysuspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2.00 million as payment on the loans. InNovember 2011, Hexagon extended the maturity to January 1, 2013. In November 2011, Hexagon also temporarily advanced the Company an additionalamount of $0.31 million, which was repaid in full in February 2012. In March 2012, Hexagon extended the maturity of the loans to June 30, 2013, and inconnection there with, the Company agreed to make minimum monthly note payments of $0.33 million, effective immediately. In July 2012, Hexagonextended the maturity date to September 30, 2013. In November 2012, Hexagon extended the maturity date of the loans to December 31, 2013. On December 27, 2012, in connection with the Company’s lease of deep rights on approximately 6,300 net acres to a third party for total consideration of$1.5 million, the Company paid Hexagon $0.75 million, which reduced the long-term debt principal amount.In April 2013, Hexagon agreed to amend all three loan agreements to extended the maturity date to May 16, 2014, reduce the interest rate to 10% from 15%beginning retroactively with March 2013, decrease our minimum payment under the term loans to $0.23 or $0.19, depending on our ability to complete thesale of certain of our assets by July 1, 2013, and require us to pay interest only for March, April, May, and June. In consideration for the extended maturitydate, reduced interest rate, and reduced minimum loan payment, we are required to provide them an additional security interest in 15,000 acres of ourundeveloped acreage (see Note 14).The Company is subject to certain non-financial covenants with respect to the Hexagon loan agreements. As of December 31, 2012, the Company was incompliance with all covenants under the facilities.Convertible Debentures Payable In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of 8% Senior Secured Debentures (the“Debentures”), secured by mortgages on several of our properties. Initially, the Debentures were convertible at any time at the holders' option into shares of ourcommon stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equityoffering at a lower price per share amount. Interest at an annualized rate of 8% is payable quarterly on each May 15, August 15, November 15 and February15 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 10trading days prior to an interest payment date. The Company can redeem some or all of the Debentures at any time. The redemption price is 115% ofprincipal plus accrued interest. If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price willinclude a make-whole premium equal to the remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable incommon stock. T.R. Winston & Company LLC acted as placement agent for the private placement and received $0.40 million of Debentures equal to 5% ofthe gross proceeds from the sale. The Company is amortizing the $0.40 million over the life of the loan as deferred financing costs. The Company amortized$0.16 million of deferred financing costs into interest expense during the year ended December 31, 2012, and has $0.14 million of deferred financing costs tobe amortized through May 2014. F-18 In December 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share. This amendment was aninducement consideration to the Debenture holders for their agreement to release a mortgage on certain properties so the properties could be sold. The sale ofthese properties was effective December 31, 2011, and a final closing occurred during the three months ended March 31, 2012. On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to issue up to an additional $5.0 million in additionaldebentures (the “Supplemental Debentures”). Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of SupplementalDebentures were used principally for the development of certain of the Company's proved undeveloped properties and other undeveloped acreage currentlytargeted by the Company for exploration, as well as for other general corporate purposes. Any new producing properties developed from the proceeds ofSupplemental Debentures are to be pledged as collateral under a mortgage to secure future payment of the Debentures and Supplemental Debentures. All termsof the Supplemental Debentures are substantively identical to the Debentures. The Agreements also provided for the payment of additional consideration to thepurchasers of Supplemental Debentures in the form of a proportionately reduced 5% carried working interest in any properties developed with the proceeds ofthe Supplemental Debenture offering.Through July 2012, we received $3.04 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development ofsix new wells, resulting in a total investment of $3.69 million. Five of these wells resulted in commercial production, and one well was plugged andabandoned.In August 2012, the Company and holders of the Supplemental Debentures agreed to renegotiate the terms of the Supplemental Debenture offering. Thesenegotiations concluded with the issuance of an additional $1.96 million of Supplemental Debentures. The August 2012 modifications to the SupplementalDebenture agreements increased the carried working interest from 5% to 10% and also provided for a one-year, proportionately reduced net profits interest of15% in the properties developed with the proceeds of the Supplemental Debenture offering, as well as the next four properties to be drilled and developed by theCompany.The Company has estimated the total value of consideration paid to Supplemental Debenture holders in the form of the modified net profits interest and carriedworking interest to be approximately $1.16 million, and recorded this amount as a debt discount to be amortized over the remaining life of the SupplementalDebentures. We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect toDecember 31, 2012, the Supplemental Debentures. This valuation resulted in an estimated derivative liability as of December 31, 2012 and December 31,2011 of $1.68 million and $1.30 million, respectively. The portion of the derivative liability that is associated with the Supplemental Debentures, in theapproximate amount of $0.70 million, has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.During the year ended December 31, 2012 and 2011, the Company amortized $2.36 million and $1.52 million, respectively, of debt discounts.On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of theSupplemental Debentures. The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs. The Company amortized $0.05million of deferred financing costs into interest expense during the year ended December 31, 2012, and has $0.18 million of deferred financing costs to beamortized through May 2014. In April 2013, the holders of our 8% Senior Secured Convertible Debentures agreed to extend their maturity date to May 16, 2014. In consideration for theextended maturity date the Company is required to provide them an additional security interest in 15,000 acres of our undeveloped acreage (see Note 14). On April 16, 2013, the Company entered into an agreement with one of its existing Debenture holders to issue up to an additional $5.0 million in additionaldebentures with substantially the same terms to the existing 8% Secured Convertible Debentures. Under the terms of this agreement, $1.5 million ofadditional debentures will be issued on or before July 16, 2013. The funds associated with the initial issuance of debentures will be used by the Company forthe drilling and development of certain properties, and for general corporate purposes (see Note 14). F-19 As of December 31, 2012 and December 31, 2011, the convertible debt is recorded as follows: As of December 31,2012 As ofDecember 31,2011 Convertible debentures $13,400,000 $8,400,000 Debt discount (3,099,639) (3,470,932)Total convertible debentures, net $10,300,361 $4,929,068 Annual debt maturities as of December 31, 2012 are as follows:Year 1 $388,351 Year 2 32,347,963 Thereafter - Total $32,736,314 Failure to make periodic interest payments due under the Debentures (including the Supplemental Debentures) may result in acceleration of all principal andinterest then outstanding under the Debentures, and may entitle the holders of the Debentures to exercise their rights to foreclose under the mortgages securingthe Debentures. In addition, failure to make the required monthly payments under our term loans could result in immediate acceleration of both the term loansand the Debentures.Interest ExpenseFor the year ended December 31, 2012 and 2011, the Company incurred interest expense of approximately $8.06 million and $8.22 million, respectively, ofwhich approximately $4.85 million and $5.02 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretionof the convertible debentures payable discount, and convertible debentures interest paid in common stock.NOTE 9 - COMMITMENTS and CONTINGENCIESEnvironmental and Governmental RegulationAt December 31, 2012, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to theCompany. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company hasoperations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling ofproperties, reports concerning operations, royalty rates, and various other matters including taxation. Oil and gas industry legislation and administrativeregulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2012, the Company had not been fined orcited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company. Legal ProceedingsThe Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, theCompany’s liability, if any, in these pending actions would not have a material adverse effect on the financial positions of the Company. The Company’sgeneral and administrative expenses would include amounts incurred to resolve claims made against the Company.Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene ingarnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant has served various writs ofgarnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested, restricted stock. The Company hasasserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. As a result ofbankruptcy proceedings filed by Mr. Parker, the garnishment proceedings have been stayed. At this stage, we cannot express an opinion as to the probableoutcome of this matter.Other Contingencies We could be liable for liquidated damages under registration rights agreements covering approximately 3.2 million shares of our common stock if we fail tomaintain the effectiveness of a prior registration statement as required in the agreements. In such case, we would be required to pay monthly liquidateddamages of up to $0.23 million. The maximum aggregate liquidated damages are capped at $1.37 million. Operating LeasesThe Company leases an office space under a one year operating lease in Denver, Colorado. Rent expense for the years ended December 31, 2012 and December31, 2011, was $0.09 million and $0.08 million, respectively. The Company will have minimum lease payments of $0.09 million for the year endingDecember 31, 2013. F-20 NOTE 10 - RELATED PARTY TRANSACTIONSDuring fiscal years 2011 and 2012, we have engaged in the following transactions with related parties:Roger Parker. Roger Parker, our chief executive officer until November 15, 2012, has interest in certain of our wells for which he is receiving revenue andjoin-interest billings. As of December 31, 2012, Mr. Parker had $0.01 million in receivables outstanding and continued to have additional receivables basedon monthly production and well maintenance. Furthermore, upon his resignation on November 15, 2012, the Company entered into a separation agreementwhich provided that Mr. Parker receive a one-year salary severance and health benefits for the year, and also provide for the deferral of vesting of 1,350,000shares into 2013. In return, the Company received a general release and certain non-compete terms from Mr. Parker, and are also to receive no less than 10hours per week of Mr. Parker’s time as a consultant to the Company. As of December 31, 2012, the Company owes Mr. Parker $0.26 million in severancesalary and health insurance, all of which was accrued as an expense in 2012.At the time of his retirement, Mr. Parker had been granted 1,350,000 shares of unvested common stock. As a result of his separation from the Company, itwas deemed improbable that these shares would vest to Mr. Parker in his capacity as an employee of the Company due to the termination of employment;however, it was deemed probable that these shares will vest under his separation agreement. As a result, the Company reversed all of the compensationexpense, in the amount of $6.75 million, associated with stock grants to Mr. Parker during his tenure as an employee, and recorded a consulting expense (inthe amount of $3.59 million) related to the shares of stock that are expected to vest during the severance period of the separation agreement. The net differenceof these two amounts resulted in a reduction in 2012 general and administrative expenses of $3.16 million.Edward Mike Davis. Prior to 2011, we acquired a significant portion of our oil and gas properties from Edward Mike Davis, L.L.C. and Spottie, Inc., bothowned by Edward Mike Davis. We paid for these acquisitions in a combination of cash and stock. As a result of these transactions, the Davis entities receivedan aggregate of 3,291,667 shares of our common stock. As of December 31, 2012, Davis had sold substantially all of his Recovery stock.During 2011 and 2012, the Company entered into minor leasing activities with Mr. Davis and his affiliates, which included swapping certain tracts ofundeveloped acreage, the purchase of certain seismic data, and the farm out and farming of certain tracts of acreage. All of these transactions were competedon terms that were consistent with those that could be achieved with other third parties.T.R. WinstonOn September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of theSupplemental Debentures. The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs. The Company amortized $0.01million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.22 million of deferred financing coststo be amortized through May 2014.TRW ExplorationUnder the terms of a December 2010 joint venture agreement, TRW Exploration paid us $2 million for the purchase of an interest in the 2,400 net acres andalso paid $7.1 million of the drilling and completion costs of two horizontal wells to earn a 60% working interest in each well. These two wells were drilledand completed in 2011. Both wells were carried as wells in progress as of December 31, 2011, but were transferred to developed properties in 2012, and theCompany currently attributes no commercial reserves to either property Upon termination of the joint venture in December 2011, TRW sold the Company itsinterest in the wells along with all of its rights to the undeveloped acreage in consideration for the issuance by the Company of 1,500,000 shares of unregisteredcommon stock that we valued at $4,875,000, and certain mutual releases. TRW Exploration was majority owned by several of our shareholders, at least oneof whom owned more than 5% of our outstanding common stock at the time the shares were issued.Conflict of Interest PolicyWe have a corporate conflict of interest policy that prohibits conflicts of interests unless approved by the board of directors. Our board of directors hasestablished a course of conduct whereby it considers in each case whether the proposed transaction is on terms as favorable or more to the Company thanwould be available from a non-related party. Our board also looks at whether the transaction is fair and reasonable to us, taking into account the totality of therelationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Each of the related partytransactions was presented to our board of directors for consideration and each of these transactions was unanimously approved by our board of directorsafter reviewing the criteria set forth in the preceding two sentences. Each of our purchases from Davis was individually negotiated, and none of thetransactions was contingent upon or otherwise related to any other transaction. F-21 NOTE 11 - INCOME TAXES The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2012 and 2011 were: 2012 2011 Deferred tax assets: Oil and gas properties and equipment $8,496,988 $(515,123)Net operating loss carry-forward 14,910,936 11,291,513 Share based compensation 3,885,974 4,675,241 Abandonment obligation 238,864 205,145 Derivative instruments 173,826 176,514 Other (48,909) (91,304)Total deferred tax asset 27,657,679 15,741,986 Valuation allowance (27,657,679) (15,741,986)Net deferred tax asset $- $- Reconciliation of the Company’s effective tax rate to the expected federal tax rate is: For the Year EndedDecember 31, 2012 2011 Effective federal tax rate 35.00% 35.00%Effect of permanent differences -4.43% -7.35%State tax rate 1.64% 1.22%Change in rate -% -%Other -% -%Valuation allowance -32.21% -28.87%Net -% -%At December 31, 2012 and 2011, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $40,699,000 and$30,350,000, respectively that may be offset against future taxable income. The Company has established a valuation allowance for the full amount of thedeferred tax assets as management does not currently believe that it is more likely than not that these assets will be recovered in the foreseeable future. To theextent not utilized, the net operating loss carry-forwards as of December 31, 2012 will expire in 2032. Net operating loss carryovers may be subject toreduction or limitation by application of Internal Revenue Code Section 382 from the result of ownership changes. NOTE 12 - SHAREHOLDERS’ EQUITYCommon StockEffective October 19, 2011, the Company completed a four-for-one reverse stock split of its common shares. All references to common stock and commonstock prices have been adjusted to reflect the effects of the reverse stock split. F-22 As of December 31, 2012, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 18,394,401shares of common stock were issued and outstanding. No preferred shares were issued or outstanding. During the year ended December 31, 2012, the Company granted 777,699 shares of common stock as restricted stock grants to employees, board members,and consultants valued at $2.08 million. The Company also issued 278,225 shares for payment of quarterly interest expense on the convertible debenturesvalued at $0.89 million, and 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as placement agent of the SupplementalDebentures. During 2012, the Company cancelled 123,184 shares of unvested common stock as a result of employee terminations.WarrantsA summary of warrant activity for the nine months ended December 31, 2012 is presented below: Weighted-Average Warrants Exercise Price Outstanding at December 31, 2011 5,638,900 $7.04 Granted 600,000 5.00 Exercised, forfeited, or expired (600,000) (5.00) Outstanding at December 31, 2012 5,638,900 $7.04 During 2012, the Company entered into a financial advisory agreement with a consulting firm that provided for the issuance of 600,000 warrants. However,this agreement was cancelled by mutual agreement during 2012 and no warrants were actually earned by the consulting firm. The Company recorded nocompensation expense related to these warrants.The aggregate intrinsic value of the warrants was approximately $0 as of both December 31, 2012 and December 31, 2011, based on the Company’s closingcommon stock price of $1.99 and $3.01, respectively; and the weighted average remaining contract life was 2.56 years and 2.93 years, respectively.NOTE 13 - SHARE BASED AND OTHER COMPENSATIONShare-Based CompensationIn September 2012, the Company adopted the 2012 Equity Incentive Plan (the “Plan”). Each member of the board of directors and the management team hasbeen periodically awarded restricted stock grants, and in the future will be awarded such grants under the terms of the Plan. The costs of employee services received in exchange for an award of equity instruments are based on the grant-date fair value of the award, recognized over theperiod during which an employee is required to provide services in exchange for such award. During the year ended December 31, 2012, the Company granted 693,289 shares of restricted common stock to employees and directors of which 335,996,132,287, 132,294, and 92,712 shares vest during the years ended December 31, 2012, 2013, 2014, and 2015, respectively. The fair value of these sharegrants was calculated to be approximately $1.28 million. As of December 31, 2012, 1,485,378 shares expired due to termination of managementpersonal. The Company also granted 100,000 shares to a consultant and 50,000 shares to T.R. Winston & Company LLC for acting as a placement agent ofthe Supplemental Debentures, valued at $0.58 million The Company recognized a credit to stock compensation expense of approximately $1.75 million and an expense of $6.16 million, respectively, for the yearended December 31, 2012 and 2011. F-23 A summary of restricted stock grant activity for the year ended December 31, 2012 is presented below: Shares Balance outstanding at December 31, 2011 2,340,235 Granted 2,984,181 Vested (986,769)Expired/ cancelled (2,606,937)Balance outstanding at December 31, 2012 1,730,710 Total unrecognized compensation cost related to unvested stock grants was approximately $0.92 million as of December 31, 2012. The cost at December 31,2012 is expected to be recognized over a weighted-average remaining service period of 3 years.On November 15, Roger Parker retired from the Company as its chief executive officer. At the time of his retirement, Mr. Parker had been granted 1,350,000shares of unvested common stock. As a result of his separation from the Company, it was deemed improbable that these shares would vest to Mr. Parker inhis capacity as an employee of the Company due to the termination of employment; however, it was deemed probable that these shares will vest under hisseparation agreement. As a result, the Company reversed all of the compensation expense, in the amount of $6.75 million, associated with stock grants to Mr.Parker during his tenure as an employee, and recorded a consulting expense (in the amount of $3.59 million) related to the shares of stock that are expected tovest during the severance period of the separation agreement. The net difference of these two amounts resulted in a reduction in 2012 general andadministrative expenses of $3.16 million.Other CompensationWe sponsor a 401(k) savings plan. All regular full-time employees are eligible to participate. We make contributions to match employee contributions up to 5%of compensation deferred into the plan. The Company made cash contributions of $0.04 million in 2012. NOTE 14- SUBSEQUENT EVENTSIn April 2013, we amended both our secured term loans and our 8% Senior Secured Convertible Debentures to extend their maturity dates to May 16, 2014. Inconsideration for the extended maturity date of both loans and the reduced interest rate and minimum loan payment under the secured term loans, theCompany will be required to provide both Hexagon and the holders of our debentures an additional security interest in 15,000 acres (or 30,000 acres inaggregate) of our undeveloped acreage. Additionally, pursuant to the amendment to our secured term loan, Hexagon has agreed to (i) reduce our interest ratefrom 15% to 10% beginning retroactively with March 2013, (ii) permit us to make interest-only payments for March, April, May, and June, after which timethe minimum secured term loan payment will be $0.23 million or $0.19 million, depending on our ability to consummate the sale of certain of our assets byJuly 1, 2013, and (iii) forbear from exercising its rights under the term loan credit agreements for any breach that may have occurred prior to the amendment.In addition, we are required under the amendment to use our reasonable best efforts to pursue certain transactions to improve our financial condition, includingthe aforementioned sale of certain of our assets, an equity offering or similar capital-raising transaction, one or more joint venture development agreements, andan engineering study of certain of our producing properties to ascertain possible operations to enhance production from those properties. Pursuant to thedebenture amendment, the Company and the debenture holders have agreed to waive any breach under the debentures that may have occurred prior to the dateof the amendment.On April 16, 2013, the Company entered into an agreement with one of its existing Debenture holders to issue up to an additional $5.0 million in additionaldebentures with substantially the same terms to the existing 8% Secured Convertible Debentures. Under the terms of this agreement, $1.5 million ofadditional debentures will be issued on or before July 16, 2013. The funds associated with the initial issuance of debentures will be used by the Company forthe drilling and development of certain properties, and for general corporate purposes.We currently have $19.34 million outstanding under our term loans and $13.40 million outstanding under our debentures.NOTE 15- SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) The following table sets forth information for the years ended December 31, 2012 and 2011 with respect to changes in the Company's proved (i.e. proveddeveloped and undeveloped) reserves: Natural Gas Crude Oil(Bbls) (Mcf) December 31, 2010 692,388 308,579 Purchase of reserves - - Revisions of previous estimates (268,718) (44,919)Extensions, discoveries 266,000 - Sale of reserves Production (81,433) (115,583)December 31, 2011 608,237 148,077 Purchase of reserves 39,327 - Revisions of previous estimates (2) (310,919) 25,813 Extensions, discoveries 99,615 313,958 Sale of reserves - - Production (85,160) (80,438)December 31, 2012 351,100 407,410 Proved Developed Reserves, included above: Balance, December 31, 2010 277,669 308,579 Balance, December 31, 2011 215,693 148,077 Balance, December 31, 2012 213,306 186,017 Proved Undeveloped Reserves, included above: Balance, December 31, 2010 414,719 - Balance, December 31, 2011 392,545 - Balance, December 31, 2012 (2) 137,555 221,314 F-24 As of December 31, 2012 and December 31, 2011, we had estimated proved reserves of 350,861 and 608,237 barrels of oil, respectively and 67,889 and24,680 thousand cubic feet ("MCF") of natural gas, respectively. Our reserves are comprised of 84% and 93% crude oil and 16% and 7% natural gas on anenergy equivalent basis, as of December 31, 2012 and December 31, 2011, respectively. The following values for the December 31, 2012 and December 31, 2011 oil and gas reserves are based on the 12 month arithmetic average first of month priceJanuary through December 31; resulting in a natural gas price of $2.75 and $3.96 per MMBtu (NYMEX price), respectively, and crude oil price of $87.37and $88.16 per barrel (West Texas Intermediate price), respectively. All prices are then further adjusted for transportation, quality and basis differentials. The following summary sets forth the Company's future net cash flows relating to proved oil and gas: For the Year EndedDecember 31, (in thousands) 2012 2011 Future oil and gas sales $32,612 $55,295 Future production costs (9,718) (16,579)Future development costs (546) (8,481)Future income tax expense (1) - - Future net cash flows 22,348 30,235 10% annual discount (6,926) (10,221) Standardized measure of discounted future net cash flows (2) $15,422 $20,014 (1)Our calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for allyears reported. We expect that all of our Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company'soperations, and resulting NOLs, are attributable to our oil and gas assets. There were no taxes in any year as the tax basis and NOLs exceeded thefuture net revenue. (2)The decrease in oil barrels of proved undeveloped reserves to 138 MBO as of the end of 2012 from 392 MBO as of the end of 2011, a decrease of 254MBO or 65%, reflects the current uncertainty regarding whether the Company will have sufficient capital to support its current development plan. Asof December 31, 2012, proved undeveloped reserves reflect the assumption that such reserves will be developed on a promoted basis of 25%, therebyreducing net PUD volumes that would otherwise by recoverable by 75%, and also effecting a corresponding decrease in the PV10 value. This changein assumptions is reflected in “Revisions of Previous Estimates in the above table, and also reflected in “Revisions of previous quantity estimates” inthe table below. The elimination of the capital costs associated with the promoted interest assumption is reflected in the table below in the caption “Netchanges in future development costs”. The Company is working on alternative capital infusion plans that could allow it to maintain a higher workinginterest position in the undeveloped acreage locations. With the exception of a single well location, the Company currently holds a one hundred percentleasehold position in all the undrilled locations classified as proved undeveloped. A successful capital campaign could result in the Companymaterially increasing its proved undeveloped reserve position.. F-25 The principle sources of change in the standardized measure of discounted future net cash flows are: 2012 2011 Balance at beginning of period $20,014 $23,595 Sales of oil and gas, net (4,656) (5,342)Net change in prices and production costs (1,724) 8,006 Net change in future development costs (2) 7,766 - Extensions and discoveries 3,916 5,883 Acquisition of reserves 1,677 - Sale of reserves - - Revisions of previous quantity estimates (2) (15,031) (14,804)Previously estimated development costs incurred 638 - Net change in income taxes - - Accretion of discount 2,001 2,360 Other 821 316 Balance at end of period $15,422 $20,014 Revisions in 2012 of previous quantity estimates, reflect both the application of the assumption that PUD’s will be developed in the future on a promotedbases, as well as other revisions of certain proven undeveloped well locations that were included in the reserve estimates dated December 31, 2011. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curveanalysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methodsis used to determine reserve estimates in substantially all of our fields. F-26Exhibit 10.56 AMENDMENT TO8% SENIOR SECURED CONVERTIBLE DEBENTURES DUE FEBRUARY 8, 2014This Amendment (“Amendment”), made as of April 15, 2013, by and between Recovery Energy, Inc., a Nevada corporation (the “Company”),and each holder identified on the signature page hereto (the “Holders”), amends that certain Securities Purchase Agreement, dated as of February 2, 2011, asamended on July 23, 2012 and August 7, 2012, between the Company and the Holders identified as original holders on the signature page hereto (the“Original Purchase Agreement”); that certain Securities Purchase Agreement, dated as of March 19, 2012, as amended on July 23, 2012 and August 7,2012, between the Company and certain of the Original Holders as well as the Holders identified as supplemental holders on the signature page hereto (the“Supplemental Purchase Agreement” and together with the Original Purchase Agreement, the “Purchase Agreements”); those certain 8% Senior SecuredConvertible Debentures due February 8, 2014, as amended on December 16, 2011, March 23, 2012 and July 23, 2012, issued pursuant to the OriginalPurchase Agreement (the “Original Debentures”); and those certain 8% Senior Secured Convertible Debentures due February 8, 2014, as amended on July23, 2012, issued pursuant to the Supplemental Purchase Agreement (the “Supplemental Debentures” and together with the Original Debentures, the“Debentures”). RecitalsWHEREAS, the Company issued the Original Debentures pursuant to the Original Purchase Agreement and the Supplemental Debentures pursuantto the Supplemental Purchase Agreement;WHEREAS, the Company and the Holders wish to amend the Debentures to (i) extend the maturity date from February 8, 2014 to May 16, 2014,and (ii) grant to the Holders an additional security interest in fifteen thousand (15,000) net acres of property not currently pledged as collateral under theDebentures, which shall include the Company’s interest in the Sawyer property and the Lang Prospect, each being ¼ section tracts in the Weld County,Colorado (the “Additional Collateral”); andWHEREAS, the Company and the Holders wish to waive certain provisions contained in the Debentures, and to clarify others.NOW THEREFORE, in consideration of the promises and mutual covenants and obligations herein set forth and for other good and valuableconsideration, the receipt, sufficiency and adequacy of which is hereby acknowledged, accepted and agreed to, the parties hereto, intending to be legallybound, hereby agree as follows:Agreement1. Maturity Date. The Company and the Holders hereby agree to extend the Maturity Date (as defined in the Debentures) from February 14, 2014 toMay 16, 2014.2. Grant of Lien on Additional Collateral. The Company hereby grants Holders a first priority lien in the Additional Collateral as security for theobligations of the Company under the Debentures, to be reflected in appropriate Security Documents (as defined in the Purchase Agreements). The Companyagrees to use its reasonable best efforts to execute and record such Security Documents with respect to the lien by May 15, 2013. 1 3. Waiver. Each of the Company and each Holder hereby waives any actual or alleged breach of the terms of the Debentures or the PurchaseAgreements that may have occurred prior to the date of this Amendment.4. Clarification. Each of the Company and the Holder hereby agrees that pursuant to the original intent of the parties to the Debentures, no past orfuture payment by the Company of interest on the Debentures in shares of the Company’s common stock shall constitute a Dilutive Issuance pursuant toSection 5(b) of the Debentures or a Preemptive Issuance pursuant to Section 9(j) of the Debentures.5. Authority. Each Holder hereby represents and warrants that it is a party to one or both of the Purchase Agreements and has full power andauthority to enter into this Amendment on the terms set forth herein.6. Further Assurances. Holders shall from time to time execute such additional instruments and documents, take such additional actions, and givesuch further assurances as are or may be reasonable or necessary to implement this Amendment. 7. Binding Effect. The terms of this Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective heirs, personalrepresentatives, successors and assigns.8. Reaffirmation of Debenture Terms. All terms of the Purchase Agreements, as previously amended, shall, except as amended hereby, remain in fullforce and effect, and are hereby ratified and confirmed.9. Governing Law. This Amendment shall be governed by and construed and enforced in accordance with the internal laws of the State of New York,without regard for principles of conflict of laws thereof.10. Counterparts. This Amendment may be executed in two or more counterparts, each of which shall be deemed an original, but all of which togethershall constitute one and the same instrument.[Signature page follows] 2 IN WITNESS WHEREOF, the parties hereto have duly executed this Amendment effective as of the date first set forth above. COMPANY Recovery Energy, Inc. By:/s/ A. Bradley Gabbard Name: A. Bradley Gabbard Title:President and Chief Financial Officer HOLDERS Original Holders EZ Colony Partners, LLC, a Delaware limited liability company /s/ Bryan Ezralow Name: Bryan Ezralow as Trustee of the Bryan Ezralow 1994 Trust Title:Managing General Partner Jonathan & Nancy Glaser Family Trust DTD 12/16/1998 Jonathan M. Glaserand Nancy E. Glaser TTEES /s/ Jonathan Glaser Name: Jonathan Glaser Title: Trustee T.R. Winston & Company, LLC /s/ John W. Galuchie, Jr. Name: John W. Galuchie, Jr. Title: President Wallington Investment Holdings, Ltd. /s/ Michael Khoury Name: Michael Khoury Title: Director 3 Steven B. Dunn and Laura Dunn Revocable Trust DTD 10/28/10, Steven B.Dunn & Laura Dunn TTEES /s/ Steven B. Dunn Name: Steven B. Dunn Title: Trustee Supplemental Holders G. Tyler Runnels and Jasmine N. Runnels TTEES The Runnels Family TrustDTD 1-11-2000 /s/ G. Tyler Runnels Name: G. Tyler Runnels Title:Trustee Ezralow Marital Trust u/t/d 01/12/2002 /s/ Marc Ezralow Name: Marc Ezralow Title:Trustee Ezralow Family Trust u/t/d 12/09/1980 /s/ Marc Ezralow Name: Marc Ezralow Title:Trustee EMSE, LLC,a Delaware limited liability company /s/ Marc Ezralow Name: Marc Ezralow Title:Manager Elevado Investment Company, LLC,a Delaware limited liability company /s/ Marc Ezralow Name: Marc Ezralow Title:Trustee of the Ezralow Family Trust 4Exhibit 10.57 FOURTH AMENDMENT TO CREDIT AGREEMENT(First Credit Agreement) This FOURTH AMENDMENT TO CREDIT AGREEMENT (this “Amendment”), dated effective as of March 1, 2013 (the “Effective Date”), is betweenRecovery Energy, Inc., a Nevada corporation (“Borrower”), and Hexagon, LLC, a Colorado limited liability company, formerly known as HexagonInvestments, LLC (“Lender”). RECITALS A. Borrower and Lender have entered into a Credit Agreement, dated as of January 29, 2010 (as modified by (i) that certain Amendment toPromissory Note, dated December 29, 2010, (ii) that certain Second Amendment to Promissory Note, dated November 14, 2011, (iii) that certain Amendmentto Credit Agreement dated March 15, 2012, (iv) that certain Second Amendment to Credit Agreement dated July 31, 2012, (v) that certain Third Amendmentto Credit Agreement dated November 8, 2012, and as further amended, modified, supplemented, substituted or replaced, the “Credit Agreement”), providingfor a term loan in the original principal amount of $4,500,000. Defined terms used herein and not defined herein shall have the meanings set forth in theCredit Agreement. B. Borrower has asked Lender, and Lender has agreed to amend the terms and conditions of the Credit Agreement to extend the Maturity Dateuntil May 16, 2014, subject to and as more fully set forth in this Amendment. AGREEMENT In consideration of the foregoing and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Borrowerand Lender agree as follows: 1. Amendment to Credit Agreement. Effective as of the Effective Date and upon the terms and subject to the conditions set forth in this Amendment: (a) Section 1.1 of the Credit Agreement is hereby amended by deleting “December 31, 2013” in the definition of “Maturity Date” and replacingit with “May 16, 2014”. (b) Section 2.1(d) of the Credit Agreement is hereby deleted in its entirety and replaced with the following: “(d) The Loan shall bear interest at a rate of 15.00% per annum for all periods prior to March 1, 2013. For all periods commencingMarch 1, 2013 and thereafter, the Loan shall bear interest at a rate of 10.00% per annum.”  (c) Section 2.2 of the Credit Agreement is hereby deleted in its entirety and replaced with the following: “Section 2.2 Mandatory Prepayments. Commencing with March, 2013, Borrower shall be required only to make payments of interestaccruing under the Loan for the months of March, April, May and June 2013, each such interest payment to be due for a particular monthon or before the last day of that month. Commencing with July, 2013, Borrower shall repay the Loan and any amounts due under theOther Credit Agreements (as defined below) with the greater of: (a) the sum of 100% of the Net Proceeds from the Oil and Gas Properties asdefined in the Credit Agreement plus 100% of the Net Proceeds from the Oil and Gas Properties as defined in the Credit Agreement datedMarch 25, 2010 and the Credit Agreement dated April 14, 2010, each between Borrower and Lender (the “Other Credit Agreements”), and(b) either (i) $190,000 if a sale of the Palm Field (as described in Section 2.6(a) below) has closed on or before July 1, 2013 for a sale priceof $4,500,000 or such other price as is mutually agreed by Borrower and Lender, or (ii) $225,000 if the condition in clause (i) is notsatisfied. Such amounts paid under this Section 2.2 shall be applied to amounts due under the Loan and the amounts due under the OtherCredit Agreements in a manner as determined by Lender in its sole discretion.” (d) Section 2.4 of the Credit Agreement is hereby amended by deleting "December 31, 2013" in the second line and replacing it with "May 16,2014". (e) Section 2.5 of the Credit Agreement is hereby amended by deleting Sections 2.5(b) and 2.5(c) in their entirety. (f) A new Section 2.6 of the Credit Agreement is hereby added as follows: “Section 2.6 Additional Equity and Development Covenants. Borrower agrees to use its reasonable best efforts to pursue the followingtransactions and other actions to improve the financial condition of Borrower: (a) A sale for cash on or before July 1, 2013 of all of Borrower’s oil and gas interests and wells in the Palm Field located in T. 17 N.,R. 58 W., Banner County, Nebraska, for a price that is mutually agreed by Borrower and Lender. All of the proceeds of any such saleshall be paid to Lender and shall reduce the amount outstanding under the Credit Agreement dated March 25, 2010 and, to the extent theproceeds exceed the amount outstanding under such Credit Agreement, the amounts due under this Credit Agreement or the Credit Agreementdated April 14, 2010, the allocation of which Lender shall determine in its sole discretion. (b) An equity offering or other transaction to provide additional equity for the Borrower, through an investment banking firm deemedby Borrower in its reasonable discretion to have suitable qualifications for such transaction. (c) One or more joint venture development agreements to develop the Borrower’s oil and gas assets with a financial or oil and gasindustry entity with suitable financial strength and technical expertise for the successful implementation of such development agreements. (d) Engineering study of Borrower’s producing oil and gas properties in the Wilke and State Line Fields (in Banner and KimballCounties, Nebraska and Laramie County, Wyoming) to ascertain possible operations to enhance production from such properties. 2 (g) A new Section 2.7 of the Credit Agreement is hereby added as follows: “Section 2.7 Additional Collateral. Promptly, and in no event more than 10 business days following the execution of this Amendment,Borrower shall execute and deliver an Amendment to the Mortgages, in form provided by Lender’s counsel, adding to the collateral coveredby the Mortgages 15,171 net acres of undeveloped leases owned by Borrower in the Pine Bluffs Prospect, Banner and Kimball Counties,Nebraska and Laramie County, Wyoming.” 2. Other Agreements. (a) Borrower and Lender agree that all of the Loan Documents are hereby amended to reflect the amendments set forth herein andthat no further amendments to any Loan Documents are required to reflect the foregoing; and (b) all references in any document to “Credit Agreement” or any“Loan Document” shall refer to the Credit Agreement or any such Loan Document, as amended pursuant to this Amendment. 3. Representations and Warranties. Borrower hereby certifies to Lender that as of the date of this Amendment and as of the Effective Date (taking intoconsideration the transactions contemplated by this Amendment) all of Borrower’s representations and warranties contained in the Credit Agreement and eachof the Loan Documents are true, accurate and complete in all material respects. Without limiting the generality of the foregoing, Borrower represents andwarrants that (i) the execution and delivery of this Amendment has been authorized by all necessary action on the part of Borrower, (ii) the person executingthis Amendment on behalf of Borrower is duly authorized to do so, and (iii) this Amendment constitutes the legal, valid, binding and enforceable obligation ofBorrower. 4. Additional Documents. Borrower shall execute and deliver, and shall cause to be executed and delivered, to Lender at any time and from time totime such documents and instruments, including without limitation additional amendments to the Credit Agreement and the Loan Documents, as Lender mayreasonably request to confirm and carry out the transactions contemplated hereby or by any other Loan Documents executed in connection herewith. 5. Continuation of the Credit Agreement and Loan Documents. Except as specified in this Amendment, the provisions of the Credit Agreement and theLoan Documents shall remain in full force and effect, and if there is a conflict between the terms of this Amendment and those of the Credit Agreement or theLoan Documents, the terms of this Amendment shall control. This Amendment is a Loan Document. 6. Ratification and Reaffirmation of Obligations by Borrower. Borrower hereby (a) ratifies and confirms all of its Obligations under the CreditAgreement and each of the other Loan Documents, and acknowledges and agrees that such Obligations remain in full force and effect, and (b) ratifies,reaffirms and reapproves in favor of Lender the terms and provisions of the Credit Agreement and each of the other Loan Documents, including (withoutlimitation), its pledges and other grants of Liens and security interests pursuant to the Loan Documents. 3 7. Release and Indemnification. (a) Borrower hereby fully, finally, and forever releases and discharges Lender, and its successors, assigns, directors, officers, employees,agents and representatives, from any and all causes of action, claims, debts, demands and liabilities, of whatever kind or nature, in law or equity, ofBorrower, whether now known or unknown to Borrower in respect of (i) the Obligations under the Credit Agreement and each of the other Loan Documents or(ii) the actions or omissions of Lender in any manner related to the Obligations under the Credit Agreement and each of the other Loan Documents; providedthat this Section shall only apply to and be effective with respect to events or circumstances existing or occurring prior to and including the date of thisAmendment. (b) Without limiting Section 7.3 of the Credit Agreement, Borrower hereby agrees to indemnify, defend, and hold harmless Lender and itssuccessors, assigns, directors, officers, employees, agents and representatives (each an “Indemnified Party” and collectively the “Indemnified Parties”) fromand against any and all accounts, covenants, agreements, obligations, claims, debts, liabilities, offsets, demands, costs, expenses, actions or causes of actionof every nature, character and description, whether arising at law or equity or under statute, regulation or otherwise, and whether liquidated or unliquidated,contingent or noncontingent, known or unknown, suspected or unsuspected (“Claims”), arising from or made under any legal theory, which any ofIndemnified Parties may incur as a direct or indirect consequence of or in relation to any acts or omissions of Borrower arising from or relating to any of: (i)the Credit Agreement; (ii) the Loan Documents; (iii) this Amendment; or (iv) any documents executed by Borrower in connection with thisAmendment. Should any Indemnified Party incur any such Claims, or defense of or response to any Claims or demand related thereto, the amount thereof,including costs, expenses and attorneys’ fees, shall be added to the amounts due under the Loan Documents, and shall be secured by any and all liens createdunder and pursuant to the Loan Documents. This indemnity shall survive until the Obligations have been indefeasibly paid in full and the termination,release or discharge of Borrower. To the extent permissible under applicable law, this indemnity shall not limit any other rights of indemnification,subrogation or assignment, whether explicit, implied, legal or equitable, that any Indemnified Party may have. 8. Forbearance. Lender hereby agrees to forbear from exercising its rights and remedies under the Credit Agreement and the other Loan Documentsarising as a result of any actual or alleged breach of the terms of the Credit Agreement or other Loan Documents that may have occurred prior to the date of thisAmendment (a “Forbearance Default”); provided, however, that upon the occurrence of any Event of Default other than a Forbearance Default, Lender shall beentitled to exercise any and all of their rights and remedies under the Credit Agreement, the other Loan Documents and applicable law, without further noticeother than as required therein. 9. No Waiver. This Amendment does not constitute a waiver by Lender of Borrower’s compliance with any covenants, or a waiver of any Defaults orEvents of Default, under the Credit Agreement or any of the Loan Documents, and shall not entitle the Borrower to any amendments or waivers in the future. 10. Miscellaneous. Article VIII of the Credit Agreement is hereby incorporated by reference into this Amendment. 11. Condition to Effectiveness. The effectiveness of this Amendment is conditioned upon Borrower obtaining from all of the holders of its 8% SeniorSecured Debentures due February 14, 2014 extensions of the due date of such debentures until a date not earlier than May 16, 2014. Borrower has providedLender with evidence of its satisfaction of this condition, and Lender’s execution of this Amendment shall evidence Lender’s agreement that such condition hasbeen satisfied and that such evidence provided by Borrower is satisfactory to Lender. [Signature Pages Follow] 4 Borrower and Lender have executed this Fourth Amendment to Credit Agreement on April 15, 2013, effective as of the Effective Date first above written. HEXAGON, LLC RECOVERY ENERGY, INC. By:Hexagon, Inc., its Manager By:/s/ Brian Fleishmann By:/s/ A. Bradley Gabbard Brian FleischmannExecutive Vice President A. Bradley GabbardChief Financial Officer 5FOURTH AMENDMENT TO CREDIT AGREEMENT(Second Credit Agreement) This FOURTH AMENDMENT TO CREDIT AGREEMENT (this “Amendment”), dated effective as of March 1, 2013 (the “Effective Date”), is betweenRecovery Energy, Inc., a Nevada corporation (“Borrower”), and Hexagon, LLC, a Colorado limited liability company, formerly known as HexagonInvestments, LLC (“Lender”). RECITALS A. Borrower and Lender have entered into a Credit Agreement, dated as of March 25, 2010 (as modified by (i) that certain Amendment toPromissory Note, dated December 29, 2010, (ii) that certain Second Amendment to Promissory Note, dated November 14, 2011, (iii) that certain Amendmentto Credit Agreement dated March 15, 2012, (iv) that certain Second Amendment to Credit Agreement dated July 31, 2012, (v) that certain Third Amendmentto Credit Agreement dated November 8, 2012, and as further amended, modified, supplemented, substituted or replaced, the “Credit Agreement”), providingfor a term loan in the original principal amount of $6,000,000. Defined terms used herein and not defined herein shall have the meanings set forth in theCredit Agreement. B. Borrower has asked Lender, and Lender has agreed to amend the terms and conditions of the Credit Agreement to extend the Maturity Dateuntil May 16, 2014, subject to and as more fully set forth in this Amendment. AGREEMENT In consideration of the foregoing and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Borrowerand Lender agree as follows: 1. Amendment to Credit Agreement. Effective as of the Effective Date and upon the terms and subject to the conditions set forth in this Amendment: (a) Section 1.1 of the Credit Agreement is hereby amended by deleting “December 31, 2013” in the definition of “Maturity Date” and replacing itwith “May 16, 2014”. (b) Section 2.1(c) of the Credit Agreement is hereby deleted in its entirety and replaced with the following: “(c) The Loan shall bear interest at a rate of 15.00% per annum for all periods prior to March 1, 2013. For all periods commencing March 1,2013 and thereafter, the Loan shall bear interest at a rate of 10.00% per annum.” (c) Section 2.2 of the Credit Agreement is hereby deleted in its entirety and replaced with the following: “Section 2.2 Mandatory Prepayments. Commencing with March, 2013, Borrower shall be required only to make payments of interestaccruing under the Loan for the months of March, April, May and June 2013, each such interest payment to be due for a particular monthon or before the last day of that month. Commencing with July, 2013, Borrower shall repay the Loan and any amounts due under theOther Credit Agreements (as defined below) with the greater of: (a) the sum of 100% of the Net Proceeds from the Oil and Gas Properties asdefined in the Credit Agreement plus 100% of the Net Proceeds from the Oil and Gas Properties as defined in the Credit Agreement datedJanuary 29, 2010 and the Credit Agreement dated April 14, 2010, each between Borrower and Lender (the “Other Credit Agreements”), and(b) either (i) $190,000 if a sale of the Palm Field (as described in Section 2.6(a) below) has closed on or before July 1, 2013 for a sale priceof $4,500,000 or such other price as is mutually agreed by Borrower and Lender, or (ii) $225,000 if the condition in clause (i) is notsatisfied. Such amounts paid under this Section 2.2 shall be applied to amounts due under the Loan and the amounts due under the OtherCredit Agreements in a manner as determined by Lender in its sole discretion.” 1 (d) Section 2.4 of the Credit Agreement is hereby amended by deleting "December 31, 2013" in the second line and replacing it with "May 16,2014". (e) Section 2.5 of the Credit Agreement is hereby amended by deleting Sections 2.5(b) and 2.5(c) in their entirety. (f) A new Section 2.6 of the Credit Agreement is hereby added as follows: “Section 2.6 Additional Equity and Development Covenants. Borrower agrees to use its reasonable best efforts to pursue the followingtransactions and other actions to improve the financial condition of Borrower: (a) A sale for cash on or before July 1, 2013 of all of Borrower’s oil and gas interests and wells in the Palm Field located in T. 17 N.,R. 58 W., Banner County, Nebraska, for a price that is mutually agreed by Borrower and Lender. All of the proceeds of any such saleshall be paid to Lender and shall reduce the amount outstanding under the Loan and, to the extent the proceeds exceed the amountoutstanding under the Loan, the amounts due under the Other Credit Agreements, the allocation of which Lender shall determine in its solediscretion. (b) An equity offering or other transaction to provide additional equity for the Borrower, through an investment banking firm deemed byBorrower in its reasonable discretion to have suitable qualifications for such transaction. (c) One or more joint venture development agreements to develop the Borrower’s oil and gas assets with a financial or oil and gasindustry entity with suitable financial strength and technical expertise for the successful implementation of such development agreements. (d) Engineering study of Borrower’s producing oil and gas properties in the Wilke and State Line Fields (in Banner and KimballCounties, Nebraska and Laramie County, Wyoming) to ascertain possible operations to enhance production from such properties. 2. Other Agreements. (a) Borrower and Lender agree that all of the Loan Documents are hereby amended to reflect the amendments set forth herein andthat no further amendments to any Loan Documents are required to reflect the foregoing; and (b) all references in any document to “Credit Agreement” or any“Loan Document” shall refer to the Credit Agreement or any such Loan Document, as amended pursuant to this Amendment. 2 3. Representations and Warranties. Borrower hereby certifies to Lender that as of the date of this Amendment and as of the Effective Date (taking intoconsideration the transactions contemplated by this Amendment) all of Borrower’s representations and warranties contained in the Credit Agreement and eachof the Loan Documents are true, accurate and complete in all material respects. Without limiting the generality of the foregoing, Borrower represents andwarrants that (i) the execution and delivery of this Amendment has been authorized by all necessary action on the part of Borrower, (ii) the person executingthis Amendment on behalf of Borrower is duly authorized to do so, and (iii) this Amendment constitutes the legal, valid, binding and enforceable obligation ofBorrower. 4. Additional Documents. Borrower shall execute and deliver, and shall cause to be executed and delivered, to Lender at any time and from time to timesuch documents and instruments, including without limitation additional amendments to the Credit Agreement and the Loan Documents, as Lender mayreasonably request to confirm and carry out the transactions contemplated hereby or by any other Loan Documents executed in connection herewith. 5. Continuation of the Credit Agreement and Loan Documents. Except as specified in this Amendment, the provisions of the Credit Agreement and theLoan Documents shall remain in full force and effect, and if there is a conflict between the terms of this Amendment and those of the Credit Agreement or theLoan Documents, the terms of this Amendment shall control. This Amendment is a Loan Document. 6. Ratification and Reaffirmation of Obligations by Borrower. Borrower hereby (a) ratifies and confirms all of its Obligations under the CreditAgreement and each of the other Loan Documents, and acknowledges and agrees that such Obligations remain in full force and effect, and (b) ratifies,reaffirms and reapproves in favor of Lender the terms and provisions of the Credit Agreement and each of the other Loan Documents, including (withoutlimitation), its pledges and other grants of Liens and security interests pursuant to the Loan Documents. 7. Release and Indemnification. (a) Borrower hereby fully, finally, and forever releases and discharges Lender, and its successors, assigns, directors, officers, employees,agents and representatives, from any and all causes of action, claims, debts, demands and liabilities, of whatever kind or nature, in law or equity, ofBorrower, whether now known or unknown to Borrower in respect of (i) the Obligations under the Credit Agreement and each of the other Loan Documents or(ii) the actions or omissions of Lender in any manner related to the Obligations under the Credit Agreement and each of the other Loan Documents; providedthat this Section shall only apply to and be effective with respect to events or circumstances existing or occurring prior to and including the date of thisAmendment. (b) Without limiting Section 7.3 of the Credit Agreement, Borrower hereby agrees to indemnify, defend, and hold harmless Lender and itssuccessors, assigns, directors, officers, employees, agents and representatives (each an “Indemnified Party” and collectively the “Indemnified Parties”) fromand against any and all accounts, covenants, agreements, obligations, claims, debts, liabilities, offsets, demands, costs, expenses, actions or causes of actionof every nature, character and description, whether arising at law or equity or under statute, regulation or otherwise, and whether liquidated or unliquidated,contingent or noncontingent, known or unknown, suspected or unsuspected (“Claims”), arising from or made under any legal theory, which any ofIndemnified Parties may incur as a direct or indirect consequence of or in relation to any acts or omissions of Borrower arising from or relating to any of: (i)the Credit Agreement; (ii) the Loan Documents; (iii) this Amendment; or (iv) any documents executed by Borrower in connection with thisAmendment. Should any Indemnified Party incur any such Claims, or defense of or response to any Claims or demand related thereto, the amount thereof,including costs, expenses and attorneys’ fees, shall be added to the amounts due under the Loan Documents, and shall be secured by any and all liens createdunder and pursuant to the Loan Documents. This indemnity shall survive until the Obligations have been indefeasibly paid in full and the termination,release or discharge of Borrower. To the extent permissible under applicable law, this indemnity shall not limit any other rights of indemnification,subrogation or assignment, whether explicit, implied, legal or equitable, that any Indemnified Party may have. 3 8. Forbearance. Lender hereby agrees to forbear from exercising its rights and remedies under the Credit Agreement and the other Loan Documentsarising as a result of any actual or alleged breach of the terms of the Credit Agreement or other Loan Documents that may have occurred prior to the date of thisAmendment (a “Forbearance Default”); provided, however, that upon the occurrence of any Event of Default other than a Forbearance Default, Lender shall beentitled to exercise any and all of their rights and remedies under the Credit Agreement, the other Loan Documents and applicable law, without further noticeother than as required therein. 9. No Waiver. This Amendment does not constitute a waiver by Lender of Borrower’s compliance with any covenants, or a waiver of any Defaults orEvents of Default, under the Credit Agreement or any of the Loan Documents, and shall not entitle the Borrower to any amendments or waivers in the future. 10. Miscellaneous. Article VIII of the Credit Agreement is hereby incorporated by reference into this Amendment. 11. Condition to Effectiveness. The effectiveness of this Amendment is conditioned upon Borrower obtaining from all of the holders of its 8% SeniorSecured Debentures due February 14, 2014 extensions of the due date of such debentures until a date not earlier than May 16, 2014. Borrower has providedLender with evidence of its satisfaction of this condition, and Lender’s execution of this Amendment shall evidence Lender’s agreement that such condition hasbeen satisfied and that such evidence provided by Borrower is satisfactory to Lender. [Signature Pages Follow] 4 Borrower and Lender have executed this Fourth Amendment to Credit Agreement on April 15, 2013, effective as of the Effective Date first above written. HEXAGON, LLCBy: Hexagon, Inc., its Manager RECOVERY ENERGY, INC. By:/s/ Brian Fleishmann By:/s/ A. Bradley Gabbard Brian Fleischmann A. Bradley Gabbard Executive Vice President Chief Financial Officer 5Exhibit 10.59 FOURTH AMENDMENT TO CREDIT AGREEMENT(Third Credit Agreement) This FOURTH AMENDMENT TO CREDIT AGREEMENT (this “Amendment”), dated effective as of March 1, 2013 (the “Effective Date”), is betweenRecovery Energy, Inc., a Nevada corporation (“Borrower”), and Hexagon, LLC, a Colorado limited liability company, formerly known as HexagonInvestments, LLC (“Lender”). RECITALS A. Borrower and Lender have entered into a Credit Agreement, dated as of April 14, 2010 (as modified by (i) that certain Amendment toPromissory Note, dated December 29, 2010, (ii) that certain Second Amendment to Promissory Note, dated November 14, 2011, (iii) that certain Amendmentto Credit Agreement dated March 15, 2012, (iv) that certain Second Amendment to Credit Agreement dated July 31, 2012, (v) that certain Third Amendmentto Credit Agreement dated November 8, 2012, and as further amended, modified, supplemented, substituted or replaced, the “Credit Agreement”), providingfor a term loan in the original principal amount of $15,000,000. Defined terms used herein and not defined herein shall have the meanings set forth in theCredit Agreement. B. Borrower has asked Lender, and Lender has agreed to amend the terms and conditions of the Credit Agreement to extend the Maturity Dateuntil May 16, 2014, subject to and as more fully set forth in this Amendment. AGREEMENT In consideration of the foregoing and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Borrowerand Lender agree as follows: 1. Amendment to Credit Agreement. Effective as of the Effective Date and upon the terms and subject to the conditions set forth in this Amendment: (a) Section 1.1 of the Credit Agreement is hereby amended by deleting “December 31, 2013” in the definition of “Maturity Date” and replacingit with “May 16, 2014”. (b) Section 2.1(c) of the Credit Agreement is hereby deleted in its entirety and replaced with the following: “(c) The Loan shall bear interest at a rate of 15.00% per annum for all periods prior to March 1, 2013. For all periods commencingMarch 1, 2013 and thereafter, the Loan shall bear interest at a rate of 10.00% per annum.” (c) Section 2.2 of the Credit Agreement is hereby deleted in its entirety and replaced with the following: “Section 2.2 Mandatory Prepayments. Commencing with March, 2013, Borrower shall be required only to make payments of interestaccruing under the Loan for the months of March, April, May and June 2013, each such interest payment to be due for a particular monthon or before the last day of that month. Commencing with July, 2013, Borrower shall repay the Loan and any amounts due under theOther Credit Agreements (as defined below) with the greater of: (a) the sum of 100% of the Net Proceeds from the Oil and Gas Properties asdefined in the Credit Agreement plus 100% of the Net Proceeds from the Oil and Gas Properties as defined in the Credit Agreement datedJanuary 29, 2010 and the Credit Agreement dated March 25, 2010, each between Borrower and Lender (the “Other Credit Agreements”),and (b) either (i) $190,000 if a sale of the Palm Field (as described in Section 2.6(a) below) has closed on or before July 1, 2013 for a saleprice of $4,500,000 or such other price as is mutually agreed by Borrower and Lender, or (ii) $225,000 if the condition in clause (i) is notsatisfied. Such amounts paid under this Section 2.2 shall be applied to amounts due under the Loan and the amounts due under the OtherCredit Agreements in a manner as determined by Lender in its sole discretion.” 1 (d) Section 2.4 of the Credit Agreement is hereby amended by deleting "December 31, 2013" in the second line and replacing it with "May 16,2014". (e) Section 2.5 of the Credit Agreement is hereby amended by deleting Sections 2.5(b) and 2.5(c) in their entirety. (f) A new Section 2.6 of the Credit Agreement is hereby added as follows: “Section 2.6 Additional Equity and Development Covenants. Borrower agrees to use its reasonable best efforts to pursue the followingtransactions and other actions to improve the financial condition of Borrower: (a) A sale for cash on or before July 1, 2013 of all of Borrower’s oil and gas interests and wells in the Palm Field located in T. 17 N.,R. 58 W., Banner County, Nebraska, for a price that is mutually agreed by Borrower and Lender. All of the proceeds of any such saleshall be paid to Lender and shall reduce the amount outstanding under the Credit Agreement dated March 25, 2010 and, to the extent theproceeds exceed the amount outstanding under such Credit Agreement, the amounts due under this Credit Agreement or the Credit Agreementdated January 29, 2010, the allocation of which Lender shall determine in its sole discretion. (b) An equity offering or other transaction to provide additional equity for the Borrower, through an investment banking firm deemedby Borrower in its reasonable discretion to have suitable qualifications for such transaction. (c) One or more joint venture development agreements to develop the Borrower’s oil and gas assets with a financial or oil and gasindustry entity with suitable financial strength and technical expertise for the successful implementation of such development agreements. (d) Engineering study of Borrower’s producing oil and gas properties in the Wilke and State Line Fields (in Banner and KimballCounties, Nebraska and Laramie County, Wyoming) to ascertain possible operations to enhance production from such properties. 2 2. Other Agreements. (a) Borrower and Lender agree that all of the Loan Documents are hereby amended to reflect the amendments set forth herein andthat no further amendments to any Loan Documents are required to reflect the foregoing; and (b) all references in any document to “Credit Agreement” or any“Loan Document” shall refer to the Credit Agreement or any such Loan Document, as amended pursuant to this Amendment. 3. Representations and Warranties. Borrower hereby certifies to Lender that as of the date of this Amendment and as of the Effective Date (taking intoconsideration the transactions contemplated by this Amendment) all of Borrower’s representations and warranties contained in the Credit Agreement and eachof the Loan Documents are true, accurate and complete in all material respects. Without limiting the generality of the foregoing, Borrower represents andwarrants that (i) the execution and delivery of this Amendment has been authorized by all necessary action on the part of Borrower, (ii) the person executingthis Amendment on behalf of Borrower is duly authorized to do so, and (iii) this Amendment constitutes the legal, valid, binding and enforceable obligation ofBorrower. 4. Additional Documents. Borrower shall execute and deliver, and shall cause to be executed and delivered, to Lender at any time and from time totime such documents and instruments, including without limitation additional amendments to the Credit Agreement and the Loan Documents, as Lender mayreasonably request to confirm and carry out the transactions contemplated hereby or by any other Loan Documents executed in connection herewith. 5. Continuation of the Credit Agreement and Loan Documents. Except as specified in this Amendment, the provisions of the Credit Agreement and theLoan Documents shall remain in full force and effect, and if there is a conflict between the terms of this Amendment and those of the Credit Agreement or theLoan Documents, the terms of this Amendment shall control. This Amendment is a Loan Document. 6. Ratification and Reaffirmation of Obligations by Borrower. Borrower hereby (a) ratifies and confirms all of its Obligations under the CreditAgreement and each of the other Loan Documents, and acknowledges and agrees that such Obligations remain in full force and effect, and (b) ratifies,reaffirms and reapproves in favor of Lender the terms and provisions of the Credit Agreement and each of the other Loan Documents, including (withoutlimitation), its pledges and other grants of Liens and security interests pursuant to the Loan Documents. 7. Release and Indemnification. (a) Borrower hereby fully, finally, and forever releases and discharges Lender, and its successors, assigns, directors, officers, employees,agents and representatives, from any and all causes of action, claims, debts, demands and liabilities, of whatever kind or nature, in law or equity, ofBorrower, whether now known or unknown to Borrower in respect of (i) the Obligations under the Credit Agreement and each of the other Loan Documents or(ii) the actions or omissions of Lender in any manner related to the Obligations under the Credit Agreement and each of the other Loan Documents; providedthat this Section shall only apply to and be effective with respect to events or circumstances existing or occurring prior to and including the date of thisAmendment. 3 (b) Without limiting Section 7.3 of the Credit Agreement, Borrower hereby agrees to indemnify, defend, and hold harmless Lender and itssuccessors, assigns, directors, officers, employees, agents and representatives (each an “Indemnified Party” and collectively the “Indemnified Parties”) fromand against any and all accounts, covenants, agreements, obligations, claims, debts, liabilities, offsets, demands, costs, expenses, actions or causes of actionof every nature, character and description, whether arising at law or equity or under statute, regulation or otherwise, and whether liquidated or unliquidated,contingent or noncontingent, known or unknown, suspected or unsuspected (“Claims”), arising from or made under any legal theory, which any ofIndemnified Parties may incur as a direct or indirect consequence of or in relation to any acts or omissions of Borrower arising from or relating to any of: (i)the Credit Agreement; (ii) the Loan Documents; (iii) this Amendment; or (iv) any documents executed by Borrower in connection with thisAmendment. Should any Indemnified Party incur any such Claims, or defense of or response to any Claims or demand related thereto, the amount thereof,including costs, expenses and attorneys’ fees, shall be added to the amounts due under the Loan Documents, and shall be secured by any and all liens createdunder and pursuant to the Loan Documents. This indemnity shall survive until the Obligations have been indefeasibly paid in full and the termination,release or discharge of Borrower. To the extent permissible under applicable law, this indemnity shall not limit any other rights of indemnification,subrogation or assignment, whether explicit, implied, legal or equitable, that any Indemnified Party may have. 8. Forbearance. Lender hereby agrees to forbear from exercising its rights and remedies under the Credit Agreement and the other Loan Documentsarising as a result of any actual or alleged breach of the terms of the Credit Agreement or other Loan Documents that may have occurred prior to the date of thisAmendment (a “Forbearance Default”); provided, however, that upon the occurrence of any Event of Default other than a Forbearance Default, Lender shall beentitled to exercise any and all of their rights and remedies under the Credit Agreement, the other Loan Documents and applicable law, without further noticeother than as required therein. 9. No Waiver. This Amendment does not constitute a waiver by Lender of Borrower’s compliance with any covenants, or a waiver of any Defaults orEvents of Default, under the Credit Agreement or any of the Loan Documents, and shall not entitle the Borrower to any amendments or waivers in the future. 10. Miscellaneous. Article VIII of the Credit Agreement is hereby incorporated by reference into this Amendment. 11. Condition to Effectiveness. The effectiveness of this Amendment is conditioned upon Borrower obtaining from all of the holders of its 8% SeniorSecured Debentures due February 14, 2014 extensions of the due date of such debentures until a date not earlier than May 16, 2014. Borrower has providedLender with evidence of its satisfaction of this condition, and Lender’s execution of this Amendment shall evidence Lender’s agreement that such condition hasbeen satisfied and that such evidence provided by Borrower is satisfactory to Lender. [Signature Pages Follow] 4 Borrower and Lender have executed this Fourth Amendment to Credit Agreement on April __, 2013, effective as of the Effective Date first above written. HEXAGON, LLC RECOVERY ENERGY, INC. By: Hexagon, Inc., its Manager By: /s/ Brian Fleishmann By: /s/ A. Bradley Gabbard Brian Fleischmann A. Bradley Gabbard Executive Vice President Chief Financial Officer 5 Exhibit 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in the Registration Statement on Form S-3 (333-169070) and the Registration Statement on Form S-8 (RegistrationNo. 333-185122) of Recovery Energy, Inc. of our report dated April 17, 2013, relating to our audit of the consolidated financial statements included in theAnnual Report on Form 10-K of Recovery Energy, Inc. for the year ended December 31, 2012. /s/ HEIN & ASSOCIATES LLP Denver, ColoradoApril 17, 2013  Exhibit 23.2 April 17, 2013Recovery Energy, Inc.1900 Grant Street, Suite 720Denver, CO 80203Attention: A. Bradley GabbardDear Mr. Gabbard:Ralph E. Davis Associates, Inc. here by consents to the reference to our firm in the form and context in which they appear in the Annual Report onForm 10-K of Recovery Energy, Inc. for the year ended December 31, 2012 (the “Annual Report”). We hereby further consent to the inclusion in the AnnualReport of estimates of oil and gas reserves contained in our report dated April 3, 2013, and to the inclusion of our report as an exhibit to the Annual Report andin all current and future registration statements of the Company that incorporate by reference such Annual Report.Sincerely, RALPH E. DAVIS ASSOCIATES, INC. /s/ Allen C. Barron Allen C Barron, P.E.President Exhibit 31.1CERTIFICATION OF CHIEF EXECUTIVE OFFICERPURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TO SECTION 302 OFTHE SARBANES-OXLEY ACT OF 2002I, W. Phillip Marcum, certify that:1.I have reviewed this Form 10-K of Recovery Energy, Inc.; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have: a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles; c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b)Any fraud, whether or not material, that involved management or other employees who have a significant role in the registrant’s internal controlover financial reporting. By:/s/ W. Phillip Marcum W. Phillip Marcum Chief Executive Officer April 17, 2013   Exhibit 31.2 CERTIFICATION OF CHIEF FINANCIAL OFFICERPURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TO SECTION 302 OFTHE SARBANES-OXLEY ACT OF 2002I, A. Bradley Gabbard, certify that:1.I have reviewed this Form 10-K of Recovery Energy, Inc.; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have: a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles; c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and 5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b)Any fraud, whether or not material, that involved management or other employees who have a significant role in the registrant’s internal controlover financial reporting. By:/s/ A. Bradley Gabbard A. Bradley Gabbard Chief Financial Officer April 17, 2013  Exhibit 32.1OFFICER'S CERTIFICATIONPURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002(18 U.S.C 1350)The undersigned W. Phillip Marcum, the Chief Executive Officer of Recovery Energy, Inc., (the "Corporation"), in connection with the Corporation's YearlyReport on Form 10-K for the year ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), doeshereby represent, warrant and certify pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, as amended, that, to the best of his knowledge:1.The Report is in full compliance with the reporting requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Corporation. By:/s/ W. Phillip Marcum W. Phillip Marcum Chief Executive OfficerApril 17, 2013   Exhibit 32.2OFFICER'S CERTIFICATIONPURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002(18 U.S.C 1350)The undersigned A. Bradley Gabbard, the Chief Financial Officer of Recovery Energy, Inc., (the "Corporation"), in connection with the Corporation's YearlyReport on Form 10-K for the year ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), doeshereby represent, warrant and certify pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, as amended, that, to the best of his knowledge:1.The Report is in full compliance with the reporting requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Corporation. By:/s/ A. Bradley Gabbard A. Bradley Gabbard Chief Financial Officer April 17, 2013Exhibit 99.1 RECOVERY ENERGY COMPANY, INC.ESTIMATED RESERVESANDFUTURE NET REVENUEPROVED RESERVESAS OF DECEMBER 31, 2012 RALPH E. DAVIS ASSOCIATES, INC.HOUSTON, TEXAS 1 Table of Contents Table of Contents 2 RECOVERY ENERGY COMPANY, INC.Table of ContentsEngineering Letter Reserve Definitions Exhibits: I:Summary Economic Cash Flow Presentations II:Oneline Summary Well Information III:Oneline Summary Sorted by Reserve Category IV:Oneline Summary Sorted by Reserve Category, Ranked by PV 10% V:Proved Developed Producing Individual Wells for Producing Properties with Production Curves VI:Proved Undeveloped Individual Wells for Non-Producing Properties Qualifications 3 Engineering Letter Engineering Letter 4 April 3, 2013 Recovery Energy Company, Inc.1900 Grant Street, Suite 720Denver, Colorado 80203 Attn: Mr. A. Brad GabbardPresident & CFO Re: Estimated Reserves and Future Net Revenue,Recovery Energy Company, Inc.As of December 31, 2012Gentlemen:At the request of Recovery Energy Company, Inc. (“Recovery”), the firm of Ralph E. Davis Associates, Inc. (“Davis”) of Houston, Texas has prepared anestimate of the oil and natural gas reserves and future net revenue associated with specific leaseholds in which Recovery owns certain interests. The purpose ofthis report is to present a summary of the Proved Developed Producing and Undeveloped reserves, future production and income attributable to the subjectinterests as of the effective date of this report, December 31, 2012.Davis has reviewed 100% of Recovery’s proved developed and undeveloped properties located in the Denver Julesberg Basin of the United States. It is ouropinion that these properties represent all of Recovery’s assets that may be classified as proved as per the Securities and Exchange Commissiondirectives as detailed later in this report.The reserves associated with this review have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Part210—Form and Content of and Requirements for Financial Statements, Securities Act of 1933, Securities Exchange Act of 1934, Public Utility HoldingCompany Act of 1935, Investment Company Act of 1940, Investment Advisers Act of 1940, and Energy Policy and Conservation Act of 1975, under Rulesof General Application§ 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy andConservation Act of 1975. A summation of these definitions is included as a portion of this letter.We have also estimated the future net revenue and discounted present value associated with these reserves as of December 31, 2012 utilizing a scenario of non-escalated product prices as well as non-escalated costs of operations, i.e., prices and costs were not escalated above current values as detailed later in thisreport. The present value is presented for your information and should not be construed as an estimate of the fair market value. 5 Estimated Reserves and Future Net RevenueApril 3, 2013Recovery Energy Company, Inc.Page 2As of December 31, 2012 The results of our study related to our estimate of the Total Proved Reserves attributable to Recovery and remaining to be produced as of December 31,2012 are as follows:Non Escalated Pricing Scenario EstimatedReserves and Future Net Income Net toRecovery Energy Company, Inc.As of December 31, 2012 Estimated Net Reserves Estimated Future Net Cash Flow($1000) Reserve Category MBbls MMC F Undiscounted Discounted@ 10% Proved Reserves Producing 213.3 186.0 13,271.9 9,743.2 Undeveloped 137. 6 221. 3 9, 076. 9 5, 679. 0 Total Proved 350.9 407.3 22,348.9 15,422.1 Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil. Gas volumes are expressed in millions of standard cubic feet (MMSCF) atthe official temperature and pressure bases of the areas wherein the gas reserves are located.The economic cash flow presentation of the above volumes and revenues are presented for the individual reserve classifications, as well as appropriatesummaries, as Exhibit No. I. DISCUSSION:The scope of this study was to prepare an estimate of the proved reserves attributable to Recovery’s ownership position in the subjectproperties. Reserve estimates were prepared by Davis using acceptable evaluation principles for each source and were based in large part on the basicinformation supplied by Recovery.The quantities presented herein are estimated reserves of oil and natural gas volumes that geologicand engineering data demonstrate can be recovered from known reservoirs under current economic conditions with reasonable certainty. Provedundeveloped locations are scheduled to be drilled such that the investment cost will be fully recovered prior to recovery of the estimated reserve volume.This evaluation has been prepared in accordance with the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” asproclaimed by the Society of Petroleum Engineers, the SPE Standards. Texas Registered Engineering Firm F-1529 6 Estimated Reserves and Future Net RevenueApril 3, 2013Recovery Energy Company, Inc.Page 3As of December 31, 2012 The estimated future net revenue and discounted present value associated with the reserves as of December 31, 2012 were prepared utilizing a pricing scenariothat is detailed later in this report. Costs of operations were provided by Recovery or the operator of the properties on a well by well basis. These costs werereviewed by Davis and are considered to be reasonable. Capital costs were also provided by Recovery, including those future well stimulation costs anticipatedas necessary to recover estimated reserve volumes from existing wells. These costs were compared to actual costs of recently drilled wells, taking into accountdepth of the wells to be drilled. The capital costs included in this report are also considered to be reasonable. DATA SOURCEBasic well and field data used in the preparation of this report were furnished by Recovery or were obtained from commercial sources or from Davis’ owndatabase of information. Records as they pertain to factual matters such as acreage controlled the number and depths of wells, reservoir pressure andproduction history, the existence of contractual obligations to others and similar matters were accepted as presented.Additionally, the analyses of these properties utilized not only the basic data on the subject wellsbut also data on analogous properties as provided. Well logs, ownership interest, revenues received from the sale of products and operating costs werefurnished by Recovery Energy. No physical inspection of the properties was made nor any well tests conducted at this time. OWNERSHIPOwnership interests in the subject properties have been furnished by Recovery Energy and accepted by Davis without independent verification.RESERVE ESTIMATESThe estimate of reserves included in this report is based primarily upon production history or analogy with wells in the area producing from the same orsimilar formations. In addition to individual well production history, geological and well test information, when available, were utilized in theevaluation. Individual well production histories were evaluated utilizing decline curve analysis on the individual properties and forecast until a calculatedeconomic limit.Exhibit No. I is a summary presentation of the economic cash flow analyses for the various reserve categories. Exhibit’s II through IV are various one-linesummary presentations of the reserve categories and individual properties. Exhibit V is a presentation of the individual proved developed producing propertieswith production curves. Exhibit VI is a presentation by reserve category of the undrilled locations classified as proved undeveloped at this time.Estimates of reserves to be recovered from undrilled locations are based upon not only the ultimate reserve of existing Recovery wells, but also completions byother operators in the area of interest. Studies of analogous completions have resulted in the development of an average completion that can be anticipated for aspecific area, as well as a production profile that recovers the estimated ultimate reserve. This methodology has been utilized in this evaluation. Texas Registered Engineering Firm F-1529 7 Estimated Reserves and Future Net RevenueApril 3, 2013Recovery Energy Company, Inc.Page 4As of December 31, 2012 Additional development potential was based upon geological interpretations, seismic indications of individual structures and well log analysis of knowindicators of production. Well spacing was based upon historical activity in the same reservoirs in nearby fields. In all cases, proved undeveloped locationswere limited to a direct offset to a proved developed producing well or unit or successful well test in the same reservoir. Net interest reserve estimates of undrilled locations are based upon Recovery’s intention to secure industry financing to drill and complete each of the scheduledlocations. Recovery anticipates a proposed trade in which it will be carried through the completion phase, and be able to maintain twenty–five percent (25.0%)of its current leasehold working interest position. The company would pay its proportional share of any future associated well expense. This interest modelwas applied to all the undrilled locations scheduled within the reserve evaluation. Recovery has indicated that in addition to pursuing industry financing in order to drill locations as detailed above, the company is working on an alternativecapital infusion that could allow it to maintain a higher working interest position in the undrilled locations. With the exception of a single well location, thecompany holds a one hundred percent (100.0%) leasehold position in all the undrilled locations classified as proved for this evaluation. Consequently, asuccessful capital campaign could result in the company increasing its proved undeveloped reserves position by a factor of four (4).The accuracy of reserve estimates is dependent upon the quality of available data and upon the independent geological and engineering interpretation of thatdata. It should be noted that all reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recoveredwill be greater or less than the estimated quantities determined as of the date the estimate is made.The uncertainty depends primarily on the amount of reliable geological and engineering data available at the time of the estimate and the interpretation of thesedata. These reserves have been determined using methods and procedures widely accepted within the industry and are believed to be appropriate for thepurposes of this report. In our opinion, we used all methods and procedures necessary under the circumstances to prepare this report. PRODUCING RATESFor the purpose of this report, estimated reserves are scheduled for recovery primarily on the basis of actual producing rates or appropriate well testinformation. They were prepared giving consideration to engineering and geological data such as reservoir pressure, anticipated producing mechanisms, thenumber and types of completions, as well as past performance of analogous reservoirs.These and other future rates may be subject to regulation by various agencies, changes in market demand or other factors; consequently, reserves recoveredand the actual rates of recovery may vary from the estimates included herein. Scheduled dates of future well completions may vary from that provided byRecovery Energy due to changes in market demand or the availability of materials and/or capital; however, the timing of the wells and their estimated rates ofproduction are reasonable and consistent with established performance to date. Texas Registered Engineering Firm F-1529 8 Estimated Reserves and Future Net RevenueApril 3, 2013Recovery Energy Company, Inc.Page 5As of December 31, 2012 PRICING PROVISIONS AND DIFFERENTIALSPrices utilized in the evaluation results presented in the letter portion of this report and summarized in the various tables included in this evaluationwere furnished by Recovery. Prices received for products sold, adjustments due to the BTU content of the gas, shrinkage for transportation, measuring or theremoval of liquids, the liquid yield from gas processed, etc., were accepted as presented.The unit price used throughout this report for crude oil, condensate and natural gas is based upon the appropriate price in effect the first trading of each monthduring the previous twelve calendar months through December 2012, and averaged for the time period.Crude Oil and Condensate - The unit price used throughout this report for crude oil and condensate is based upon the average of prices for the previoustwelve months as indicated above. An average crude oil price for West Texas Intermediate crude of $95.01 per barrel was held constant throughoutthe producing life of the properties. A pricing differential from this posted price of -$7.64 was utilized to account for location and grade of crude based upon historical sales information for each producing property and was utilized inthis evaluation. This pricing differential was similarly held constant. Prices for liquid reserves scheduled for initial production at some future date wereestimated using current prices on the same properties.Natural Gas Liquids were priced at forty-four percent (44.0%) of the existing oil and condensate price for the State-Bradbury 13-36 well, the only property withNGL’s extracted from the production stream.Natural Gas - The unit price used throughout this report for natural gas is based upon the average of prices for previous twelve months as indicatedabove. An average gas price of $2.75 per MMBTU representing the Henry Hub natural gas price was held constant throughout the producing life of theproperties. Prices for gas reserves scheduled for initial production at some future date were estimated using this same price differential.FUTURE NET INCOMEFuture net income is based upon gross income from future production, less direct operating expenses and taxes (production, severance, ad valorem orother). Estimated future capital for development and work-over costs was also deducted from gross income at the time it will be expended. No allowance wasmade for depletion, depreciation, income taxes or administrative expense.Direct lease operating expense includes direct cost of operations of each lease or an estimated value for future operations based upon analogousproperties. Lease operating expense and/or capital costs for drilling and/or major work over expense were not escalated throughout the remaining producing lifeof the properties. Neither the cost to abandon properties nor the salvage value of equipment was considered in this report.Future net income has been discounted for present worth at values ranging from 0 to 100 percent using continuous discounting. In this report the future netincome is discounted at a primary rate of ten (10.0) percent.Texas Registered Engineering Firm F-1529 9 Estimated Reserves and Future Net RevenueApril 3, 2013Recovery Energy Company, Inc.Page 6As of December 31, 2012 GENERALRecovery Energy Company, Inc. has provided access to all of its accounts, records, geological and engineering data, reports and other information as requiredfor this evaluation. The ownership interests, product classifications relating to prices and other factual data were accepted as furnished withoutverification.No consideration was given in this report to either gas contract disputes including take or pay demands or gas sales imbalances.No consideration was given in this report to potential environmental liabilities which may exist, nor were any costs included for potential liability to restore andclean up damages, if any, caused by past operating practices.Neither Ralph E. Davis Associates, Inc. nor any of its employees have any interest in Recovery Energy Company, Inc. or any other related company or theproperties reported on herein. The employment and compensation to make this study are not contingent on our estimate of reserves. The technical personsresponsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forthin the SPE standards.This report has been prepared for public disclosure by Recovery Energy Company, Inc. in filings made with the SEC in accordance with the disclosurerequirements set forth in the SEC regulations.The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please feel free to contact usif we can be of further service.We appreciate the opportunity to be of service to you in the matter of this report and will be glad to address any questions or inquiries you may have. Very truly yours, RALPH E. DAVIS ASSOCIATES, INC. Date/s/ Allen C. Barron Allen C. Barron, P. E.President Texas Registered Engineering Firm F-1529 10 Reserves Definitions Reserves Definitions 11 Securities and Exchange CommissionDefinitions of Reserves The following information is taken from the United States Securities and Exchange Commission:PART 210—FORM AND CONTENT OF AND REQUIREMENTS FOR FINANCIAL STATEMENTS, SECURITIES ACT OF 1933, SECURITIESEXCHANGE ACT OF 1934, PUBLIC UTILITY HOLDING COMPANY ACT OF 1935, INVESTMENT COMPANY ACT OF 1940, INVESTMENTADVISERS ACT OF 1940, AND ENERGY POLICY AND CONSERVATION ACT OF 1975 Rules of General Application§ 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policyand Conservation Act of 1975.ReservesReserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by applicationof development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right toproduce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financingrequired to implement the project.Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated aseconomically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e.,absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resourcesfrom undiscovered accumulations). Proved Oil and Gas ReservesProved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonablecertainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, andgovernment regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or theoperator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes:(A) The area identified by drilling and limited by fluid contacts, if any, and(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producibleoil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetrationunless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, provedoil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technologyestablish the higher contact with reasonable certainty.(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) areincluded in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of aninstalled program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineeringanalysis on which the project or program was based; and(B) The project has been approved for development by all necessary parties and entities, including governmental entities.(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the averageprice during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon futureconditions. 12 Securities and Exchange CommissionPage 2§ 210.4-10 Definitions (of Reserves) Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. Ifprobabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degreeof confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological,geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is muchmore likely to increase or remain constant than to decrease. Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has beendemonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.Probable ReservesProbable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likelyas not to be recovered.(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plusprobable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed theproved plus probable reserves estimates.(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are lesscertain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may beassigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place thanassumed for proved reserves.Possible ReservesPossible reserves are those additional reserves that are less certain to be recovered than probable reserves.(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probableplus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equalor exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data areprogressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits ofcommercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recoveryquantities assumed for probable reserves.(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercialinterpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulationthat may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not beenpenetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reservesmay be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists foran associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact canbe established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may beassigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. 13 Securities and Exchange CommissionPage 3§ 210.4-10 Definitions (of Reserves) Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter Developed Oil and Gas ReservesDeveloped oil and gas reserves are reserves of any category that can be expected to be recovered:(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to thecost of a new well; and(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving awell.Undeveloped Oil and Gas ReservesUndeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wellswhere a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled,unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to bedrilled within five years, unless the specific circumstances, justify a longer time.(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or otherimproved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogousreservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.Additional Definitions:Deterministic EstimateThe method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economicdata) in the reserves calculation is used in the reserves estimation procedure.Probabilistic EstimateThe method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter(from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.Reasonable CertaintyIf deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods areused, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if thequantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical),engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remainconstant than to decrease. 14 ExhibitsExhibits 15 Summary Economic CashFlow Presentations Summary Economic Cash FlowPresentations 16 RECOVERY ENERGYDATE : 04/01/2013TOTAL PROVED TIME :13:51:46RESERVES AND REVENUES AS OF 12/31/2012DBS :DEMOREVISED EVALUATION AT 04/01 2013SETTINGS :RED_JAN13 SCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 12-2013 231.626 666.916 58.638 56.730 87.370 2.663 5123.214 151.064 5499.152 12-2014 253.286 418.070 60.764 44.795 87.370 2.673 5308.948 119.726 5628.631 12-2015 195.699 300.953 45.295 34.857 87.370 2.670 3957.449 93.051 4194.470 12-2016 141.213 225.092 31.229 26.216 87.370 2.668 2728.477 69.945 2902.081 12-2017 110.845 179.162 23.255 20.772 87.370 2.664 2031.774 55.337 2161.745 12-2018 100.679 176.656 20.694 22.788 87.370 2.649 1808.033 60.368 1922.137 12-2019 86.478 156.697 17.386 20.493 87.370 2.643 1519.007 54.173 1611.870 12-2020 73.515 131.640 14.410 16.710 87.370 2.641 1258.981 44.126 1330.964 12-2021 64.875 112.794 12.381 13.725 87.370 2.632 1081.771 36.124 1130.386 12-2022 57.081 98.232 10.565 11.432 87.370 2.621 923.069 29.968 953.037 12-2023 48.328 89.601 8.507 10.462 87.370 2.621 743.278 27.420 770.697 12-2024 41.975 82.397 7.139 9.650 87.370 2.620 623.771 25.289 649.059 12-2025 37.436 76.255 6.184 8.954 87.370 2.620 540.275 23.461 563.736 12-2026 33.341 70.789 5.319 8.248 87.370 2.619 464.699 21.601 486.300 12-2027 30.068 65.948 4.622 7.627 87.370 2.618 403.849 19.968 423.818 S TOT 1506.444 2851.204 326.389 313.460 87.370 2.653 28516.588 831.620 30228.084 AFTER 239.286 758.872 24.473 93.872 87.370 2.618 2138.204 245.743 2383.947 TOTAL 1745.730 3610.076 350.862 407.331 87.370 2.645 30654.793 1077.363 32612.031 AD VALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 309.640 212.932 833.119 0.000 0.000 76.875 4066.587 4066.587 3874.847 12-2014 276.401 204.064 885.503 0.000 0.000 250.000 4012.664 8079.251 7351.183 12-2015 205.810 150.373 694.740 0.000 0.000 0.000 3143.546 11222.798 9837.360 12-2016 144.167 100.344 483.240 0.000 0.000 0.000 2174.330 13397.128 11399.500 12-2017 109.907 73.183 355.071 0.000 0.000 0.000 1623.583 15020.712 12459.438 12-2018 102.703 58.795 351.494 0.000 0.000 218.750 1190.395 16211.106 13164.162 12-2019 86.620 48.037 344.519 0.000 0.000 0.000 1132.694 17343.801 13775.336 12-2020 70.835 39.685 333.864 0.000 0.000 0.000 886.579 18230.381 14210.047 12-2021 59.695 33.884 322.484 0.000 0.000 0.000 714.322 18944.701 14528.415 12-2022 50.382 28.777 301.996 0.000 0.000 0.000 571.881 19516.584 14760.247 12-2023 42.268 23.529 270.396 0.000 0.000 0.000 434.504 19951.088 14920.358 12-2024 37.233 19.525 246.196 0.000 0.000 0.000 346.105 20297.191 15036.246 12-2025 33.312 16.689 231.896 0.000 0.000 0.000 281.840 20579.031 15122.040 12-2026 29.566 14.277 210.327 0.000 0.000 0.000 232.129 20811.162 15186.274 12-2027 26.443 12.333 193.908 0.000 0.000 0.000 191.133 21002.297 15234.355 S TOT 1584.982 1036.429 6058.754 0.000 0.000 545.625 21002.297 21002.297 15234.355 AFTER 178.488 18.012 840.882 0.000 0.000 0.000 1346.564 22348.861 15422.130 TOTAL 1763.470 1054.441 6899.636 0.000 0.000 545.625 22348.859 22348.861 15422.130 OIL GAS P.W. % P.W., M$ GROSS WELLS 38.0 1.0 LIFE, YRS. 42.42 5.00 18110.877 GROSS ULT., MB & MMF 2461.803 4816.261 DISCOUNT % 10.00 8.00 16374.374 GROSS CUM., MB & MMF 716.073 1206.183 UNDISCOUNTED PAYOUT, YRS. 0.02 10.00 15422.128 GROSS RES., MB & MMF 1745.730 3610.077 DISCOUNTED PAYOUT, YRS. 0.02 12.00 14593.596 NET RES., MB & MMF 350.862 407.331 UNDISCOUNTED NET/INVEST. 41.96 15.00 13531.830 NET REVENUE, M$ 30654.793 1077.363 DISCOUNTED NET/INVEST. 37.50 18.00 12638.278 INITIAL PRICE, $ 87.370 2.634 RATE-OF-RETURN, PCT. 260.00 30.00 10119.967 INITIAL N.I., PCT. 40.176 5.931 INITIAL W.I., PCT. 26.632 60.00 7041.921 80.00 5976.986 260.00 3054.993 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 17 RECOVERY ENERGYDATE : 04/01/2013TOTAL PROVED TIME :13:51:46RESERVES AND REVENUES AS OF 12/31/2012DBS :DEMOREVISED EVALUATION AT 04/01 2013SETTINGS :RED_JAN13 SCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTION MMC NET OILPRODUCTIONMBBL NET GASPRODUCTION MMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 12-2013 197.939 638.405 51.927 50.921 87.370 2.668 4536.825 135.843 4897.542 12-2014 129.647 354.038 36.386 31.748 87.370 2.694 3179.041 85.544 3464.542 12-2015 95.000 239.715 25.459 22.380 87.370 2.697 2224.379 60.361 2428.709 12-2016 73.896 177.636 17.946 16.547 87.370 2.696 1567.923 44.612 1716.193 12-2017 60.615 138.560 13.331 12.499 87.370 2.693 1164.708 33.663 1273.004 12-2018 52.483 111.924 11.113 9.599 87.370 2.689 970.963 25.813 1050.512 12-2019 46.294 92.838 9.387 7.482 87.370 2.684 820.117 20.084 878.891 12-2020 41.396 78.672 8.015 5.917 87.370 2.679 700.229 15.850 743.937 12-2021 37.301 65.519 6.890 4.093 87.370 2.660 601.958 10.887 625.337 12-2022 33.758 54.960 5.917 2.615 87.370 2.626 516.941 6.868 523.809 12-2023 30.497 49.521 4.942 2.296 87.370 2.624 431.774 6.024 437.798 12-2024 27.904 45.014 4.338 2.033 87.370 2.622 379.027 5.332 384.359 12-2025 25.574 41.223 3.829 1.816 87.370 2.620 334.500 4.760 339.260 12-2026 23.412 37.871 3.351 1.541 87.370 2.614 292.789 4.028 296.817 12-2027 21.412 35.005 2.905 1.323 87.370 2.608 253.824 3.450 257.274 S TOT 897.129 2160.900 205.734 172.810 87.370 2.680 17974.994 463.119 19317.984 AFTER 155.559 362.971 7.572 13.207 87.370 2.605 661.588 34.401 695.989 TOTAL 1052.689 2523.871 213.306 186.017 87.370 2.675 18636.582 497.520 20013.975 AD VALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 282.191 202.694 804.669 0.000 0.000 76.875 3531.113 3531.113 3375.591 12-2014 198.328 142.352 769.203 0.000 0.000 0.000 2354.660 5885.773 5423.761 12-2015 142.456 98.852 556.440 0.000 0.000 0.000 1630.962 7516.734 6712.760 12-2016 103.171 68.054 344.940 0.000 0.000 0.000 1200.027 8716.762 7574.643 12-2017 79.236 50.150 216.771 0.000 0.000 0.000 926.846 9643.608 8179.603 12-2018 64.990 41.107 213.194 0.000 0.000 0.000 731.221 10374.829 8613.465 12-2019 54.182 34.206 210.619 0.000 0.000 0.000 579.884 10954.713 8926.246 12-2020 45.813 28.824 208.764 0.000 0.000 0.000 460.536 11415.249 9152.071 12-2021 38.143 24.552 197.384 0.000 0.000 0.000 365.258 11780.507 9314.891 12-2022 31.533 21.109 179.096 0.000 0.000 0.000 292.071 12072.578 9433.246 12-2023 26.198 18.301 159.596 0.000 0.000 0.000 233.703 12306.281 9519.340 12-2024 23.214 15.982 159.596 0.000 0.000 0.000 185.567 12491.848 9581.493 12-2025 20.689 14.047 159.596 0.000 0.000 0.000 144.928 12636.776 9625.629 12-2026 18.163 12.418 155.627 0.000 0.000 0.000 110.609 12747.385 9656.256 12-2027 15.968 10.923 148.008 0.000 0.000 0.000 82.375 12829.760 9676.997 S TOT 1144.273 783.573 4483.504 0.000 0.000 76.875 12829.760 12829.760 9676.997 AFTER 53.133 13.219 187.457 0.000 0.000 0.000 442.180 13271.939 9743.167 TOTAL 1197.406 796.792 4670.961 0.000 0.000 76.875 13271.940 13271.939 9743.167 OIL GAS P.W. % P.W., M$ GROSS WELLS 24.0 1.0 LIFE, YRS. 34.00 5.00 11160.462 GROSS ULT., MB & MMF 1768.762 3730.055 DISCOUNT % 10.00 8.00 10251.478 GROSS CUM., MB & MMF 716.073 1206.183 UNDISCOUNTED PAYOUT, YRS. 0.02 10.00 9743.169 GROSS RES., MB & MMF 1052.689 2523.872 DISCOUNTED PAYOUT, YRS. 0.02 12.00 9295.615 NET RES., MB & MMF 213.306 186.017 UNDISCOUNTED NET/INVEST. 173.64 15.00 8715.323 NET REVENUE, M$ 18636.578 497.520 DISCOUNTED NET/INVEST. 128.75 18.00 8221.428 INITIAL PRICE, $ 87.370 2.635 RATE-OF-RETURN, PCT. 260.00 30.00 6803.890 INITIAL N.I., PCT. 40.176 5.931 INITIAL W.I., PCT. 27.804 60.00 5016.243 80.00 4378.413 260.00 2520.648 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 18 RECOVERY ENERGYDATE : 04/01/2013TOTAL PROVED TIME :13:51:46RESERVES AND REVENUES AS OF 12/31/2012DBS :DEMOREVISED EVALUATION AT 04/01 2013SETTINGS :RED_JAN13 SCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 12-2013 33.687 28.512 6.712 5.809 87.370 2.620 586.390 15.220 601.610 12-2014 123.638 64.032 24.378 13.047 87.370 2.620 2129.907 34.182 2164.089 12-2015 100.698 61.238 19.836 12.477 87.370 2.620 1733.070 32.690 1765.760 12-2016 67.317 47.456 13.283 9.669 87.370 2.620 1160.554 25.333 1185.888 12-2017 50.230 40.602 9.924 8.273 87.370 2.620 867.067 21.674 888.741 12-2018 48.196 64.732 9.581 13.189 87.370 2.620 837.070 34.556 871.625 12-2019 40.184 63.859 7.999 13.011 87.370 2.620 698.889 34.090 732.979 12-2020 32.119 52.968 6.395 10.792 87.370 2.620 558.751 28.276 587.027 12-2021 27.573 47.275 5.492 9.632 87.370 2.620 479.812 25.237 505.049 12-2022 23.323 43.273 4.648 8.817 87.370 2.620 406.128 23.100 429.228 12-2023 17.831 40.080 3.565 8.166 87.370 2.620 311.504 21.395 332.900 12-2024 14.070 37.383 2.801 7.617 87.370 2.620 244.744 19.956 264.700 12-2025 11.862 35.032 2.355 7.138 87.370 2.620 205.774 18.701 224.475 12-2026 9.929 32.919 1.968 6.707 87.370 2.620 171.910 17.573 189.483 12-2027 8.656 30.943 1.717 6.305 87.370 2.620 150.025 16.518 166.543 S TOT 609.315 690.304 120.655 140.650 87.370 2.620 10541.596 368.502 10910.098 AFTER 83.726 395.901 16.901 80.665 87.370 2.620 1476.615 211.342 1687.958 TOTAL 693.041 1086.205 137.555 221.314 87.370 2.620 12018.211 579.844 12598.056 AD VALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 27.449 10.238 28.450 0.000 0.000 0.000 535.474 535.474 499.256 12-2014 78.074 61.712 116.300 0.000 0.000 250.000 1658.004 2193.478 1927.422 12-2015 63.354 51.522 138.300 0.000 0.000 0.000 1512.585 3706.062 3124.600 12-2016 40.996 32.289 138.300 0.000 0.000 0.000 974.303 4680.365 3824.857 12-2017 30.671 23.032 138.300 0.000 0.000 0.000 696.737 5377.102 4279.834 12-2018 37.713 17.688 138.300 0.000 0.000 218.750 459.173 5836.275 4550.696 12-2019 32.438 13.831 133.900 0.000 0.000 0.000 552.810 6389.085 4849.090 12-2020 25.023 10.861 125.100 0.000 0.000 0.000 426.043 6815.129 5057.976 12-2021 21.552 9.333 125.100 0.000 0.000 0.000 349.064 7164.193 5213.524 12-2022 18.849 7.668 122.900 0.000 0.000 0.000 279.811 7444.003 5327.001 12-2023 16.070 5.229 110.800 0.000 0.000 0.000 200.801 7644.804 5401.018 12-2024 14.019 3.543 86.600 0.000 0.000 0.000 160.538 7805.342 5454.753 12-2025 12.623 2.641 72.300 0.000 0.000 0.000 136.911 7942.253 5496.412 12-2026 11.403 1.859 54.700 0.000 0.000 0.000 121.520 8063.773 5530.018 12-2027 10.474 1.410 45.900 0.000 0.000 0.000 108.758 8172.532 5557.357 S TOT 440.709 252.856 1575.250 0.000 0.000 468.750 8172.532 8172.532 5557.357 AFTER 125.355 4.793 653.425 0.000 0.000 0.000 904.385 9076.917 5678.957 TOTAL 566.064 257.649 2228.675 0.000 0.000 468.750 9076.917 9076.917 5678.957 OIL GAS P.W. % P.W., MS GROSS WELLS 14.0 0.0 LIFE, YRS. 42.42 5.00 6950.415 GROSS ULT., MB & MMF 693.041 1086.205 DISCOUNT % 10.00 8.00 6122.896 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 5678.958 GROSS RES., MB & MMF 693.041 1086.205 DISCOUNTED PAYOUT, YRS. 0.00 12.00 5297.981 NET RES., MB & MMF 137.555 221.314 UNDISCOUNTED NET/INVEST. 20.36 15.00 4816.507 NET REVENUE, M$ 12018.210 579.844 DISCOUNTED NET/INVEST. 17.40 18.00 4416.851 INITIAL PRICE, $ 87.370 2.620 RATE-OF-RETURN, PCT. 260.00 30.00 3316.077 INITIAL N.I., PCT. 19.923 20.375 INITIAL W.I., PCT. 25.000 60.00 2025.678 80.00 1598.573 260.00 534.344 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 19 This Page Is Intentionally Left Blank 20 Well Information Oneline SummaryWell Information 21 REVISED AS OF APRIL 1, 2013 RECOVERY ENERGY, INC. REVISEDRESERVES AND REVENUES AS OF12/31/2012SORTED BY CATEGORY, STATE, FIELD, AND LEASE API RESERVECAT LEASE FIELD RESERVOIR OPERATOR COUNTY STATE MAJOR STARTDATE WI NRI PROVED DEVELOPED PRODUCING 05005071280000 1PDP STATE-BRADBURY 13-36 PEACE PIPE J SAND RECOVERY ENERGY, INC. ARAPAHOE CO GAS 3/1/2013 62.50000% 48.12500%05121083670000 1PDP LEO PEIPER #1&3 RED CLOUD J SAND RECOVERY ENERGY, INC. WASHINGTON CO OIL 2/1/2013 100.00000% 78.00000%05001088980000 1PDP CIMYOTTE #6-21 TRAPPER D SAND RECOVERY ENERGY, INC. ADAMS CO OIL 11/1/2012 94.50000% 77.08002%05123142720001 1PDP SAWYER 32-2 WATTENBERG J SAND RECOVERY ENERGY, INC. WELD CO OIL 11/1/2012 57.22250% 40.53555%05123346790000 1PDP SLW STATE PC BB18-65HN WATTENBERG NIOBRARA NOBLE ENERGY INC. WELD CO GAS 12/1/2012 7.90409% 6.91608%05123346740000 1PDP SLW STATE PC BB18-67HN WATTENBERG NIOBRARA NOBLE ENERGY INC. WELD CO GAS 12/1/2012 6.75559% 5.91114%05123352730000 1PDP VINCE STATE B13-63HN WATTENBERG NIOBRARA NOBLE ENERGY INC. WELD CO GAS 12/1/2012 2.20043% 1.92538%26007218980000 1PDP PALM 21A-20, 43-20, 23-21 ALBIN WEST J SAND RECOVERY ENERGY, INC. BANNER NE OIL 1/1/2013 100.00000% 82.50000%26007218870000 1PDP PALM EGLE 34-17 ALBIN WEST J SAND RECOVERY ENERGY, INC. BANNER NE OIL 1/1/2012 100.00000% 82.50000%26105226450000 1PDP LUKASSEN 14-34 CABLE J SAND RECOVERY ENERGY, INC. KIMBALL NE OIL 12/1/2012 100.00000% 78.00000%26105226250000 1PDP WILKE 34-5,33-5,24-5,23-5 DILL EAST J SAND RECOVERY ENERGY, INC. KIMBALL NE OIL 7/1/2012 87.50000% 68.25000%49021209410000 1PDP HANSON 42-26 GOLDEN PRARIE J SAND RECOVERY ENERGY, INC. LARAMIE WY OIL 1/1/2013 90.00000% 72.00000%49021207300000 1PDP ANDERSON 21-34 STATELINE J SAND RECOVERY ENERGY, INC. LARAMIE WY OIL 11/1/2012 74.00000% 56.98000%49021206080000 1PDP HOLGERSON 33A-33 STATELINE J SAND RECOVERY ENERGY, INC. LARAMIE WY OIL 11/1/2012 100.00000% 77.00000%49021206590000 1PDP MALM 42-34 STATELINE J SAND RECOVERY ENERGY, INC. LARAMIE WY OIL 10/1/2012 74.00001% 56.98000%49021205960000 1PDP OLIVERIUS 41-33 STATELINE J3 SAND RECOVERY ENERGY, INC. LARAMIE WY OIL 11/1/2012 100.00000% 76.99999%49021205940000 1PDP OLIVERIUS 42-33 STATELINE J1 SAND RECOVERY ENERGY, INC. LARAMIE WY OIL 10/1/2012 100.00000% 77.00000%49021205950000 1PDP WENZEL 12-34 STATELINE J SAND RECOVERY ENERGY, INC. LARAMIE WY OIL 1/1/2013 100.00000% 77.00000%49021209080000 1PDP FORNSTROM 33-32 WILDCAT J SAND EVERTSON OPERATING CO. INC. LARAMIE WY OIL 12/1/2012 0.00000% 2.60000%49021209290000 1PDP FORNSTROM 34A-32 WILDCAT J SAND EVERTSON OPERATING CO. INC. LARAMIE WY OIL 12/1/2012 0.00000% 2.60000%49021209060000 1PDP FORNSTROM 43-32 WILDCAT J SAND EVERTSON OPERATING CO. INC. LARAMIE WY OIL 12/1/2012 0.00000% 2.60000% PROVED UNDEVELOPED 3PUD LANG 11-34 WATTENBERG CODELL-NIOBRARA RECOVERY ENERGY, INC. WELD CO OIL 7/1/2013 25.00000% 20.37500% 3PUD LANG 12-34 WATTENBERG CODELL-NIOBRARA RECOVERY ENERGY, INC. WELD CO OIL 7/1/2013 25.00000% 20.37500% 3PUD LANG 21-34 WATTENBERG CODELL-NIOBRARA RECOVERY ENERGY, INC. WELD CO OIL 7/1/2013 25.00000% 20.37500% 3PUD LANG 22-34 WATTENBERG CODELL-NIOBRARA RECOVERY ENERGY, INC. WELD CO OIL 7/1/2013 25.00000% 20.37500% 3PUD LANG 2-2-34 WATTENBERG CODELL-NIOBRARA RECOVERY ENERGY, INC. WELD CO OIL 7/1/2013 25.00000% 20.37500% 3PUD PALM 11-20 ALBIN WEST J-SAND RECOVERY ENERGY, INC. BANNER NE OIL 7/1/2014 25.00000% 20.62500% 3PUD PALM 42-20 ALBIN WEST J-SAND RECOVERY ENERGY, INC. BANNER NE OIL 8/1/2013 25.00000% 20.62500% 3PUD LARSON 24-20 RANCHER J-Sand RECOVERY ENERGY, INC. KIMBALL NE OIL 3/1/2014 25.00000% 21.87500% 3PUD OLIVERIUS 32-33 STATELINE J-SAND RECOVERY ENERGY, INC. BANNER NE OIL 7/1/2014 25.00000% 19.25000% 3PUD VRTATKO 44-22 SURGE J1-SAND RECOVERY ENERGY, INC. KIMBALL NE OIL 3/1/2014 25.00000% 19.37500% 3PUD LUKASSEN 42-7 TERRESTRIAL WYKERT SAND RECOVERY ENERGY, INC. BANNER NE OIL 7/1/2013 25.00000% 18.75000% 3PUD LUKASSEN 44-18 TERRESTRIAL WYKERT SAND RECOVERY ENERGY, INC. BANNER NE OIL 7/1/2013 25.00000% 18.75000% 3PUD WILKE 44A-5 WILKE J-SAND RECOVERY ENERGY, INC. KIIMBALL NE OIL 5/1/2014 25.00000% 17.06250% 3PUD MALM 32-34 ALBIN WEST J-SAND RECOVERY ENERGY, INC. LARAMIE WY OIL 1/1/2014 25.00000% 19.75000% RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 22 Oneline SummarySorted by Reserve CAT Oneline SummarySorted by Reserve Category 23 REVISED AS OF APRIL 1, 2013 RECOVERY ENERGY, INC. REVISEDRESERVES AND REVENUES AS OF12/31/2012SORTED BY CATEGORY, STATE, FIELD, AND LEASE CASH FLOW RESERVE CAT FIELD LEASE COUNTY STATE NET OILRESERVESMBBLS NET GASRESERVESMMCF TOTALREVENUE M$ SEVERANCE TAXM$ AD VALTAXM$ DIRECTOPEXPENSEM$ TOTALOPEXPENSEM$ OPERATINGREVENUEM$ TOTAL INVESTMENT M$ UNDISC M$ DISC @10%M$ PROVED DEVELOPED PRODUCING 1PDP PEACE PIPE STATE-BRADBURY 13-36 ARAPAHOE CO 1.5 76.3 1,217.4 - 121.7 327.4 449.1 768.3 46.9 721.4 581.6 1PDP RED CLOUD LEO PEIPER #1&3 WASHINGTON CO 5.0 - 432.8 - 34.6 228.2 262.8 170.0 30.0 140.0 100.2 1PDP TRAPPER CIMYOTTE #6-21 ADAMS CO 6.5 17.1 610.5 - 54.9 107.2 162.1 448.4 - 448.4 336.1 1PDP WATTENBERG SAWYER 32-2 WELD CO 4.5 6.5 411.2 - 32.9 93.7 126.6 284.6 - 284.6 152.9 1PDP WATTENBERG SLW STATE PC BB18-65HN WELD CO 11.0 42.9 1,069.8 - 85.6 44.0 129.6 940.2 - 940.2 557.8 1PDP WATTENBERG SLW STATE PC BB18-67HN WELD CO 8.7 31.7 839.0 - 67.1 35.2 102.3 736.7 - 736.7 439.3 1PDP WATTENBERG VINCE STATE B13-63HN WELD CO 2.7 11.6 263.4 - 21.1 12.0 33.1 230.4 - 230.4 132.1 1PDP ALBIN WEST PALM 21A-20, 43-20, 23-21 BANNER NE 10.1 - 881.3 26.4 17.1 404.8 448.3 432.9 - 432.9 392.5 1PDP ALBIN WEST PALM EGLE 34-17 BANNER NE 37.7 - 3,295.0 98.8 63.9 653.4 816.1 2,478.8 - 2,478.8 1,799.6 1PDP CABLE LUKASSEN 14-34 KIMBALL NE 3.1 - 266.7 8.0 5.2 162.8 176.0 90.7 - 90.7 83.3 1PDP DILL EAST WILKE 34-5,33-5,24-5,23-5 KIMBALL NE 7.8 - 677.2 20.3 13.1 415.8 449.3 227.9 - 227.9 214.1 1PDP GOLDEN PRARIE HANSON 42-26 LARAMIE WY 35.4 - 3,093.1 198.0 209.3 772.2 1,179.5 1,913.6 - 1,913.6 1,419.5 1PDP STATELINE ANDERSON 21-34 LARAMIE WY 0.4 - 38.4 2.5 2.6 26.0 31.1 7.3 - 7.3 7.1 1PDP STATELINE HOLGERSON 33A-33 LARAMIE WY 4.2 - 365.8 23.4 24.8 189.2 237.4 128.5 - 128.5 117.1 1PDP STATELINE MALM 42-34 LARAMIE WY 1.2 - 104.9 6.7 7.1 68.4 82.2 22.7 - 22.7 21.6 1PDP STATELINE OLIVERIUS 41-33 LARAMIE WY 2.3 - 202.7 13.0 13.7 123.2 149.9 52.8 - 52.8 49.5 1PDP STATELINE OLIVERIUS 42-33 LARAMIE WY 4.1 - 361.0 23.1 24.4 158.4 205.9 155.0 - 155.0 143.4 1PDP STATELINE WENZEL 12-34 LARAMIE WY 61.0 - 5,325.9 340.9 360.4 849.2 1,550.5 3,775.4 - 3,775.4 2,888.7 1PDP WILDCAT FORNSTROM 33-32 LARAMIE WY 1.3 - 117.3 7.5 7.9 - 15.5 101.9 - 101.9 68.0 1PDP WILDCAT FORNSTROM 34A-32 LARAMIE WY 3.4 - 297.1 19.0 20.1 - 39.1 258.0 - 258.0 157.9 1PDP WILDCAT FORNSTROM 43-32 LARAMIE WY 1.6 - 143.6 9.2 9.7 - 18.9 124.7 - 124.7 80.9 SUB TOTAL: PDP 213.3 186.0 20,014.0 796.8 1,197.4 4,671.0 6,665.2 13,348.8 76.9 13,271.9 9,743.2 PROVED UNDEVELOPED 3PUD WATTENBERG LANG 11-34 WELD CO 9.6 44.3 954.4 - 76.4 163.5 239.8 714.6 93.8 620.8 277.9 3PUD WATTENBERG LANG 12-34 WELD CO 9.6 44.3 954.4 - 76.4 163.5 239.8 714.6 93.8 620.8 277.9 3PUD WATTENBERG LANG 21-34 WELD CO 9.6 44.3 954.4 - 76.4 163.5 239.8 714.6 93.8 620.8 277.9 3PUD WATTENBERG LANG 22-34 WELD CO 9.6 44.3 954.4 - 76.4 163.5 239.8 714.6 93.8 620.8 277.9 3PUD WATTENBERG LANG 2-2-34 WELD CO 9.6 44.3 954.4 - 76.4 163.5 239.8 714.6 93.8 620.8 277.9 3PUD ALBIN WEST PALM 11-20 BANNER NE 10.8 - 940.6 28.2 18.2 143.0 189.5 751.2 - 751.2 545.0 3PUD ALBIN WEST PALM 42-20 BANNER NE 12.0 - 1,045.2 31.4 20.3 159.5 211.1 834.0 - 834.0 649.0 3PUD RANCHER LARSON 24-20 KIMBALL NE 9.7 - 851.7 25.6 16.5 130.9 173.0 678.7 - 678.7 462.2 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 24 REVISED AS OF APRIL 1, 2013 RECOVERY ENERGY, INC. REVISEDRESERVES AND REVENUES AS OF12/31/2012SORTED BY CATEGORY, STATE, FIELD, AND LEASE CASH FLOW RESERVECAT FIELD LEASE COUNTY STATE NET OILRESERVESMBBLS NET GASRESERVESMMCF TOTALREVENUEM$ SEVERANCETAX M$ ADVALTAX M$ DIRECTOPEXPENSEM$ TOTALOPEXPENSEM$ OPERATINGREVENUEM$ TOTALINVESTMENTM$ UNDISCM$ DISC @10% M$ 3PUD STATELINE OLIVERIUS 32-33 BANNER NE 7.7 - 672.7 43.1 45.5 68.2 156.8 515.9 - 515.9 407.9 3PUD SURGE VRTATKO 44-22 KIMBALL NE 8.6 - 752.2 22.6 14.6 128.7 165.9 586.4 - 586.4 400.8 3PUD TERRESTRIAL LUKASSEN 42-7 BANNER NE 10.6 - 923.4 27.7 17.9 250.8 296.4 627.0 - 627.0 411.0 3PUD TERRESTRIAL LUKASSEN 44-18 BANNER NE 10.6 - 923.4 27.7 17.9 250.8 296.4 627.0 - 627.0 411.0 3PUD WILKE WILKE 44A-5 KIIMBALL NE 7.7 - 670.8 20.1 13.0 112.2 145.3 525.5 - 525.5 392.3 3PUD ALBIN WEST MALM 32-34 LARAMIE WY 12.0 - 1,045.9 31.4 20.3 167.2 218.9 827.0 - 827.0 610.2 SUB TOTAL: PUD 137.6 221.3 12,598.1 257.6 566.1 2,228.7 3,052.4 9,545.7 468.8 9,076.9 5,679.0 TOTAL PROVED 350.9 407.3 32,612.0 1,054.4 1,763.5 6,899.6 9,717.5 18,380.7 545.6 22,348.9 15,422.1 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 25 Oneline SummaryRanked by PV 10% Oneline Summary Sorted byReserve Cateogory, Ranked by PV 10% 26 REVISED AS OF APRIL 1, 2013 RECOVERY ENERGY, INC. REVISEDRESERVES AND REVENUES AS OF12/31/2012SORTED BY CATEGORY AND RANKED BY PV 10 CASH FLOW RESERVE CAT STATE LEASE COUNTY FIELD GROSS OILRESERVESMBBLS GROSS GASRESERVESMMCF NET OILRESERVESMBBLS NET GASRESERVESMMCF TOTALREVENUEM$ SEVERANCETAXM$ ADVALTAXM$ DIRECTOPEXPENSEM$ TOTALOPEXPENSEM$ OPERATINGREVENUEM$ TOTALINVESTMENTM$ UNDISC M$ DISC @10% M$ PROVED DEVELOPED PRODUCING 1PDP WY LARAMIE STATELINE WENZEL 12-34 79.2 - 61.0 - 5,325.9 340.9 360.4 849.2 1,550.5 3,775.4 - 3,775.4 2,888.7 1PDP NE BANNER ALBIN WEST PALM EGLE 34-17 45.7 - 37.7 - 3,295.0 98.8 63.9 653.4 816.1 2,478.8 - 2,478.8 1,799.6 1PDP WY LARAMIE GOLDEN PRARIE HANSON42-26 49.2 - 35.4 - 3,093.1 198.0 209.3 772.2 1,179.5 1,913.6 - 1,913.6 1,419.5 1PDP CO ARAPAHOE PEACE PIPE STATE-BRADBURY 13-36 3.0 273.3 1.5 76.3 1,217.4 - 121.7 327.4 449.1 768.3 46.9 721.4 581.6 1PDP CO WELD WATTENBERG SLW STATE PC BB18-65HN 200.5 783.2 11.0 42.9 1,069.8 - 85.6 44.0 129.6 940.2 - 940.2 557.8 1PDP CO WELD WATTENBERG SLW STATE PC BB18-67HN 185.8 680.0 8.7 31.7 839.0 - 67.1 35.2 102.3 736.7 - 736.7 439.3 1PDP NE BANNER ALBIN WEST PALM 21A-20, 43-20, 23-21 12.2 - 10.1 - 881.3 26.4 17.1 404.8 448.3 432.9 - 432.9 392.5 1PDP CO ADAMS TRAPPER CIMYOTTE #6-21 8.4 22.2 6.5 17.1 610.5 - 54.9 107.2 162.1 448.4 - 448.4 336.1 1PDP NE KIMBALL DILL EAST WILKE 34-5,33-5,24-5,23-5 11.4 - 7.8 - 677.2 20.3 13.1 415.8 449.3 227.9 - 227.9 214.1 1PDP WY LARAMIE WILDCAT FORNSTROM 34A-32 130.8 - 3.4 - 297.1 19.0 20.1 - 39.1 258.0 - 258.0 157.9 1PDP CO WELD WATTENBERG SAWYER 32-2 11.1 16.0 4.5 6.5 411.2 - 32.9 93.7 126.6 284.6 - 284.6 152.9 1PDP WY LARAMIE STATELINE OLIVERIUS42-33 5.4 - 4.1 - 361.0 23.1 24.4 158.4 205.9 155.0 - 155.0 143.4 1PDP CO WELD WATTENBERG VINCE STATE B13-63HN 173.6 749.1 2.7 11.6 263.4 - 21.1 12.0 33.1 230.4 - 230.4 132.1 1PDP WY LARAMIE STATELINE HOLGERSON 33A-33 5.4 - 4.2 - 365.8 23.4 24.8 189.2 237.4 128.5 - 128.5 117.1 1PDP CO WASHINGTON RED CLOUD LEO PEIPER #1&3 6.4 - 5.0 - 432.8 - 34.6 228.2 262.8 170.0 30.0 140.0 100.2 1PDP NE KIMBALL CABLE LUKASSEN 14-34 3.9 - 3.1 - 266.7 8.0 5.2 162.8 176.0 90.7 - 90.7 83.3 1PDP WY LARAMIE WILDCAT FORNSTROM 43-32 63.2 - 1.6 - 143.6 9.2 9.7 - 18.9 124.7 - 124.7 80.9 1PDP WY LARAMIE WILDCAT FORNSTROM 33-32 51.7 - 1.3 - 117.3 7.5 7.9 - 15.5 101.9 - 101.9 68.0 1PDP WY LARAMIE STATELINE OLIVERIUS41-33 3.0 - 2.3 - 202.7 13.0 13.7 123.2 149.9 52.8 - 52.8 49.5 1PDP WY LARAMIE STATELINE MALM 42-34 2.1 - 1.2 - 104.9 6.7 7.1 68.4 82.2 22.7 - 22.7 21.6 1PDP WY LARAMIE STATELINE ANDERSON 21-34 0.8 - 0.4 - 38.4 2.5 2.6 26.0 31.1 7.3 - 7.3 7.1 SUB TOTAL: PDP 1,052.7 2,523.9 213.3 186.0 20,014.0 796.8 1,197.4 4,671.0 6,665.2 13,348.8 76.9 13,271.9 9,743.2 PROVED UNDEVELOPED 3PUD NE BANNER ALBIN WEST PALM 42-20 58.0 - 12.0 - 1,045.2 31.4 20.3 159.5 211.1 834.0 - 834.0 649.0 3PUD WY LARAMIE ALBIN WEST MALM 32-34 60.6 - 12.0 - 1,045.9 31.4 20.3 167.2 218.9 827.0 - 827.0 610.2 3PUD NE BANNER ALBIN WEST PALM 11-20 52.2 - 10.8 - 940.6 28.2 18.2 143.0 189.5 751.2 - 751.2 545.0 3PUD NE KIMBALL RANCHER LARSON 24-20 44.6 - 9.7 - 851.7 25.6 16.5 130.9 173.0 678.7 - 678.7 462.2 3PUD NE BANNER TERRESTRIAL LUKASSEN 42-7 56.4 - 10.6 - 923.4 27.7 17.9 250.8 296.4 627.0 - 627.0 411.0 3PUD NE BANNER TERRESTRIAL LUKASSEN44-18 56.4 - 10.6 - 923.4 27.7 17.9 250.8 296.4 627.0 - 627.0 411.0 3PUD NE BANNER STATELINE OLIVERIUS 32-33 40.0 - 7.7 - 672.7 43.1 45.5 68.2 156.8 515.9 - 515.9 407.9 3PUD NE KIMBALL SURGE VRTATKO 44-22 44.4 - 8.6 - 752.2 22.6 14.6 128.7 165.9 586.4 - 586.4 400.8 3PUD NE KIIMBALL WILKE WILKE 44A-5 45.0 - 7.7 - 670.8 20.1 13.0 112.2 145.3 525.5 - 525.5 392.3 3PUD CO WELD WATTENBERG LANG 11-34 47.1 217.2 9.6 44.3 954.4 - 76.4 163.5 239.8 714.6 93.8 620.8 277.9 3PUD CO WELD WATTENBERG LANG 12-34 47.1 217.2 9.6 44.3 954.4 - 76.4 163.5 239.8 714.6 93.8 620.8 277.9 3PUD CO WELD WATTENBERG LANG 21-34 47.1 217.2 9.6 44.3 954.4 - 76.4 163.5 239.8 714.6 93.8 620.8 277.9 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 27 REVISED AS OF APRIL 1, 2013 RECOVERY ENERGY, INC. REVISEDRESERVES AND REVENUES AS OF12/31/2012SORTED BY CATEGORY AND RANKED BY PV 10 GROSS OIL GROSSGAS NET OIL NET GAS TOTAL SEVERANCE AD VAL DIRECT TOTAL OPERATING TOTAL CASH FLOW RESERVES RESERVES RESERVES RESERVES REVENUE TAX TAX OP EXPENSE OPEXPENSE REVENUE INVESTMENT UNDISC DISC @ 10%RESERVE CAT STATE LEASE COUNTY FIELD MBBLS MMCF MBBLS MMCF M$ M$ M$ M$ M$ M$ M$ M$ M$ 3PUD CO WELD WATTENBERG LANG 2-2-34 47.1 217.2 9.6 44.3 954.4 - 76.4 163.5 239.8 714.6 93.8 620.8 277.93PUD CO WELD WATTENBERG LANG 22-34 47.1 217.2 9.6 44.3 954.4 - 76.4 163.5 239.8 714.6 93.8 620.8 277.9SUB TOTAL: PUD 693.0 1,086.2 137.6 221.3 12,598.1 257.6 566.1 2,228.7 3,052.4 9,545.7 468.8 9,076.9 5,679.0TOTAL PROVED 1,745.7 3,610.1 350.9 407.3 32,612.0 1,054.4 1,763.5 6,899.6 9,717.5 18,380.7 545.6 22,348.9 15,422.1 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 28 Proved Developed Producing Proved Developed ProducingIndividual Wells for ProducingProperties w/ Production Curves 29 RECOVERY ENERGYDATE: 04/01/2013PROVED DEVELOPED PRODUCINGTIME: 14:03:13RESERVES AND REVENUES AS OF 12/3DBS: DEMOREVISED EVALUATION AT 03/28 2013SETTINGS: RED_JAN 13 SCENARIO: RED_JAN 13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 12-2013 197.939 638.405 51.927 50.921 87.370 2.668 4536.825 135.843 4897.542 12-2014 129.647 354.038 36.386 31.748 87.370 2.694 3179.041 85.544 3464.542 12-2015 95.000 239.715 25.459 22.380 87.370 2.697 2224.379 60.361 2428.709 12-2016 73.896 177.636 17.946 16.547 87.370 2.696 1567.923 44.612 1716.193 12-2017 60.615 138.560 13.331 12.499 87.370 2.693 1164.708 33.663 1273.004 12-2018 52.483 111.924 11.113 9.599 87.370 2.689 970.963 25.813 1050.512 12-2019 46.294 92.838 9.387 7.482 87.370 2.684 820.117 20.084 878.891 12-2020 41.396 78.672 8.015 5.917 87.370 2.679 700.229 15.850 743.937 12-2021 37.301 65.519 6.890 4.093 87.370 2.660 601.958 10.887 625.337 12-2022 33.758 54.960 5.917 2.615 87.370 2.626 516.941 6.868 523.809 12-2023 30.497 49.521 4.942 2.296 87.370 2.624 431.774 6.024 437.798 12-2024 27.904 45.014 4.338 2.033 87.370 2.622 379.027 5.332 384.359 12-2025 25.574 41.223 3.829 1.816 87.370 2.620 334.500 4.760 339.260 12-2026 23.412 37.871 3.351 1.541 87.370 2.614 292.789 4.028 296.817 12-2027 21.412 35.005 2.905 1.323 87.370 2.608 253.824 3.450 257.274 S TOT 897.129 2160.900 205.734 172.810 87.370 2.680 17974.994 463.119 19317.984 AFTER 155.559 362.971 7.572 13.207 87.370 2.605 661.588 34.401 695.989 TOTAL 1052.689 2523.871 213.306 186.017 87.370 2.675 18636.582 497.520 20013.975 AD VALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 282.191 202.694 804.669 0.000 0.000 76.875 3531.113 3531.113 3375.591 12-2014 198.328 142.352 769.203 0.000 0.000 0.000 2354.660 5885.773 5423.761 12-2015 142.456 98.852 556.440 0.000 0.000 0.000 1630.962 7516.734 6712.760 12-2016 103.171 68.054 344.940 0.000 0.000 0.000 1200.027 8716.762 7574.643 12-2017 79.236 50.150 216.771 0.000 0.000 0.000 926.846 9643.608 8179.603 12-2018 64.990 41.107 213.194 0.000 0.000 0.000 731.221 10374.829 8613.465 12-2019 54.182 34.206 210.619 0.000 0.000 0.000 579.884 10954.713 8926.246 12-2020 45.813 28.824 208.764 0.000 0.000 0.000 460.536 11415.249 9152.071 12-2021 38.143 24.552 197.384 0.000 0.000 0.000 365.258 11780.507 9314.891 12-2022 31.533 21.109 179.096 0.000 0.000 0.000 292.071 12072.578 9433.246 12-2023 26.198 18.301 159.596 0.000 0.000 0.000 233.703 12306.281 9519.340 12-2024 23.214 15.982 159.596 0.000 0.000 0.000 185.567 12491.848 9581.493 12-2025 20.689 14.047 159.596 0.000 0.000 0.000 144.928 12636.776 9625.629 12-2026 18.163 12.418 155.627 0.000 0.000 0.000 110.609 12747.385 9656.256 12-2027 15.968 10.923 148.008 0.000 0.000 0.000 82.375 12829.760 9676.997 S TOT 1144.273 783.573 4483.504 0.000 0.000 76.875 12829.760 12829.760 9676.997 AFTER 53.133 13.219 187.457 0.000 0.000 0.000 442.180 13271.939 9743.167 TOTAL 1197.406 796.792 4670.961 0.000 0.000 76.875 13271.940 13271.939 9743.167 OIL GAS P.W. % P.W., M$ GROSS WELLS 24.0 1.0 LIFE, YRS. 34.00 5.00 11160.462 GROSS ULT., MB & MMF 1768.762 3730.055 DISCOUNT % 10.00 8.00 10251.478 GROSS CUM., MB & MMF 716.073 1206.183 UNDISCOUNTED PAYOUT, YRS. 0.02 10.00 9743.169 GROSS RES., MB & MMF 1052.689 2523.872 DISCOUNTED PAYOUT, YRS. 0.02 12.00 9295.615 NET RES., MB & MMF 213.306 186.017 UNDISCOUNTED NET/INVEST. 173.64 15.00 8715.323 NET REVENUE, M$ 18636.578 497.520 DISCOUNTED NET/INVEST. 128.75 18.00 8221.428 INITIAL PRICE, $ 87.370 2.635 RATE-OF-RETURN, PCT. 260.00 30.00 6803.890 INITIAL N.I., PCT. 40.176 5.931 INITIAL W.I., PCT. 27.804 60.00 5016.243 80.00 4378.413 260.00 2520.648 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 30 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 31 STATE-BRADBURY 13-36DATE: 04/01/2013FIELD: PEACE PIPETIME: 14:03:09COUNTY: ARAPAHOE STATE: CODBS: DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS: RED_JAN 131PDPSCENARIO: RED_JAN 13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 12-2013 0.776 69.860 0.374 19.500 87.370 2.750 32.640 53.624 311.138 12-2014 0.690 62.119 0.332 17.339 87.370 2.750 29.024 47.682 276.663 12-2015 0.497 44.726 0.239 12.484 87.370 2.750 20.897 34.331 199.198 12-2016 0.358 32.203 0.172 8.989 87.370 2.750 15.046 24.718 143.422 12-2017 0.258 23.186 0.124 6.472 87.370 2.750 10.833 17.797 103.264 12-2018 0.186 16.694 0.089 4.660 87.370 2.750 7.800 12.814 74.350 12-2019 0.134 12.020 0.064 3.355 87.370 2.750 5.616 9.226 53.532 12-2020 0.096 8.654 0.046 2.416 87.370 2.750 4.043 6.643 38.543 12-2021 0.043 3.881 0.021 1.083 87.370 2.750 1.813 2.979 17.283 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT 3.037 273.341 1.462 76.296 87.370 2.750 127.712 209.815 1217.395 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 TOTAL 3.037 273.341 1.462 76.296 87.370 2.750 127.712 209.815 1217.395 AD VALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 31.114 0.000 55.993 0.000 0.000 46.875 177.157 177.157 165.876 12-2014 27.666 0.000 55.228 0.000 0.000 0.000 193.769 370.926 334.378 12-2015 19.920 0.000 45.644 0.000 0.000 0.000 133.634 504.560 440.034 12-2016 14.342 0.000 38.744 0.000 0.000 0.000 90.336 594.897 504.978 12-2017 10.326 0.000 33.775 0.000 0.000 0.000 59.162 654.059 543.655 12-2018 7.435 0.000 30.198 0.000 0.000 0.000 36.717 690.776 565.489 12-2019 5.353 0.000 27.623 0.000 0.000 0.000 20.556 711.332 576.615 12-2020 3.854 0.000 25.768 0.000 0.000 0.000 8.920 720.252 581.019 12-2021 1.728 0.000 14.388 0.000 0.000 0.000 1.167 721.419 581.554 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT 121.739 0.000 327.361 0.000 0.000 46.875 721.419 721.419 581.554 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 721.419 581.554 TOTAL 121.739 0.000 327.361 0.000 0.000 46.875 721.419 721.419 581.554 OIL GAS P.W. % P.W., M$ GROSS WELLS 0.0 1.0 LIFE, YRS. 8.58 5.00 644.172 GROSS ULT., MB & MMF 5.869 517.569 DISCOUNT % 10.00 8.00 605.105 GROSS CUM., MB & MMF 2.832 244.228 UNDISCOUNTED PAYOUT, YRS. 0.21 10.00 581.554 GROSS RES., MB & MMF 3.037 273.341 DISCOUNTED PAYOUT, YRS. 0.22 12.00 559.752 NET RES., MB & MMF 1.462 76.296 UNDISCOUNTED NET/INVEST. 16.39 15.00 529.948 NET REVENUE, M$ 127.712 209.815 DISCOUNTED NET/INVEST. 13.51 18.00 503.173 INITIAL PRICE, $ 87.370 2.750 RATE-OF-RETURN, PCT. 260.00 30.00 418.930 INITIAL N.I., PCT. 48.125 48.125 INITIAL W.I., PCT. 62.500 60.00 297.543 80.00 250.833 260.00 110.800 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 32 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 33 LEO PEIPER #1&3DATE: 04/01/2013FIELD: RED CLOUDTIME: 14:03:09COUNTY: WASHINGTON STATE: CODBS: DEMOOPERATOR : RECOVERY ENERGY INCORSETTINGS: RED_JAN 131PDPSCENARIO: RED_JAN 13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 12-2013 0.911 0.000 0.711 0.000 87.370 0.000 62.085 0.000 62.085 12-2014 0.898 0.000 0.701 0.000 87.370 0.000 61.221 0.000 61.221 12-2015 0.808 0.000 0.631 0.000 87.370 0.000 55.092 0.000 55.092 12-2016 0.727 0.000 0.567 0.000 87.370 0.000 49.576 0.000 49.576 12-2017 0.655 0.000 0.511 0.000 87.370 0.000 44.612 0.000 44.612 12-2018 0.589 0.000 0.459 0.000 87.370 0.000 40.146 0.000 40.146 12-2019 0.530 0.000 0.413 0.000 87.370 0.000 36.126 0.000 36.126 12-2020 0.477 0.000 0.372 0.000 87.370 0.000 32.509 0.000 32.509 12-2021 0.429 0.000 0.335 0.000 87.370 0.000 29.254 0.000 29.254 12-2022 0.325 0.000 0.253 0.000 87.370 0.000 22.128 0.000 22.128 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT 6.350 0.000 4.953 0.000 87.370 0.000 432.751 0.000 432.751 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 TOTAL 6.350 0.000 4.953 0.000 87.370 0.000 432.751 0.000 432.751 AD VALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 4.967 0.000 21.450 0.000 0.000 30.000 5.669 5.669 4.160 12-2014 4.898 0.000 23.400 0.000 0.000 0.000 32.924 38.592 32.749 12-2015 4.407 0.000 23.400 0.000 0.000 0.000 27.284 65.877 54.290 12-2016 3.966 0.000 23.400 0.000 0.000 0.000 22.210 88.087 70.233 12-2017 3.569 0.000 23.400 0.000 0.000 0.000 17.643 105.730 81.750 12-2018 3.212 0.000 23.400 0.000 0.000 0.000 13.534 119.264 89.783 12-2019 2.890 0.000 23.400 0.000 0.000 0.000 9.836 129.100 95.094 12-2020 2.601 0.000 23.400 0.000 0.000 0.000 6.508 135.609 98.292 12-2021 2.340 0.000 23.400 0.000 0.000 0.000 3.514 139.122 99.865 12-2022 1.770 0.000 19.500 0.000 0.000 0.000 0.858 139.981 100.220 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT 34.620 0.000 228.150 0.000 0.000 30.000 139.981 139.981 100.220 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 139.981 100.220 TOTAL 34.620 0.000 228.150 0.000 0.000 30.000 139.981 139.981 100.220 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 9.83 5.00 117.537 GROSS ULT., MB & MMF 20.833 0.000 DISCOUNT % 10.00 8.00 106.639 GROSS CUM., MB & MMF 14.483 0.000 UNDISCOUNTED PAYOUT, YRS. 0.84 10.00 100.220 GROSS RES., MB & MMF 6.350 0.000 DISCOUNTED PAYOUT, YRS. 0.88 12.00 94.382 NET RES., MB & MMF 4.953 0.000 UNDISCOUNTED NET/INVEST. 5.67 15.00 86.567 NET REVENUE, M$ 432.751 0.000 DISCOUNTED NET/INVEST. 4.37 18.00 79.711 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 246.57 30.00 59.196 INITIAL N.I., PCT. 78.000 0.000 INITIAL W.I., PCT. 100.000 60.00 32.591 80.00 23.324 260.00 -1.019 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 34 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 35 CIMYOTTE #6-21DATE: 04/01/2013FIELD: TRAPPERTIME: 14:03:09COUNTY: ADAMS STATE: CODBS: DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS: RED_JAN 131PDPSCENARIO: RED_JAN 13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 12-2013 1.629 4.640 1.256 3.577 87.370 2.690 109.719 9.622 119.341 12-2014 1.334 3.717 1.028 2.865 87.370 2.690 89.827 7.707 97.534 12-2015 1.092 2.977 0.842 2.295 87.370 2.690 73.542 6.173 79.715 12-2016 0.894 2.385 0.689 1.838 87.370 2.690 60.209 4.945 65.154 12-2017 0.732 1.910 0.564 1.472 87.370 2.690 49.293 3.961 53.254 12-2018 0.599 1.530 0.462 1.179 87.370 2.690 40.356 3.173 43.529 12-2019 0.491 1.226 0.378 0.945 87.370 2.690 33.039 2.541 35.581 12-2020 0.402 0.982 0.310 0.757 87.370 2.690 27.049 2.036 29.085 12-2021 0.329 0.786 0.253 0.606 87.370 2.690 22.145 1.631 23.776 12-2022 0.269 0.630 0.208 0.486 87.370 2.690 18.130 1.306 19.437 12-2023 0.220 0.505 0.170 0.389 87.370 2.690 14.843 1.046 15.890 12-2024 0.180 0.404 0.139 0.312 87.370 2.690 12.152 0.838 12.990 12-2025 0.148 0.324 0.114 0.250 87.370 2.690 9.949 0.671 10.620 12-2026 0.063 0.137 0.049 0.105 87.370 2.690 4.276 0.284 4.560 12-2027 S TOT 8.383 22.154 6.461 17.076 87.370 2.690 564.531 45.935 610.465 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 TOTAL 8.383 22.154 6.461 17.076 87.370 2.690 564.531 45.935 610.465 AD VALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 10.741 0.000 7.938 0.000 0.000 0.000 100.663 100.663 96.179 12-2014 8.778 0.000 7.938 0.000 0.000 0.000 80.818 181.481 166.380 12-2015 7.174 0.000 7.938 0.000 0.000 0.000 64.603 246.084 217.396 12-2016 5.864 0.000 7.938 0.000 0.000 0.000 51.352 297.435 254.263 12-2017 4.793 0.000 7.938 0.000 0.000 0.000 40.523 337.958 280.713 12-2018 3.918 0.000 7.938 0.000 0.000 0.000 31.673 369.631 299.508 12-2019 3.202 0.000 7.938 0.000 0.000 0.000 24.441 394.072 312.695 12-2020 2.618 0.000 7.938 0.000 0.000 0.000 18.529 412.601 321.785 12-2021 2.140 0.000 7.938 0.000 0.000 0.000 13.698 426.299 327.895 12-2022 1.749 0.000 7.938 0.000 0.000 0.000 9.749 436.049 331.850 12-2023 1.430 0.000 7.938 0.000 0.000 0.000 6.521 442.570 334.257 12-2024 1.169 0.000 7.938 0.000 0.000 0.000 3.883 446.453 335.562 12-2025 0.956 0.000 7.938 0.000 0.000 0.000 1.726 448.180 336.091 12-2026 0.410 0.000 3.969 0.000 0.000 0.000 0.180 448.360 336.142 12-2027 S TOT 54.942 0.000 107.163 0.000 0.000 0.000 448.360 448.360 336.142 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 448.360 336.142 TOTAL 54.942 0.000 107.163 0.000 0.000 0.000 448.360 448.360 336.142 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 13.50 5.00 383.979 GROSS ULT., MB & MMF 92.734 323.189 DISCOUNT % 10.00 8.00 353.691 GROSS CUM., MB & MMF 84.352 301.036 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 336.142 GROSS RES., MB & MMF 8.383 22.154 DISCOUNTED PAYOUT, YRS. 0.00 12.00 320.363 NET RES., MB & MMF 6.461 17.076 UNDISCOUNTED NET/INVEST. 0.00 15.00 299.497 NET REVENUE, M$ 564.531 45.935 DISCOUNTED NET/INVEST. 0.00 18.00 281.429 INITIAL PRICE, $ 87.370 2.690 RATE-OF-RETURN, PCT. 260.00 30.00 228.519 INITIAL N.I., PCT. 77.080 77.080 INITIAL W.I., PCT. 94.500 60.00 161.624 80.00 138.363 260.00 74.638 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 36 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 37 SAWYER 32-2DATE: 04/01/2013FIELD: WATTENBERGTIME: 14:03:09COUNTY: WELD STATE: CODBS: DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS: RED_JAN 131PDPSCENARIO: RED_JAN 13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTION-MMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTALNET SALESM$ 12-2013 0.816 2.933 0.331 1.189 87.370 2.690 28.908 3.198 32.106 12-2014 0.783 2.406 0.317 0.975 87.370 2.690 27.726 2.624 30.350 12-2015 0.751 1.975 0.304 0.800 87.370 2.690 26.592 2.153 28.745 12-2016 0.720 1.620 0.292 0.657 87.370 2.690 25.504 1.767 27.271 12-2017 0.691 1.329 0.280 0.539 87.370 2.690 24.461 1.450 25.911 12-2018 0.662 1.091 0.269 0.442 87.370 2.690 23.461 1.189 24.651 12-2019 0.635 0.895 0.258 0.363 87.370 2.690 22.502 0.976 23.478 12-2020 0.609 0.734 0.247 0.298 87.370 2.690 21.581 0.801 22.382 12-2021 0.584 0.603 0.237 0.244 87.370 2.690 20.699 0.657 21.356 12-2022 0.561 0.495 0.227 0.200 87.370 2.690 19.852 0.539 20.392 12-2023 0.538 0.406 0.218 0.164 87.370 2.690 19.041 0.442 19.483 12-2024 0.516 0.333 0.209 0.135 87.370 2.690 18.262 0.363 18.625 12-2025 0.495 0.273 0.200 0.111 87.370 2.690 17.515 0.298 17.813 12-2026 0.474 0.224 0.192 0.091 87.370 2.690 16.799 0.244 17.043 12-2027 0.455 0.184 0.184 0.075 87.370 2.690 16.112 0.201 16.312 S TOT 9.290 15.501 3.766 6.283 87.370 2.690 329.015 16.902 345.917 AFTER 1.828 0.496 0.741 0.201 87.370 2.690 64.729 0.540 65.269 TOTAL 11.118 15.997 4.507 6.484 87.370 2.690 393.743 17.443 411.186 AD VALOREM PRODUCTION DIRECT OPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 2.568 0.000 4.807 0.000 0.000 0.000 24.731 24.731 23.601 12-2014 2.428 0.000 4.807 0.000 0.000 0.000 23.115 47.846 43.655 12-2015 2.300 0.000 4.807 0.000 0.000 0.000 21.639 69.484 60.721 12-2016 2.182 0.000 4.807 0.000 0.000 0.000 20.283 89.767 75.264 12-2017 2.073 0.000 4.807 0.000 0.000 0.000 19.031 108.799 87.668 12-2018 1.972 0.000 4.807 0.000 0.000 0.000 17.872 126.670 98.258 12-2019 1.878 0.000 4.807 0.000 0.000 0.000 16.793 143.463 107.304 12-2020 1.791 0.000 4.807 0.000 0.000 0.000 15.785 159.248 115.034 12-2021 1.708 0.000 4.807 0.000 0.000 0.000 14.841 174.089 121.641 12-2022 1.631 0.000 4.807 0.000 0.000 0.000 13.954 188.043 127.288 12-2023 1.559 0.000 4.807 0.000 0.000 0.000 13.118 201.160 132.114 12-2024 1.490 0.000 4.807 0.000 0.000 0.000 12.328 213.488 136.237 12-2025 1.425 0.000 4.807 0.000 0.000 0.000 11.581 225.070 139.759 12-2026 1.363 0.000 4.807 0.000 0.000 0.000 10.873 235.943 142.765 12-2027 1.305 0.000 4.807 0.000 0.000 0.000 10.201 246.143 145.328 S TOT 27.673 0.000 72.100 0.000 0.000 0.000 246.143 246.143 145.328 AFTER 5.222 0.000 21.630 0.000 0.000 0.000 38.417 284.561 152.887 TOTAL 32.895 0.000 93.730 0.000 0.000 0.000 284.561 284.561 152.887 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 19.50 5.00 201.165 GROSS ULT., MB & MMF 37.475 181.878 DISCOUNT % 10.00 8.00 169.357 GROSS CUM., MB & MMF 26.357 165.882 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 152.887 GROSS RES., MB & MMF 11.118 15.997 DISCOUNTED PAYOUT, YRS. 0.00 12.00 139.222 NET RES., MB & MMF 4.507 6.484 UNDISCOUNTED NET/INVEST. 0.00 15.00 122.708 NET REVENUE, M$ 393.743 17.443 DISCOUNTED NET/INVEST. 0.00 18.00 109.736 INITIAL PRICE, $ 87.370 2.690 RATE-OF-RETURN, PCT. 260.00 30.00 77.884 INITIAL N.I., PCT. 40.536 40.536 INITIAL W.I., PCT. 57.222 60.00 47.684 80.00 39.079 260.00 18.960 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 38 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 39 SLW STATE PC BB18-65HNDATE: 04/01/2013FIELD: WATTENBERGTIME: 14:03:09COUNTY: WELD STATE: CODBS: DEMOOPERATOR: NOBLE ENERGY INCORPORSETTINGS: RED_JAN131PDPSCENARIO: RED_JAN13 R E S E R V E S A N D E C O N O M I C SAS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTALNET SALESM$ 12-2013 31.127 195.829 2.153 13.137 87.370 2.594 188.086 34.078 222.164 12-2014 19.665 100.543 1.053 5.235 87.370 2.594 91.996 13.579 105.575 12-2015 15.214 67.032 0.789 3.373 87.370 2.594 68.948 8.749 77.697 12-2016 12.701 49.954 0.659 2.513 87.370 2.594 57.561 6.520 64.081 12-2017 11.046 39.640 0.573 1.994 87.370 2.594 50.061 5.174 55.235 12-2018 9.857 32.756 0.511 1.648 87.370 2.594 44.671 4.275 48.946 12-2019 8.952 27.847 0.464 1.401 87.370 2.594 40.571 3.634 44.205 12-2020 8.221 24.176 0.426 1.216 87.370 2.594 37.256 3.155 40.412 12-2021 7.563 21.331 0.392 1.073 87.370 2.594 34.276 2.784 37.060 12-2022 6.958 19.064 0.361 0.959 87.370 2.594 31.534 2.488 34.022 12-2023 6.401 17.216 0.332 0.866 87.370 2.594 29.011 2.247 31.258 12-2024 5.889 15.683 0.305 0.789 87.370 2.594 26.690 2.047 28.737 12-2025 5.418 14.392 0.281 0.724 87.370 2.594 24.555 1.878 26.433 12-2026 4.985 13.289 0.259 0.669 87.370 2.594 22.591 1.734 24.325 12-2027 4.586 12.338 0.238 0.621 87.370 2.594 20.783 1.610 22.394 S TOT 158.584 651.090 8.797 36.220 87.370 2.594 768.590 93.954 862.544 AFTER 41.922 132.118 2.175 6.647 87.370 2.594 189.988 17.243 207.231 TOTAL 200.506 783.208 10.971 42.867 87.370 2.594 958.578 111.197 1069.775 AD VALOREM PRODUCTION DIRECT OPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 17.773 0.000 1.707 0.000 0.000 0.000 202.684 202.684 194.381 12-2014 8.446 0.000 1.316 0.000 0.000 0.000 95.813 298.497 277.794 12-2015 6.216 0.000 1.280 0.000 0.000 0.000 70.201 368.697 333.230 12-2016 5.126 0.000 1.280 0.000 0.000 0.000 57.674 426.371 374.616 12-2017 4.419 0.000 1.280 0.000 0.000 0.000 49.536 475.907 406.922 12-2018 3.916 0.000 1.280 0.000 0.000 0.000 43.750 519.657 432.856 12-2019 3.536 0.000 1.280 0.000 0.000 0.000 39.388 559.045 454.079 12-2020 3.233 0.000 1.280 0.000 0.000 0.000 35.898 594.943 471.662 12-2021 2.965 0.000 1.280 0.000 0.000 0.000 32.815 627.758 486.274 12-2022 2.722 0.000 1.280 0.000 0.000 0.000 30.020 657.778 498.426 12-2023 2.501 0.000 1.280 0.000 0.000 0.000 27.477 685.255 508.537 12-2024 2.299 0.000 1.280 0.000 0.000 0.000 25.158 710.412 516.953 12-2025 2.115 0.000 1.280 0.000 0.000 0.000 23.038 733.451 523.960 12-2026 1.946 0.000 1.280 0.000 0.000 0.000 21.099 754.549 529.793 12-2027 1.791 0.000 1.280 0.000 0.000 0.000 19.322 773.871 534.650 S TOT 69.004 0.000 19.669 0.000 0.000 0.000 773.871 773.871 534.650 AFTER 16.578 0.000 24.329 0.000 0.000 0.000 166.324 940.195 557.752 TOTAL 85.582 0.000 43.998 0.000 0.000 0.000 940.195 940.195 557.752 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 40 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 41 SLW STATE PC BB18-67HNDATE: 04/01/2013FIELD: WATTENBERGTIME: 14:03:10COUNTY: WELD STATE: CODBS: DEMOOPERATOR: NOBLE ENERGY INCORPORSETTINGS: RED_JAN 131PDPSCENARIO: RED_JAN 13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 12-2013 28.995 173.266 1.714 9.935 87.370 2.580 149.745 25.632 175.377 12-2014 18.400 88.371 0.816 3.800 87.370 2.580 71.271 9.805 81.076 12-2015 14.253 58.783 0.632 2.528 87.370 2.580 55.210 6.522 61.732 12-2016 11.907 43.755 0.528 1.882 87.370 2.580 46.120 4.854 50.975 12-2017 10.359 34.695 0.459 1.492 87.370 2.580 40.126 3.849 43.975 12-2018 9.246 28.656 0.410 1.232 87.370 2.580 35.814 3.179 38.993 12-2019 8.399 24.353 0.372 1.047 87.370 2.580 32.533 2.702 35.235 12-2020 7.713 21.137 0.342 0.909 87.370 2.580 29.877 2.345 32.222 12-2021 7.096 18.645 0.315 0.802 87.370 2.580 27.487 2.069 29.556 12-2022 6.529 16.661 0.289 0.716 87.370 2.580 25.288 1.848 27.136 12-2023 6.006 15.044 0.266 0.647 87.370 2.580 23.265 1.669 24.934 12-2024 5.526 13.703 0.245 0.589 87.370 2.580 21.404 1.520 22.924 12-2025 5.084 12.573 0.225 0.541 87.370 2.580 19.691 1.395 21.086 12-2026 4.677 11.609 0.207 0.499 87.370 2.580 18.116 1.288 19.404 12-2027 4.303 10.777 0.191 0.463 87.370 2.580 16.667 1.196 17.862 S TOT 148.493 572.029 7.012 27.083 87.370 2.580 612.614 69.874 682.488 AFTER 37.324 108.004 1.655 4.645 87.370 2.580 144.573 11.983 156.556 TOTAL 185.818 680.033 8.666 31.727 87.370 2.580 757.187 81.856 839.043 AD VALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 14.030 0.000 1.459 0.000 0.000 0.000 159.887 159.887 153.330 12-2014 6.486 0.000 1.094 0.000 0.000 0.000 73.496 233.383 217.228 12-2015 4.939 0.000 1.094 0.000 0.000 0.000 55.699 289.081 261.212 12-2016 4.078 0.000 1.094 0.000 0.000 0.000 45.803 334.884 294.079 12-2017 3.518 0.000 1.094 0.000 0.000 0.000 39.363 374.247 319.750 12-2018 3.119 0.000 1.094 0.000 0.000 0.000 34.780 409.026 340.367 12-2019 2.819 0.000 1.094 0.000 0.000 0.000 31.321 440.348 357.243 12-2020 2.578 0.000 1.094 0.000 0.000 0.000 28.550 468.898 371.227 12-2021 2.364 0.000 1.094 0.000 0.000 0.000 26.097 494.994 382.848 12-2022 2.171 0.000 1.094 0.000 0.000 0.000 23.871 518.865 392.511 12-2023 1.995 0.000 1.094 0.000 0.000 0.000 21.845 540.710 400.550 12-2024 1.834 0.000 1.094 0.000 0.000 0.000 19.996 560.706 407.239 12-2025 1.687 0.000 1.094 0.000 0.000 0.000 18.305 579.011 412.806 12-2026 1.552 0.000 1.094 0.000 0.000 0.000 16.757 595.769 417.439 12-2027 1.429 0.000 1.094 0.000 0.000 0.000 15.339 611.108 421.295 S TOT 54.599 0.000 16.781 0.000 0.000 0.000 611.108 611.108 421.295 AFTER 12.524 0.000 18.422 0.000 0.000 0.000 125.609 736.716 439.315 TOTAL 67.123 0.000 35.203 0.000 0.000 0.000 736.716 736.716 439.315 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 31.83 5.00 542.272 GROSS ULT., MB & MMF 210.909 833.428 DISCOUNT % 10.00 8.00 473.898 GROSS CUM., MB & MMF 25.091 153.396 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 439.315 GROSS RES., MB & MMF 185.818 680.033 DISCOUNTED PAYOUT, YRS. 0.00 12.00 410.859 NET RES., MB & MMF 8.666 31.727 UNDISCOUNTED NET/INVEST. 0.00 15.00 376.515 NET REVENUE, M$ 757.187 81.856 DISCOUNTED NET/INVEST. 0.00 18.00 349.341 INITIAL PRICE, $ 87.370 2.580 RATE-OF-RETURN, PCT. 260.00 30.00 280.022 INITIAL N.I., PCT. 5.911 5.911 INITIAL W.I., PCT. 6.756 60.00 205.567 80.00 181.129 260.00 111.830 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 42 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 43 VINCE STATE B13-63HNDATE: 04/01/2013FIELD: WATTENBERGTIME: 14:03:10COUNTY: WELD STATE: CODBS: DEMOOPERATOR: NOBLE ENERGY INCORPORSETTINGS: RED_JAN 131PDPSCENARIO: RED_JAN 13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTALNETSALESM$ 12-2013 25.448 191.876 0.490 3.584 87.370 2.704 42.809 9.690 52.499 12-2014 15.803 96.881 0.256 1.534 87.370 2.704 22.401 4.147 26.548 12-2015 12.168 64.223 0.176 0.900 87.370 2.704 15.352 2.432 17.785 12-2016 10.135 47.720 0.146 0.668 87.370 2.704 12.787 1.807 14.595 12-2017 8.803 37.799 0.127 0.529 87.370 2.704 11.106 1.432 12.538 12-2018 7.848 31.197 0.113 0.437 87.370 2.704 9.901 1.182 11.083 12-2019 7.123 26.498 0.103 0.371 87.370 2.704 8.987 1.004 9.990 12-2020 6.550 22.989 0.095 0.322 87.370 2.704 8.264 0.871 9.135 12-2021 6.084 20.273 0.088 0.284 87.370 2.704 7.675 0.768 8.443 12-2022 5.694 18.111 0.082 0.254 87.370 2.704 7.184 0.686 7.870 12-2023 5.351 16.350 0.077 0.229 87.370 2.704 6.752 0.619 7.371 12-2024 5.030 14.890 0.073 0.209 87.370 2.704 6.346 0.564 6.910 12-2025 4.728 13.661 0.068 0.191 87.370 2.704 5.966 0.517 6.483 12-2026 4.445 12.611 0.064 0.177 87.370 2.704 5.608 0.478 6.085 12-2027 4.178 11.706 0.060 0.164 87.370 2.704 5.271 0.443 5.715 S TOT 129.390 626.786 2.019 9.852 87.370 2.704 176.410 26.640 203.050 AFTER 44.186 122.354 0.638 1.714 87.370 2.704 55.747 4.634 60.382 TOTAL 173.576 749.140 2.657 11.566 87.370 2.704 232.158 31.274 263.432 AD VALOREM PRODUCTION DIRECT OPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 4.200 0.000 0.475 0.000 0.000 0.000 47.824 47.824 45.879 12-2014 2.124 0.000 0.396 0.000 0.000 0.000 24.028 71.852 66.840 12-2015 1.423 0.000 0.356 0.000 0.000 0.000 16.005 87.857 79.480 12-2016 1.168 0.000 0.356 0.000 0.000 0.000 13.071 100.928 88.860 12-2017 1.003 0.000 0.356 0.000 0.000 0.000 11.178 112.106 96.150 12-2018 0.887 0.000 0.356 0.000 0.000 0.000 9.840 121.946 101.983 12-2019 0.799 0.000 0.356 0.000 0.000 0.000 8.835 130.781 106.744 12-2020 0.731 0.000 0.356 0.000 0.000 0.000 8.048 138.828 110.685 12-2021 0.675 0.000 0.356 0.000 0.000 0.000 7.411 146.240 113.985 12-2022 0.630 0.000 0.356 0.000 0.000 0.000 6.884 153.124 116.772 12-2023 0.590 0.000 0.356 0.000 0.000 0.000 6.425 159.548 119.135 12-2024 0.553 0.000 0.356 0.000 0.000 0.000 6.001 165.550 121.143 12-2025 0.519 0.000 0.356 0.000 0.000 0.000 5.608 171.157 122.848 12-2026 0.487 0.000 0.356 0.000 0.000 0.000 5.242 176.400 124.297 12-2027 0.457 0.000 0.356 0.000 0.000 0.000 4.901 181.301 125.529 S TOT 16.244 0.000 5.505 0.000 0.000 0.000 181.301 181.301 125.529 AFTER 4.831 0.000 6.476 0.000 0.000 0.000 49.075 230.376 132.101 TOTAL 21.075 0.000 11.981 0.000 0.000 0.000 230.376 230.376 132.101 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 33.17 5.00 164.745 GROSS ULT., MB & MMF 196.425 920.075 DISCOUNT % 10.00 8.00 142.894 GROSS CUM., MB & MMF 22.849 170.935 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 132.101 GROSS RES., MB & MMF 173.576 749.140 DISCOUNTED PAYOUT, YRS. 0.00 12.00 123.347 NET RES., MB & MMF 2.657 11.566 UNDISCOUNTED NET/INVEST. 0.00 15.00 112.923 NET REVENUE, M$ 232.158 31.274 DISCOUNTED NET/INVEST. 0.00 18.00 104.773 INITIAL PRICE, $ 87.370 2.704 RATE-OF-RETURN, PCT. 260.00 30.00 84.256 INITIAL N.I., PCT. 1.925 1.925 INITIAL W.I., PCT. 2.200 60.00 62.303 80.00 55.029 260.00 34.060 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529  44 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 45 PALM 21A-20, 43-20, 23-21DATE: 04/01/2013FIELD: ALBIN WESTTIME: 14:03:10COUNTY: BANNER STATE: NEDBS: DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS: RED_JAN 131PDPSCENARIO: RED_JAN 13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTALNET SALESM$ 12-2013 5.076 0.000 4.188 0.000 87.370 0.000 365.866 0.000 365.866 12-2014 3.346 0.000 2.761 0.000 87.370 0.000 241.190 0.000 241.190 12-2015 2.342 0.000 1.932 0.000 87.370 0.000 168.829 0.000 168.829 12-2016 1.462 0.000 1.206 0.000 87.370 0.000 105.389 0.000 105.389 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT 12.226 0.000 10.087 0.000 87.370 0.000 881.275 0.000 881.275 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 TOTAL 12.226 0.000 10.087 0.000 87.370 0.000 881.275 0.000 881.275 AD VALOREM PRODUCTION DIRECT OPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 7.098 10.976 105.600 0.000 0.000 0.000 242.192 242.192 232.186 12-2014 4.679 7.236 105.600 0.000 0.000 0.000 123.676 365.868 340.024 12-2015 3.275 5.065 105.600 0.000 0.000 0.000 54.889 420.757 383.623 12-2016 2.045 3.162 88.000 0.000 0.000 0.000 12.183 432.940 392.538 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT 17.097 26.438 404.800 0.000 0.000 0.000 432.940 432.940 392.538 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 432.940 392.538 TOTAL 17.097 26.438 404.800 0.000 0.000 0.000 432.940 432.940 392.538 OIL GAS P.W. % P.W., M$ GROSS WELLS 2.0 0.0 LIFE, YRS. 3.83 5.00 411.446 GROSS ULT., MB & MMF 93.396 0.000 DISCOUNT % 10.00 8.00 399.821 GROSS CUM., MB & MMF 81.170 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 392.538 GROSS RES., MB & MMF 12.226 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 385.599 NET RES., MB & MMF 10.087 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 375.782 NET REVENUE, M$ 881.275 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 366.615 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 335.306 INITIAL N.I., PCT. 82.500 0.000 INITIAL W.I., PCT. 100.000 60.00 281.820 80.00 257.795 260.00 169.311 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 46 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 47 PALM EGLE 34-17DATE: 04/01/2013FIELD: ALBIN WESTTIME: 14:03:10COUNTY: BANNER STATE: NEDBS: DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS: RED_JAN 131PDPSCENARIO: RED_JAN 13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTALNET SALESM$ 12-2013 7.900 0.000 6.518 0.000 87.370 0.000 569.455 0.000 569.455 12-2014 6.636 0.000 5.475 0.000 87.370 0.000 478.343 0.000 478.343 12-2015 5.574 0.000 4.599 0.000 87.370 0.000 401.808 0.000 401.808 12-2016 4.683 0.000 3.863 0.000 87.370 0.000 337.518 0.000 337.518 12-2017 3.933 0.000 3.245 0.000 87.370 0.000 283.515 0.000 283.515 12-2018 3.304 0.000 2.726 0.000 87.370 0.000 238.153 0.000 238.153 12-2019 2.775 0.000 2.290 0.000 87.370 0.000 200.049 0.000 200.049 12-2020 2.331 0.000 1.923 0.000 87.370 0.000 168.041 0.000 168.041 12-2021 1.958 0.000 1.616 0.000 87.370 0.000 141.154 0.000 141.154 12-2022 1.645 0.000 1.357 0.000 87.370 0.000 118.570 0.000 118.570 12-2023 1.382 0.000 1.140 0.000 87.370 0.000 99.598 0.000 99.598 12-2024 1.161 0.000 0.958 0.000 87.370 0.000 83.663 0.000 83.663 12-2025 0.975 0.000 0.804 0.000 87.370 0.000 70.277 0.000 70.277 12-2026 0.819 0.000 0.676 0.000 87.370 0.000 59.032 0.000 59.032 12-2027 0.635 0.000 0.524 0.000 87.370 0.000 45.777 0.000 45.777 S TOT 45.712 0.000 37.713 0.000 87.370 0.000 3294.953 0.000 3294.953 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 TOTAL 45.712 0.000 37.713 0.000 87.370 0.000 3294.953 0.000 3294.953 AD VALOREM PRODUCTION DIRECT OPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 11.047 17.084 43.800 0.000 0.000 0.000 497.524 497.524 475.259 12-2014 9.280 14.350 43.800 0.000 0.000 0.000 410.912 908.437 832.107 12-2015 7.795 12.054 43.800 0.000 0.000 0.000 338.158 1246.595 1099.085 12-2016 6.548 10.126 43.800 0.000 0.000 0.000 277.045 1523.640 1297.937 12-2017 5.500 8.505 43.800 0.000 0.000 0.000 225.710 1749.350 1445.222 12-2018 4.620 7.145 43.800 0.000 0.000 0.000 182.588 1931.938 1553.544 12-2019 3.881 6.001 43.800 0.000 0.000 0.000 146.366 2078.304 1632.489 12-2020 3.260 5.041 43.800 0.000 0.000 0.000 115.940 2194.244 1689.345 12-2021 2.738 4.235 43.800 0.000 0.000 0.000 90.381 2284.625 1729.643 12-2022 2.300 3.557 43.800 0.000 0.000 0.000 68.912 2353.538 1757.582 12-2023 1.932 2.988 43.800 0.000 0.000 0.000 50.878 2404.416 1776.339 12-2024 1.623 2.510 43.800 0.000 0.000 0.000 35.730 2440.146 1788.321 12-2025 1.363 2.108 43.800 0.000 0.000 0.000 23.005 2463.150 1795.340 12-2026 1.145 1.771 43.800 0.000 0.000 0.000 12.316 2475.467 1798.764 12-2027 0.888 1.373 40.150 0.000 0.000 0.000 3.366 2478.833 1799.626 S TOT 63.922 98.849 653.350 0.000 0.000 0.000 2478.833 2478.833 1799.626 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 2478.833 1799.626 TOTAL 63.922 98.849 653.350 0.000 0.000 0.000 2478.833 2478.833 1799.626 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 14.92 5.00 2084.613 GROSS ULT., MB & MMF 74.310 0.000 DISCOUNT % 10.00 8.00 1903.357 GROSS CUM., MB & MMF 28.598 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 1799.626 GROSS RES., MB & MMF 45.712 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 1707.175 NET RES., MB & MMF 37.713 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 1586.138 NET REVENUE, M$ 3294.953 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 1482.463 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 1185.055 INITIAL N.I., PCT. 82.500 0.000 INITIAL W.I., PCT. 100.000 60.00 822.200 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 48 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 49 LUKASSEN 14-34DATE : 04/01/2013FIELD: CABLETIME : 14:03:11COUNTY: KIMBALL STATE: NEDBS : DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS : RED_JAN131PDPSCENARIO : RED_JAN13 RESERVES AND ECONOMICS AS OF DATE: 12/31/2012--END--MO-YEAR-------GROSS OILPRODUCTION---MBBLS---GROSS GASPRODUCTION----MMCF---NET OILPRODUCTION---MBBLS---NET GASPRODUCTION----MMCF---NET OILPRICE---$/BBL---NET GASPRICE---$/MCF---NETOIL SALES-----M$----NETGAS SALES-----M$----TOTAL NETSALES-----M$----12-20131.6650.0001.2990.00087.3700.000113.4680.000113.46812-20141.2370.0000.9650.00087.3700.00084.2760.00084.27612-20150.9430.0000.7360.00087.3700.00064.2900.00064.29012-20160.0680.0000.0530.00087.3700.0004.6560.0004.65612-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT3.9130.0003.0520.00087.3700.000266.6890.000266.689AFTER0.0000.0000.0000.0000.0000.0000.0000.0000.000TOTAL3.9130.0003.0520.00087.3700.000266.6890.000266.689 --END--ADVALOREMPRODUCTIONDIRECTOPERINTERESTCAPITALEQUITYFUTURENETCUMULATIVECUM. DISC.MO-YEARTAXTAXEXPENSEPAIDREPAYMENTINVESTMENTCASHFLOWCASHFLOWCASHFLOW------------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$----12-20132.2013.40452.8000.0000.0000.00055.06255.06252.77212-20141.6352.52852.8000.0000.0000.00027.31382.37576.61012-20151.2471.92952.8000.0000.0000.0008.31490.68983.26212-20160.0900.1404.4000.0000.0000.0000.02690.71583.28212-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT5.1748.001162.8000.0000.0000.00090.71590.71583.282AFTER0.0000.0000.0000.0000.0000.0000.00090.71583.282TOTAL5.1748.001162.8000.0000.0000.00090.71590.71583.282 OILGAS P.W. %P.W., M$ ------------------ --------------GROSS WELLS1.00.0 LIFE, YRS.3.085.0086.784GROSS ULT., MB & MMF14.4080.000 DISCOUNT %10.008.0084.636GROSS CUM., MB & MMF10.4940.000 UNDISCOUNTED PAYOUT, YRS.0.0010.0083.282GROSS RES., MB & MMF3.9130.000 DISCOUNTED PAYOUT, YRS.0.0012.0081.985NET RES., MB & MMF3.0520.000 UNDISCOUNTED NET/INVEST.0.0015.0080.140NET REVENUE, M$266.6890.000 DISCOUNTED NET/INVEST.0.0018.0078.407INITIAL PRICE, $87.3700.000 RATE-OF-RETURN, PCT.260.0030.0072.401INITIAL N.I., PCT.78.0000.000 INITIAL W.I., PCT.100.00060.0061.817 80.0056.920 260.0038.079RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 50 51 WILKE 34-5,33-5,24-5,23-5 DATE : 04/01/2013FIELD: DILL EASTTIME : 14:03:11COUNTY: KIMBALL STATE: NEDBS : DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS : RED_JAN131PDPSCENARIO : RED_JAN13 RESERVES AND ECONOMICS AS OF DATE: 12/31/2012 --END--MO-YEAR-------GROSS OILPRODUCTION---MBBLS---GROSS GASPRODUCTION----MMCF---NET OILPRODUCTION---MBBLS---NET GASPRODUCTION----MMCF---NET OILPRICE---$/BBL---NET GASPRICE---$/MCF---NETOIL SALES-----M$----NETGAS SALES-----M$----TOTAL NETSALES-----M$----12-20136.2680.0004.2780.00087.3700.000373.7720.000373.77212-20144.2400.0002.8940.00087.3700.000252.8090.000252.80912-20150.8490.0000.5790.00087.3700.00050.6000.00050.60012-2016 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT11.3560.0007.7510.00087.3700.000677.1810.000677.181AFTER0.0000.0000.0000.0000.0000.0000.0000.0000.000TOTAL11.3560.0007.7510.00087.3700.000677.1810.000677.181 --END--ADVALOREMPRODUCTIONDIRECTOPERINTERESTCAPITALEQUITYFUTURENETCUMULATIVECUM. DISC.MO-YEARTAXTAXEXPENSEPAIDREPAYMENTINVESTMENTCASHFLOWCASHFLOWCASHFLOW------------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$----12-20137.25111.213184.8000.0000.0000.000170.508170.508163.75812-20144.9047.584184.8000.0000.0000.00055.520226.028212.49212-20150.9821.51846.2000.0000.0000.0001.901227.929214.05012-2016 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT13.13720.315415.8000.0000.0000.000227.929227.929214.050AFTER0.0000.0000.0000.0000.0000.0000.000227.929214.050TOTAL13.13720.315415.8000.0000.0000.000227.929227.929214.050 OILGAS P.W. %P.W., M$ ------------------ --------------GROSS WELLS4.00.0LIFE, YRS.2.255.00220.652GROSS ULT., MB & MMF61.3240.000DISCOUNT %10.008.00216.616GROSS CUM., MB & MMF49.9670.000UNDISCOUNTED PAYOUT, YRS.0.0010.00214.050GROSS RES., MB & MMF11.3560.000DISCOUNTED PAYOUT, YRS.0.0012.00211.577NET RES., MB & MMF7.7510.000UNDISCOUNTED NET/INVEST.0.0015.00208.030NET REVENUE, M$677.1810.000DISCOUNTED NET/INVEST.0.0018.00204.665INITIAL PRICE, $87.3700.000RATE-OF-RETURN, PCT.260.0030.00192.763INITIAL N.I., PCT.68.2500.000INITIAL W.I., PCT.87.50060.00170.747 80.00160.048 260.00115.116RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 52 53 HANSON 42-26DATE : 04/01/2013FIELD: GOLDEN PRARIE TIME : 14:03:11COUNTY: LARAMIE STATE: WYDBS : DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS : RED_JAN131PDPSCENARIO : RED_JAN13 RESERVES AND ECONOMICS AS OF DATE: 12/31/2012--END--MO-YEAR-------GROSS OILPRODUCTION---MBBLS---GROSS GASPRODUCTION----MMCF---NET OILPRODUCTION---MBBLS---NET GASPRODUCTION----MMCF---NET OILPRICE---$/BBL---NET GASPRICE---$/MCF---NETOIL SALES-----M$----NETGAS SALES-----M$----TOTAL NETSALES-----M$----12-20139.3320.0006.7190.00087.3700.000587.0190.000587.01912-20147.0530.0005.0780.00087.3700.000443.6890.000443.68912-20155.5280.0003.9800.00087.3700.000347.7740.000347.77412-20164.4560.0003.2080.00087.3700.000280.3250.000280.32512-20173.6730.0002.6440.00087.3700.000231.0260.000231.02612-20183.0820.0002.2190.00087.3700.000193.8620.000193.86212-20192.6250.0001.8900.00087.3700.000165.1270.000165.12712-20202.2640.0001.6300.00087.3700.000142.4340.000142.43412-20211.9740.0001.4210.00087.3700.000124.1890.000124.18912-20221.7370.0001.2510.00087.3700.000109.2920.000109.29212-20231.5410.0001.1100.00087.3700.00096.9660.00096.96612-20241.3770.0000.9920.00087.3700.00086.6470.00086.64712-20251.2390.0000.8920.00087.3700.00077.9190.00077.91912-20261.1200.0000.8070.00087.3700.00070.4670.00070.46712-20271.0180.0000.7330.00087.3700.00064.0530.00064.053 S TOT48.0200.00034.5750.00087.3700.0003020.7880.0003020.788AFTER1.1500.0000.8280.00087.3700.00072.3310.00072.331TOTAL49.1700.00035.4030.00087.3700.0003093.1190.0003093.119 --END--ADVALOREMPRODUCTIONDIRECTOPERINTERESTCAPITALEQUITYFUTURENETCUMULATIVECUM. DISC.MO-YEARTAXTAXEXPENSEPAIDREPAYMENTINVESTMENTCASHFLOWCASHFLOWCASHFLOW------------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$----12-201339.72537.56947.5200.0000.0000.000462.205462.205442.01312-201430.02628.39647.5200.0000.0000.000337.747799.952735.56112-201523.53522.25847.5200.0000.0000.000254.4621054.414936.57612-201618.97017.94147.5200.0000.0000.000195.8931250.3071077.23712-201715.63414.78647.5200.0000.0000.000153.0861403.3931177.15712-201813.11912.40747.5200.0000.0000.000120.8151524.2091248.84212-201911.17510.56847.5200.0000.0000.00095.8641620.0731300.54912-20209.6399.11647.5200.0000.0000.00076.1591696.2311337.89412-20218.4047.94847.5200.0000.0000.00060.3161756.5481364.78212-20227.3966.99547.5200.0000.0000.00047.3811803.9291383.98612-20236.5626.20647.5200.0000.0000.00036.6781840.6071397.50212-20245.8645.54547.5200.0000.0000.00027.7181868.3251406.79012-20255.2734.98747.5200.0000.0000.00020.1391888.4641412.92812-20264.7694.51047.5200.0000.0000.00013.6691902.1331416.71712-20274.3354.09947.5200.0000.0000.0008.0991910.2321418.762 S TOT204.425193.330712.8000.0000.0000.0001910.2321910.2321418.762AFTER4.8954.62959.4000.0000.0000.0003.4071913.6391419.546TOTAL209.320197.960772.2000.0000.0000.0001913.6391913.6391419.546 OILGAS P.W. %P.W., M$ ------------------ --------------GROSS WELLS1.00.0LIFE, YRS.16.255.001626.358GROSS ULT., MB & MMF49.1700.000DISCOUNT %10.008.001494.783GROSS CUM., MB & MMF0.0000.000UNDISCOUNTED PAYOUT, YRS.0.0010.001419.546GROSS RES., MB & MMF49.1700.000DISCOUNTED PAYOUT, YRS.0.0012.001352.488NET RES., MB & MMF35.4030.000UNDISCOUNTED NET/INVEST.0.0015.001264.629NET REVENUE, M$3093.1190.000DISCOUNTED NET/INVEST.0.0018.001189.245INITIAL PRICE, $87.3700.000RATE-OF-RETURN, PCT.260.0030.00971.572INITIAL N.I., PCT.72.0000.000INITIAL W.I., PCT.90.00060.00699.663 80.00604.724 260.00338.447 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 54 55 ANDERSON 21-34DATE : 04/01/2013FIELD: STATELINE TIME : 14:03:11COUNTY: LARAMIE STATE: WYDBS : DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS : RED_JAN131PDPSCENARIO : RED_JAN13 RESERVES AND ECONOMICS AS OF DATE: 12/31/2012--END--MO-YEAR-------GROSS OILPRODUCTION---MBBLS---GROSS GASPRODUCTION----MMCF---NET OILPRODUCTION---MBBLS---NET GASPRODUCTION----MMCF---NET OILPRICE---$/BBL---NET GASPRICE---$/MCF---NETOIL SALES-----M$----NETGAS SALES-----M$----TOTAL NETSALES-----M$----12-20130.7710.0000.4390.00087.3700.00038.3840.00038.38412-2014 12-2015 12-2016 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT0.7710.0000.4390.00087.3700.00038.3840.00038.384AFTER0.0000.0000.0000.0000.0000.0000.0000.0000.000TOTAL0.7710.0000.4390.00087.3700.00038.3840.00038.384 --END--ADVALOREMPRODUCTIONDIRECTOPERINTERESTCAPITALEQUITYFUTURENETCUMULATIVECUM. DISC.MO-YEARTAXTAXEXPENSEPAIDREPAYMENTINVESTMENTCASHFLOWCASHFLOWCASHFLOW------------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$----12-20132.5982.45726.0480.0000.0000.0007.2827.2827.13312-2014 12-2015 12-2016 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT2.5982.45726.0480.0000.0000.0007.2827.2827.133AFTER0.0000.0000.0000.0000.0000.0000.0007.2827.133TOTAL2.5982.45726.0480.0000.0000.0007.2827.2827.133 OILGAS P.W. %P.W., M$ ------------------ --------------GROSS WELLS1.00.0LIFE, YRS.0.675.007.205GROSS ULT., MB & MMF7.4040.000DISCOUNT %10.008.007.161GROSS CUM., MB & MMF6.6330.000UNDISCOUNTED PAYOUT, YRS.0.0010.007.133GROSS RES., MB & MMF0.7710.000DISCOUNTED PAYOUT, YRS.0.0012.007.106NET RES., MB & MMF0.4390.000UNDISCOUNTED NET/INVEST.0.0015.007.065NET REVENUE, M$38.3840.000DISCOUNTED NET/INVEST.0.0018.007.027INITIAL PRICE, $87.3700.000RATE-OF-RETURN, PCT.260.0030.006.884INITIAL N.I., PCT.56.9800.000INITIAL W.I., PCT.74.00060.006.592 80.006.435 260.005.620 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 56 57 HOLGERSON 33A-33DATE : 04/01/2013FIELD: STATELINE TIME : 14:03:12COUNTY: LARAMIE STATE: WYDBS : DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS : RED_JAN131PDPSCENARIO : RED_JAN13 RESERVES AND ECONOMICS AS OF DATE: 12/31/2012 --END--MO-YEAR-------GROSS OILPRODUCTION---MBBLS---GROSS GASPRODUCTION----MMCF---NET OILPRODUCTION---MBBLS---NET GASPRODUCTION----MMCF---NET OILPRICE---$/BBL---NET GASPRICE---$/MCF---NETOIL SALES-----M$----NETGAS SALES-----M$----TOTAL NETSALES-----M$----12-20132.1830.0001.6810.00087.3700.000146.8570.000146.85712-20141.5300.0001.1780.00087.3700.000102.9330.000102.93312-20151.1610.0000.8940.00087.3700.00078.1340.00078.13412-20160.5640.0000.4340.00087.3700.00037.9200.00037.92012-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT5.4380.0004.1870.00087.3700.000365.8450.000365.845AFTER0.0000.0000.0000.0000.0000.0000.0000.0000.000TOTAL5.4380.0004.1870.00087.3700.000365.8450.000365.845 --END--ADVALOREMPRODUCTIONDIRECTOPERINTERESTCAPITALEQUITYFUTURENETCUMULATIVECUM. DISC.MO-YEARTAXTAXEXPENSEPAIDREPAYMENTINVESTMENTCASHFLOWCASHFLOWCASHFLOW------------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$----12-20139.9389.39952.8000.0000.0000.00074.72074.72071.66012-20146.9666.58852.8000.0000.0000.00036.580111.300103.56712-20155.2885.00152.8000.0000.0000.00015.046126.346115.53112-20162.5662.42730.8000.0000.0000.0002.127128.473117.09912-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT24.75823.414189.2000.0000.0000.000128.473128.473117.099AFTER0.0000.0000.0000.0000.0000.0000.000128.473117.099TOTAL24.75823.414189.2000.0000.0000.000128.473128.473117.099 OILGAS P.W. %P.W., M$ ------------------ --------------GROSS WELLS1.00.0LIFE, YRS.3.585.00122.435GROSS ULT., MB & MMF80.4270.000DISCOUNT %10.008.00119.157GROSS CUM., MB & MMF74.9890.000UNDISCOUNTED PAYOUT, YRS.0.0010.00117.099GROSS RES., MB & MMF5.4380.000DISCOUNTED PAYOUT, YRS.0.0012.00115.135NET RES., MB & MMF4.1870.000UNDISCOUNTED NET/INVEST.0.0015.00112.351NET REVENUE, M$365.8450.000DISCOUNTED NET/INVEST.0.0018.00109.746INITIAL PRICE, $87.3700.000RATE-OF-RETURN, PCT.260.0030.00100.804INITIAL N.I., PCT.77.0000.000INITIAL W.I., PCT.100.00060.0085.362 80.0078.352 260.0052.111RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 58 59 MALM 42-34DATE : 04/01/2013FIELD: STATELINE TIME : 14:03:12COUNTY: LARAMIE STATE: WYDBS : DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS : RED_JAN131PDPSCENARIO : RED_JAN13 RESERVES AND ECONOMICS AS OF DATE: 12/31/2012 --END--MO-YEAR-------GROSS OILPRODUCTION---MBBLS---GROSS GASPRODUCTION----MMCF---NET OILPRODUCTION---MBBLS---NET GASPRODUCTION----MMCF---NET OILPRICE---$/BBL---NET GAS PRICE---$/MCF---NETOIL SALES-----M$----NETGAS SALES-----M$----TOTAL NETSALES-----M$----12-20131.3380.0000.7620.00087.3700.00066.6110.00066.61112-20140.7700.0000.4390.00087.3700.00038.3140.00038.31412-2015 12-2016 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT2.1080.0001.2010.00087.3700.000104.9250.000104.925AFTER0.0000.0000.0000.0000.0000.0000.0000.0000.000TOTAL2.1080.0001.2010.00087.3700.000104.9250.000104.925 --END--ADVALOREMPRODUCTIONDIRECTOPERINTERESTCAPITALEQUITYFUTURENETCUMULATIVECUM. DISC.MO-YEARTAXTAXEXPENSEPAIDREPAYMENTINVESTMENTCASHFLOWCASHFLOWCASHFLOW------------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$----12-20134.5084.26339.0720.0000.0000.00018.76818.76818.03212-20142.5932.45229.3040.0000.0000.0003.96522.73321.55012-2015 12-2016 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT7.1016.71568.3760.0000.0000.00022.73322.73321.550AFTER0.0000.0000.0000.0000.0000.0000.00022.73321.550TOTAL7.1016.71568.3760.0000.0000.00022.73322.73321.550 OILGAS P.W. %P.W., M$ ------------------ --------------GROSS WELLS1.00.0LIFE, YRS.1.755.0022.116GROSS ULT., MB & MMF6.6010.000DISCOUNT %10.008.0021.770GROSS CUM., MB & MMF4.4930.000UNDISCOUNTED PAYOUT, YRS.0.0010.0021.550GROSS RES., MB & MMF2.1080.000DISCOUNTED PAYOUT, YRS.0.0012.0021.337NET RES., MB & MMF1.2010.000UNDISCOUNTED NET/INVEST.0.0015.0021.030NET REVENUE, M$104.9250.000DISCOUNTED NET/INVEST.0.0018.0020.738INITIAL PRICE, $87.3700.000RATE-OF-RETURN, PCT.260.0030.0019.694INITIAL N.I., PCT.56.9800.000INITIAL W.I., PCT.74.00060.0017.716 80.0016.732 260.0012.408RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 60 61 WENZEL 12-34 DATE : 04/01/2013FIELD: STATELINE TIME : 14:03:12COUNTY: LARAMIE STATE: WYDBS : DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS : RED_JAN131PDPSCENARIO : RED_JAN13 RESERVES AND ECONOMICS AS OF DATE: 12/31/2012 --END--MO-YEAR-------GROSS OILPRODUCTION---MBBLS---GROSS GASPRODUCTION----MMCF---NET OILPRODUCTION---MBBLS---NET GASPRODUCTION----MMCF---NET OILPRICE---$/BBL---NET GASPRICE---$/MCF---NETOIL SALES-----M$----NETGAS SALES-----M$----TOTAL NETSALES-----M$----12-201318.7690.00014.4520.00087.3700.0001262.6960.0001262.69612-201413.1870.00010.1540.00087.3700.000887.1350.000887.13512-20159.6810.0007.4540.00087.3700.000651.2660.000651.26612-20167.3540.0005.6620.00087.3700.000494.7250.000494.72512-20175.7410.0004.4210.00087.3700.000386.2250.000386.22512-20184.5830.0003.5290.00087.3700.000308.3450.000308.34512-20193.7280.0002.8710.00087.3700.000250.8040.000250.80412-20203.0810.0002.3720.00087.3700.000207.2490.000207.24912-20212.5800.0001.9870.00087.3700.000173.5950.000173.59512-20222.1870.0001.6840.00087.3700.000147.1230.000147.12312-20231.8730.0001.4420.00087.3700.000125.9770.000125.97712-20241.6180.0001.2460.00087.3700.000108.8550.000108.85512-20251.4090.0001.0850.00087.3700.00094.8220.00094.82212-20261.2370.0000.9520.00087.3700.00083.1970.00083.19712-20271.0920.0000.8410.00087.3700.00073.4740.00073.474 S TOT78.1200.00060.1520.00087.3700.0005255.4870.0005255.487AFTER1.0460.0000.8060.00087.3700.00070.3800.00070.380TOTAL79.1660.00060.9580.00087.3700.0005325.8670.0005325.867 --END--ADVALOREMPRODUCTIONDIRECTOPERINTERESTCAPITALEQUITYFUTURENETCUMULATIVECUM. DISC.MO-YEARTAXTAXEXPENSEPAIDREPAYMENTINVESTMENTCASHFLOWCASHFLOWCASHFLOW------------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$----12-201385.45080.81352.8000.0000.0000.0001043.6331043.633998.55112-201460.03556.77752.8000.0000.0000.000717.5231761.1561622.45012-201544.07341.68152.8000.0000.0000.000512.7122273.8682027.63012-201633.47931.66252.8000.0000.0000.000376.7832650.6512298.27112-201726.13724.71852.8000.0000.0000.000282.5702933.2212482.76312-201820.86719.73452.8000.0000.0000.000214.9443148.1652610.33212-201916.97316.05152.8000.0000.0000.000164.9803313.1452699.34112-202014.02513.26452.8000.0000.0000.000127.1603440.3052761.70912-202111.74811.11052.8000.0000.0000.00097.9373538.2422805.37712-20229.9569.41652.8000.0000.0000.00074.9513613.1932835.76112-20238.5258.06352.8000.0000.0000.00056.5893669.7832856.61912-20247.3666.96752.8000.0000.0000.00041.7213711.5042870.60212-20256.4176.06952.8000.0000.0000.00029.5363741.0402879.60512-20265.6305.32552.8000.0000.0000.00019.4423760.4822884.99712-20274.9724.70252.8000.0000.0000.00011.0003771.4822887.775 S TOT355.654336.351792.0000.0000.0000.0003771.4823771.4822887.775AFTER4.7634.50457.2000.0000.0000.0003.9133775.3952888.680TOTAL360.416340.856849.2000.0000.0000.0003775.3953775.3952888.680 OILGAS P.W. %P.W., M$ ------------------ --------------GROSS WELLS1.00.0LIFE, YRS.16.085.003264.100GROSS ULT., MB & MMF192.3980.000DISCOUNT %10.008.003026.062GROSS CUM., MB & MMF113.2320.000UNDISCOUNTED PAYOUT, YRS.0.0010.002888.680GROSS RES., MB & MMF79.1660.000DISCOUNTED PAYOUT, YRS.0.0012.002765.386NET RES., MB & MMF60.9580.000UNDISCOUNTED NET/INVEST.0.0015.002602.547NET REVENUE, M$5325.8670.000DISCOUNTED NET/INVEST.0.0018.002461.562INITIAL PRICE, $87.3700.000RATE-OF-RETURN, PCT.260.0030.002047.021INITIAL N.I., PCT. 77.000 0.000INITIAL W.I., PCT. 100.00060.001510.634 80.001317.627 260.00757.853RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 62 63 OLIVERIUS 42-33DATE : 04/01/2013FIELD: STATELINE TIME : 14:03:12COUNTY: LARAMIE STATE: WYDBS : DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS : RED_JAN131PDPSCENARIO : RED_JAN13 RESERVES AND ECONOMICS AS OF DATE: 12/31/2012 --END--MO-YEAR-------GROSS OILPRODUCTION---MBBLS---GROSS GASPRODUCTION----MMCF---NET OILPRODUCTION---MBBLS---NET GASPRODUCTION----MMCF---NET OILPRICE---$/BBL---NET GASPRICE---$/MCF---NETOIL SALES----M$----NETGAS SALES-----M$----TOTAL NETSALES----M$----12-20132.6410.0002.0340.00087.3700.000177.6950.000177.69512-20141.6330.0001.2570.00087.3700.000109.8360.000109.83612-20151.0910.0000.8400.00087.3700.00073.4280.00073.42812-2016 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT5.3650.0004.1310.00087.3700.000360.9590.000360.959AFTER0.0000.0000.0000.0000.0000.0000.0000.0000.000TOTAL5.3650.0004.1310.00087.3700.000360.9590.000360.959 --END--ADVALOREMPRODUCTIONDIRECTOPERINTERESTCAPITALEQUITYFUTURENETCUMULATIVECUM. DISC.MO-YEARTAXTAXEXPENSEPAIDREPAYMENTINVESTMENTCASHFLOWCASHFLOWCASHFLOW------------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$---------M$----12-201312.02511.37252.8000.0000.0000.000101.497101.49797.42012-20147.4337.03052.8000.0000.0000.00042.574144.071134.61912-20154.9694.69952.8000.0000.0000.00010.959155.030143.40512-2016 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT24.42723.101158.4000.0000.0000.000155.030155.030143.405AFTER0.0000.0000.0000.0000.0000.0000.000155.030143.405TOTAL24.42723.101158.4000.0000.0000.000155.030155.030143.405 OILGAS P.W. %P.W., M$ ------------------ --------------GROSS WELLS1.00.0LIFE, YRS.3.005.00148.895GROSS ULT., MB & MMF38.9830.000DISCOUNT %10.008.00145.530GROSS CUM., MB & MMF33.6170.000UNDISCOUNTED PAYOUT, YRS.0.0010.00143.405GROSS RES., MB & MMF5.3650.000DISCOUNTED PAYOUT, YRS.0.0012.00141.367NET RES., MB & MMF4.1310.000UNDISCOUNTED NET/INVEST.0.0015.00138.463NET REVENUE, M$360.9590.000DISCOUNTED NET/INVEST.0.0018.00135.728INITIAL PRICE, $87.3700.000RATE-OF-RETURN, PCT.260.0030.00126.206INITIAL N.I., PCT.77.0000.000INITIAL W.I., PCT.100.00060.00109.227 80.00101.272 260.0069.906RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 64 65 OLIVERIUS 41-33DATE: 04/01/2013FIELD: STATELINETIME: 14:03:10COUNTY: LARAMIE STATE: WYDBS: DEMOOPERATOR: RECOVERY ENERGY INCORSETTINGS: RED_JAN 131PDPSCENARIO: RED_JAN 13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 12-2013 1.573 0.000 1.211 0.000 87.370 0.000 105.790 0.000 105.790 12-2014 1.128 0.000 0.869 0.000 87.370 0.000 75.916 0.000 75.916 12-2015 0.312 0.000 0.240 0.000 87.370 0.000 20.975 0.000 20.975 12-2016 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT 3.013 0.000 2.320 0.000 87.370 0.000 202.681 0.000 202.681 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 TOTAL 3.013 0.000 2.320 0.000 87.370 0.000 202.681 0.000 202.681 AD VALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 7.159 6.771 52.800 0.000 0.000 0.000 39.061 39.061 37.514 12-2014 5.137 4.859 52.800 0.000 0.000 0.000 13.120 52.181 49.023 12-2015 1.419 1.342 17.600 0.000 0.000 0.000 0.613 52.793 49.524 12-2016 12-2017 12-2018 12-2019 12-2020 12-2021 12-2022 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT 13.716 12.972 123.200 0.000 0.000 0.000 52.793 52.793 49.524 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 52.793 49.524 TOTAL 13.716 12.972 123.200 0.000 0.000 0.000 52.793 52.793 49.524 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 2.33 5.00 51.079 GROSS ULT., MB & MMF 15.156 0.000 DISCOUNT % 10.00 8.00 50.128 GROSS CUM., MB & MMF 12.143 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 49.524 GROSS RES., MB & MMF 3.013 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 48.942 NET RES., MB & MMF 2.320 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 48.108 NET REVENUE, M$ 202.681 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 47.318 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 44.523 INITIAL N.I., PCT. 77.000 0.000 INITIAL W.I., PCT. 100.000 60.00 39.370 80.00 36.872 260.00 26.437 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 66 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 67 FORNSTROM 33-32 DATE :04/01/2013FIELD: WILDCAT TIME :14:03:13COUNTY: LARAMIE STATE: WYDBS :DEMOOPERATOR: EVERTSON OPERATING COSETTINGS :RED_JAN131PDPSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012--END--MO-YEAR-------GROSS OILPRODUCTION---MBBLS---GROSS GASPRODUCTION----MMCF---NET OILPRODUCTION---MBBLS---NET GASPRODUCTION----MMCF---NET OILPRICE---$/BBL---NET GASPRICE---$/MCF---NETOIL SALES-----M$----NETGAS SALES-----M$----TOTAL NETSALES-----M$----12-201311.4380.0000.2970.00087.3700.00025.9830.00025.98312-20147.0290.0000.1830.00087.3700.00015.9670.00015.96712-20155.0940.0000.1320.00087.3700.00011.5720.00011.57212-20164.0000.0000.1040.00087.3700.0009.0870.0009.08712-20173.2950.0000.0860.00087.3700.0007.4850.0007.48512-20182.8030.0000.0730.00087.3700.0006.3670.0006.36712-20192.4390.0000.0630.00087.3700.0005.5400.0005.54012-20202.1590.0000.0560.00087.3700.0004.9050.0004.90512-20211.9370.0000.0500.00087.3700.0004.4010.0004.40112-20221.7570.0000.0460.00087.3700.0003.9910.0003.99112-20231.6070.0000.0420.00087.3700.0003.6510.0003.65112-20241.4780.0000.0380.00087.3700.0003.3580.0003.35812-20251.3600.0000.0350.00087.3700.0003.0890.0003.08912-20261.2510.0000.0330.00087.3700.0002.8420.0002.84212-20271.1510.0000.0300.00087.3700.0002.6150.0002.615S TOT48.7980.0001.2690.00087.3700.000110.8520.000110.852AFTER2.8570.0000.0740.00087.3700.0006.4910.0006.491TOTAL51.6560.0001.3430.00087.3700.000117.3430.000117.343--END--ADVALOREMPRODUCTIONDIRECTOPERINTERESTCAPITALEQUITYFUTURENETCUMULATIVECUM. DISC.MO-YEAR-------TAX-----MS------TAX-----MS------EXPENSE-----MS------PAID-----MS------REPAYMENT-----MS------INVESTMENT-----MS------CASHFLOW-----MS------CASHFLOW-----MS------CASHFLOW-----MS------12-20131.7581.6630.0000.0000.0000.00022.56222.56221.62412-20141.0811.0220.0000.0000.0000.00013.86436.42633.68212-20150.7830.7410.0000.0000.0000.00010.04846.47441.62012-20160.6150.5820.0000.0000.0000.0007.89054.36447.28312-20170.5070.4790.0000.0000.0000.0006.50060.86451.52412-20180.4310.4070.0000.0000.0000.0005.52866.39354.80212-20190.3750.3550.0000.0000.0000.0004.81171.20357.39412-20200.3320.3140.0000.0000.0000.0004.25975.46259.48112-20210.2980.2820.0000.0000.0000.0003.82179.28461.18312-20220.2700.2550.0000.0000.0000.0003.46582.74962.58512-20230.2470.2340.0000.0000.0000.0003.17185.92063.75212-20240.2270.2150.0000.0000.0000.0002.91688.83564.72712-20250.2090.1980.0000.0000.0000.0002.68291.51765.54312-20260.1920.1820.0000.0000.0000.0002.46893.98566.22512-20270.1770.1670.0000.0000.0000.0002.27096.25566.796S TOT7.5027.0950.0000.0000.0000.00096.25596.25566.796AFTER0.4390.4150.0000.0000.0000.0005.636101.89267.981TOTAL7.9417.5100.0000.0000.0000.000101.892101.89267.981 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 17.92 5.00 81.119 GROSS ULT., MB & MMF 83.872 0.000 DISCOUNT % 10.00 8.00 72.589 GROSS CUM., MB & MMF 32.216 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 67.981 GROSS RES., MB & MMF 51.656 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 64.033 NET RES., MB & MMF 1.343 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 59.079 NET REVENUE, M$ 117.343 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 55.017 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 44.151 INITIAL N.I., PCT. 2.600 0.000 INITIAL W.I., PCT. 0.000 60.00 31.903 80.00 27.818 260.00 16.371 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 68 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 69 FORNSTROM 34A-32DATE :04/01/2013FIELD: WILDCAT TIME :14:03:13COUNTY: LARAMIE STATE: WYDBS :DEMOOPERATOR: EVERTSON OPERATING COSETTINGS :RED_JAN131PDPSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTION---MBBLS--- GROSS GASPRODUCTION MMCF--- NET OILPRODUCTION---MBBLS--- NET GASPRODUCTION---MMCF--- NET OILPRICE---$/BBL--- NET GASPRICE---$/MCF--- NETOIL SALES ---M$-- NETGAS SALES ---M$-- TOTAL NETSALES--M$-- 26.018 0.000 0.676 0.000 87.370 0.000 59.103 0.000 59.103 15.988 0.000 0.416 0.000 87.370 0.000 36.318 0.000 36.318 11.587 0.000 0.301 0.000 87.370 0.000 26.321 0.000 26.321 9.099 0.000 0.237 0.000 87.370 0.000 20.669 0.000 20.669 7.495 0.000 0.195 0.000 87.370 0.000 17.027 0.000 17.027 6.375 0.000 0.166 0.000 87.370 0.000 14.482 0.000 14.482 5.548 0.000 0.144 0.000 87.370 0.000 12.602 0.000 12.602 4.911 0.000 0.128 0.000 87.370 0.000 11.157 0.000 11.157 4.407 0.000 0.115 0.000 87.370 0.000 10.010 0.000 10.010 3.996 0.000 0.104 0.000 87.370 0.000 9.078 0.000 9.078 3.656 0.000 0.095 0.000 87.370 0.000 8.305 0.000 8.305 3.362 0.000 0.087 0.000 87.370 0.000 7.637 0.000 7.637 3.093 0.000 0.080 0.000 87.370 0.000 7.026 0.000 7.026 2.846 0.000 0.074 0.000 87.370 0.000 6.464 0.000 6.464 2.618 0.000 0.068 0.000 87.370 0.000 5.947 0.000 5.947 110.999 0.000 2.886 0.000 87.370 0.000 252.148 0.000 252.148 19.781 0.000 0.514 0.000 87.370 0.000 44.935 0.000 44.935 130.780 0.000 3.400 0.000 87.370 0.000 297.083 0.000 297.083 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX-----MS------ TAX-----MS------ EXPENSE-----MS------ PAID-----MS------ REPAYMENT-----MS------ INVESTMENT-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ 4.000 3.783 0.000 0.000 0.000 0.000 51.321 51.321 49.188 2.458 2.324 0.000 0.000 0.000 0.000 31.536 82.857 76.615 1.781 1.685 0.000 0.000 0.000 0.000 22.855 105.713 94.670 1.399 1.323 0.000 0.000 0.000 0.000 17.947 123.660 107.553 1.152 1.090 0.000 0.000 0.000 0.000 14.785 138.445 117.198 0.980 0.927 0.000 0.000 0.000 0.000 12.575 151.020 124.654 0.853 0.807 0.000 0.000 0.000 0.000 10.943 161.963 130.552 0.755 0.714 0.000 0.000 0.000 0.000 9.688 171.650 135.298 0.677 0.641 0.000 0.000 0.000 0.000 8.692 180.342 139.169 0.614 0.581 0.000 0.000 0.000 0.000 7.883 188.225 142.360 0.562 0.532 0.000 0.000 0.000 0.000 7.212 195.437 145.014 0.517 0.489 0.000 0.000 0.000 0.000 6.632 202.069 147.232 0.476 0.450 0.000 0.000 0.000 0.000 6.101 208.170 149.088 0.437 0.414 0.000 0.000 0.000 0.000 5.613 213.783 150.640 0.402 0.381 0.000 0.000 0.000 0.000 5.164 218.947 151.938 17.064 16.137 0.000 0.000 0.000 0.000 218.947 218.947 151.938 3.041 2.876 0.000 0.000 0.000 0.000 39.018 257.966 157.902 20.104 19.013 0.000 0.000 0.000 0.000 257.966 257.966 157.902 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 27.83 5.00 193.470 GROSS ULT., MB & MMF 164.919 0.000 DISCOUNT % 10.00 8.00 169.971 GROSS CUM., MB & MMF 34.139 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 157.902 GROSS RES., MB & MMF 130.780 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 147.875 NET RES., MB & MMF 3.400 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 135.651 NET REVENUE, M$ 297.083 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 125.880 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 100.526 INITIAL N.I., PCT. 2.600 0.000 INITIAL W.I., PCT. 0.000 60.00 72.569 80.00 63.276 260.00 37.239 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 70 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 71 FORNSTROM 43-32 DATE :04/01/2013FIELD: WILDCAT TIME :14:03:13COUNTY: LARAMIE STATE: WYDBS :DEMOOPERATOR: EVERTSON OPERATING COSETTINGS :RED_JAN131PDPSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTION---MBBLS--- GROSS GASPRODUCTION --MMCF--- NET OILPRODUCTION---MBBLS--- NET GASPRODUCTION --MMCF--- NET OILPRICE---$/BBL--- NET GASPRICE---$/MCF--- NETOIL SALES ---M$--- NETGAS SALES ---M$-- TOTAL NETSALES ---M$-- 13.264 0.000 0.345 0.000 87.370 0.000 30.132 0.000 30.132 8.298 0.000 0.216 0.000 87.370 0.000 18.849 0.000 18.849 6.053 0.000 0.157 0.000 87.370 0.000 13.750 0.000 13.750 4.768 0.000 0.124 0.000 87.370 0.000 10.830 0.000 10.830 3.934 0.000 0.102 0.000 87.370 0.000 8.936 0.000 8.936 3.349 0.000 0.087 0.000 87.370 0.000 7.607 0.000 7.607 2.915 0.000 0.076 0.000 87.370 0.000 6.622 0.000 6.622 2.581 0.000 0.067 0.000 87.370 0.000 5.863 0.000 5.863 2.316 0.000 0.060 0.000 87.370 0.000 5.261 0.000 5.261 2.100 0.000 0.055 0.000 87.370 0.000 4.770 0.000 4.770 1.921 0.000 0.050 0.000 87.370 0.000 4.364 0.000 4.364 1.766 0.000 0.046 0.000 87.370 0.000 4.013 0.000 4.013 1.625 0.000 0.042 0.000 87.370 0.000 3.692 0.000 3.692 1.495 0.000 0.039 0.000 87.370 0.000 3.396 0.000 3.396 1.376 0.000 0.036 0.000 87.370 0.000 3.125 0.000 3.125 57.760 0.000 1.502 0.000 87.370 0.000 131.210 0.000 131.210 5.465 0.000 0.142 0.000 87.370 0.000 12.414 0.000 12.414 63.225 0.000 1.644 0.000 87.370 0.000 143.624 0.000 143.624 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX-----MS------ TAX-----MS------ EXPENSE-----MS------ PAID-----MS------ REPAYMENT-----MS------ INVESTMENT-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ 2.039 1.928 0.000 0.000 0.000 0.000 26.164 26.164 25.071 1.276 1.206 0.000 0.000 0.000 0.000 16.367 42.531 39.305 0.931 0.880 0.000 0.000 0.000 0.000 11.940 54.471 48.736 0.733 0.693 0.000 0.000 0.000 0.000 9.404 63.875 55.487 0.605 0.572 0.000 0.000 0.000 0.000 7.759 71.635 60.549 0.515 0.487 0.000 0.000 0.000 0.000 6.605 78.240 64.465 0.448 0.424 0.000 0.000 0.000 0.000 5.750 83.990 67.564 0.397 0.375 0.000 0.000 0.000 0.000 5.091 89.081 70.058 0.356 0.337 0.000 0.000 0.000 0.000 4.568 93.649 72.093 0.323 0.305 0.000 0.000 0.000 0.000 4.142 97.791 73.769 0.295 0.279 0.000 0.000 0.000 0.000 3.789 101.581 75.164 0.272 0.257 0.000 0.000 0.000 0.000 3.484 105.065 76.329 0.250 0.236 0.000 0.000 0.000 0.000 3.206 108.271 77.304 0.230 0.217 0.000 0.000 0.000 0.000 2.949 111.220 78.120 0.211 0.200 0.000 0.000 0.000 0.000 2.713 113.933 78.802 8.879 8.397 0.000 0.000 0.000 0.000 113.933 113.933 78.802 0.840 0.795 0.000 0.000 0.000 0.000 10.780 124.712 80.882 9.719 9.192 0.000 0.000 0.000 0.000 124.712 124.712 80.882 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 20.08 5.00 97.487 GROSS ULT., MB & MMF 93.360 0.000 DISCOUNT % 10.00 8.00 86.652 GROSS CUM., MB & MMF 30.135 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 80.882 GROSS RES., MB & MMF 63.225 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 75.985 NET RES., MB & MMF 1.644 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 69.897 NET REVENUE, M$ 143.624 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 64.950 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 51.876 INITIAL N.I., PCT. 2.600 0.000 INITIAL W.I., PCT. 0.000 60.00 37.317 80.00 32.484 260.00 19.001 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 72 This Page Is Intentionally Left Blank 73 Proved UndevelopedIndividual Wells forNon-Producing Properties Proved Undeveloped 74 RECOVERY ENERGYDATE :04/01/2013PROVED UNDEVELOPEDTIME :14:03:16RESERVES AND REVENUES AS OF 12/3DBS :DEMOREVISED EVALUATION AT 03/28/2013SETTINGS :RED_JAN13 SCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTION---MBBLS--- GROSS GASPRODUCTION MMCF--- NET OILPRODUCTION---MBBLS--- NET GASPRODUCTION --MMCF--- NET OILPRICE---$/BBL--- NET GASPRICE---$/MCF--- NETOIL SALES ---M$-- NETGAS SALES ---M$-- TOTAL NETSALES ---M$-- 33.687 28.512 6.712 5.809 87.370 2.620 586.390 15.220 601.610 123.638 64.032 24.378 13.047 87.370 2.620 2129.907 34.182 2164.089 100.698 61.238 19.836 12.477 87.370 2.620 1733.070 32.690 1765.760 67.317 47.456 13.283 9.669 87.370 2.620 1160.554 25.333 1185.888 50.230 40.602 9.924 8.273 87.370 2.620 867.067 21.674 888.741 48.196 64.732 9.581 13.189 87.370 2.620 837.070 34.556 871.625 40.184 63.859 7.999 13.011 87.370 2.620 698.889 34.090 732.979 32.119 52.968 6.395 10.792 87.370 2.620 558.751 28.276 587.027 27.573 47.275 5.492 9.632 87.370 2.620 479.812 25.237 505.049 23.323 43.273 4.648 8.817 87.370 2.620 406.128 23.100 429.228 17.831 40.080 3.565 8.166 87.370 2.620 311.504 21.395 332.900 14.070 37.383 2.801 7.617 87.370 2.620 244.744 19.956 264.700 11.862 35.032 2.355 7.138 87.370 2.620 205.774 18.701 224.475 9.929 32.919 1.968 6.707 87.370 2.620 171.910 17.573 189.483 8.656 30.943 1.717 6.305 87.370 2.620 150.025 16.518 166.543 609.315 690.304 120.655 140.650 87.370 2.620 10541.596 368.502 10910.098 83.726 395.901 16.901 80.665 87.370 2.620 1476.615 211.342 1687.958 693.041 1086.205 137.555 221.314 87.370 2.620 12018.211 579.844 12598.056 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX-----MS------ TAX-----MS------ EXPENSE-----MS------ PAID-----MS------ REPAYMENT-----MS------ INVESTMENT-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ 27.449 10.238 28.450 0.000 0.000 0.000 535.474 535.474 499.256 78.074 61.712 116.300 0.000 0.000 250.000 1658.004 2193.478 1927.422 63.354 51.522 138.300 0.000 0.000 0.000 1512.585 3706.062 3124.600 40.996 32.289 138.300 0.000 0.000 0.000 974.303 4680.365 3824.857 30.671 23.032 138.300 0.000 0.000 0.000 696.737 5377.102 4279.834 37.713 17.688 138.300 0.000 0.000 218.750 459.173 5836.275 4550.696 32.438 13.831 133.900 0.000 0.000 0.000 552.810 6389.085 4849.090 25.023 10.861 125.100 0.000 0.000 0.000 426.043 6815.129 5057.976 21.552 9.333 125.100 0.000 0.000 0.000 349.064 7164.193 5213.524 18.849 7.668 122.900 0.000 0.000 0.000 279.811 7444.003 5327.001 16.070 5.229 110.800 0.000 0.000 0.000 200.801 7644.804 5401.018 14.019 3.543 86.600 0.000 0.000 0.000 160.538 7805.342 5454.753 12.623 2.641 72.300 0.000 0.000 0.000 136.911 7942.253 5496.412 11.403 1.859 54.700 0.000 0.000 0.000 121.520 8063.773 5530.018 10.474 1.410 45.900 0.000 0.000 0.000 108.758 8172.532 5557.357 440.709 252.856 1575.250 0.000 0.000 468.750 8172.532 8172.532 5557.357 125.355 4.793 653.425 0.000 0.000 0.000 904.385 9076.917 5678.957 566.064 257.649 2228.675 0.000 0.000 468.750 9076.917 9076.917 5678.957 OIL GAS P.W. % P.W., M$ GROSS WELLS 14.0 0.0 LIFE, YRS. 42.42 5.00 6950.415 GROSS ULT., MB & MMF 693.041 1086.205 DISCOUNT % 10.00 8.00 6122.896 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 5678.958 GROSS RES., MB & MMF 693.041 1086.205 DISCOUNTED PAYOUT, YRS. 0.00 12.00 5297.981 NET RES., MB & MMF 137.555 221.314 UNDISCOUNTED NET/INVEST. 20.36 15.00 4816.507 NET REVENUE, M$ 12018.210 579.844 DISCOUNTED NET/INVEST. 17.40 18.00 4416.851 INITIAL PRICE, $ 87.370 2.620 RATE-OF-RETURN, PCT. 260.00 30.00 3316.077 INITIAL N.I., PCT. 19.923 20.375 INITIAL W.I., PCT. 25.000 60.00 2025.678 80.00 1598.573 260.00 534.344 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 75 LANG 11-34 DATE :04/01/2013FIELD: WATTENBERGTIME :14:03:14COUNTY: WELD STATE: CODBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTION---MBBLS--- GROSS GASPRODUCTION MMCF--- NET OILPRODUCTION---MBBLS--- NET GASPRODUCTION ---MMCF--- NET OILPRICE---$/BBL--- NET GASPRICE---$/MCF--- NETOIL SALES ---M$-- NETGAS SALES---M$--- TOTAL NETSALES ---M$--- 2.754 5.702 0.561 1.162 87.370 2.620 49.027 3.044 52.071 4.042 12.806 0.823 2.609 87.370 2.620 71.946 6.836 78.782 3.025 12.248 0.616 2.495 87.370 2.620 53.850 6.538 60.388 2.182 9.491 0.445 1.934 87.370 2.620 38.845 5.067 43.911 1.780 8.120 0.363 1.655 87.370 2.620 31.682 4.335 36.016 3.185 12.946 0.649 2.638 87.370 2.620 56.689 6.911 63.600 2.861 12.772 0.583 2.602 87.370 2.620 50.939 6.818 57.757 2.210 10.594 0.450 2.158 87.370 2.620 39.342 5.655 44.997 1.896 9.455 0.386 1.926 87.370 2.620 33.746 5.047 38.793 1.691 8.655 0.345 1.763 87.370 2.620 30.107 4.620 34.727 1.542 8.016 0.314 1.633 87.370 2.620 27.444 4.279 31.723 1.423 7.477 0.290 1.523 87.370 2.620 25.330 3.991 29.321 1.323 7.006 0.270 1.428 87.370 2.620 23.547 3.740 27.287 1.235 6.584 0.252 1.341 87.370 2.620 21.989 3.515 25.503 1.157 6.189 0.236 1.261 87.370 2.620 20.602 3.304 23.906 32.305 138.061 6.582 28.130 87.370 2.620 575.084 73.700 648.784 14.795 79.180 3.014 16.133 87.370 2.620 263.370 42.268 305.639 47.100 217.241 9.597 44.263 87.370 2.620 838.454 115.969 954.423 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX-----MS------ TAX-----MS------ EXPENSE-----MS------ PAID-----MS------ REPAYMENT-----MS------ INVESTMENT-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ 4.166 0.000 1.950 0.000 0.000 0.000 45.956 45.956 42.971 6.303 0.000 3.900 0.000 0.000 50.000 18.579 64.535 58.782 4.831 0.000 3.900 0.000 0.000 0.000 51.657 116.192 99.650 3.513 0.000 3.900 0.000 0.000 0.000 36.498 152.691 125.859 2.881 0.000 3.900 0.000 0.000 0.000 29.235 181.926 144.933 5.088 0.000 3.900 0.000 0.000 43.750 10.862 192.788 151.042 4.621 0.000 3.900 0.000 0.000 0.000 49.236 242.024 177.630 3.600 0.000 3.900 0.000 0.000 0.000 37.498 279.522 196.012 3.103 0.000 3.900 0.000 0.000 0.000 31.790 311.312 210.173 2.778 0.000 3.900 0.000 0.000 0.000 28.049 339.361 221.529 2.538 0.000 3.900 0.000 0.000 0.000 25.285 364.646 230.835 2.346 0.000 3.900 0.000 0.000 0.000 23.075 387.721 238.554 2.183 0.000 3.900 0.000 0.000 0.000 21.204 408.925 245.003 2.040 0.000 3.900 0.000 0.000 0.000 19.563 428.488 250.411 1.912 0.000 3.900 0.000 0.000 0.000 18.093 446.582 254.958 51.903 0.000 56.550 0.000 0.000 93.750 446.582 446.582 254.958 24.451 0.000 106.925 0.000 0.000 0.000 174.263 620.844 277.891 76.354 0.000 163.475 0.000 0.000 93.750 620.844 620.844 277.891 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 42.42 5.00 389.009 GROSS ULT., MB & MMF 47.100 217.241 DISCOUNT % 10.00 8.00 314.170 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 277.891 GROSS RES., MB & MMF 47.100 217.241 DISCOUNTED PAYOUT, YRS. 0.00 12.00 248.927 NET RES., MB & MMF 9.597 44.263 UNDISCOUNTED NET/INVEST. 7.62 15.00 215.156 NET REVENUE, M$ 838.454 115.969 DISCOUNTED NET/INVEST. 5.01 18.00 189.465 INITIAL PRICE, $ 87.370 2.620 RATE-OF-RETURN, PCT. 260.00 30.00 128.935 INITIAL N.I., PCT. 20.375 20.375 INITIAL W.I., PCT. 25.000 60.00 74.287 80.00 59.177 260.00 24.476 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 76 LANG 12-34DATE :04/01/2013FIELD: WATTENBERGTIME :14:03:14COUNTY: WELD STATE: CODBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTION---MBBLS--- GROSS GASPRODUCTION MMCF--- NET OILPRODUCTION---MBBLS--- NET GASPRODUCTION ---MMCF--- NET OILPRICE---$/BBL--- NET GASPRICE---$/MCF--- NETOIL SALES ---M$-- NETGAS SALES---M$--- TOTAL NETSALES ---M$--- 2.754 5.702 0.561 1.162 87.370 2.620 49.027 3.044 52.071 4.042 12.806 0.823 2.609 87.370 2.620 71.946 6.836 78.782 3.025 12.248 0.616 2.495 87.370 2.620 53.850 6.538 60.388 2.182 9.491 0.445 1.934 87.370 2.620 38.845 5.067 43.911 1.780 8.120 0.363 1.655 87.370 2.620 31.682 4.335 36.016 3.185 12.946 0.649 2.638 87.370 2.620 56.689 6.911 63.600 2.861 12.772 0.583 2.602 87.370 2.620 50.939 6.818 57.757 2.210 10.594 0.450 2.158 87.370 2.620 39.342 5.655 44.997 1.896 9.455 0.386 1.926 87.370 2.620 33.746 5.047 38.793 1.691 8.655 0.345 1.763 87.370 2.620 30.107 4.620 34.727 1.542 8.016 0.314 1.633 87.370 2.620 27.444 4.279 31.723 1.423 7.477 0.290 1.523 87.370 2.620 25.330 3.991 29.321 1.323 7.006 0.270 1.428 87.370 2.620 23.547 3.740 27.287 1.235 6.584 0.252 1.341 87.370 2.620 21.989 3.515 25.503 1.157 6.189 0.236 1.261 87.370 2.620 20.602 3.304 23.906 32.305 138.061 6.582 28.130 87.370 2.620 575.084 73.700 648.784 14.795 79.180 3.014 16.133 87.370 2.620 263.370 42.268 305.639 47.100 217.241 9.597 44.263 87.370 2.620 838.454 115.969 954.423 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX-----MS------ TAX-----MS------ EXPENSE-----MS------ PAID-----MS------ REPAYMENT-----MS------ INVESTMENT-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ 4.166 0.000 1.950 0.000 0.000 0.000 45.956 45.956 42.971 6.303 0.000 3.900 0.000 0.000 50.000 18.579 64.535 58.782 4.831 0.000 3.900 0.000 0.000 0.000 51.657 116.192 99.650 3.513 0.000 3.900 0.000 0.000 0.000 36.498 152.691 125.859 2.881 0.000 3.900 0.000 0.000 0.000 29.235 181.926 144.933 5.088 0.000 3.900 0.000 0.000 43.750 10.862 192.788 151.042 4.621 0.000 3.900 0.000 0.000 0.000 49.236 242.024 177.630 3.600 0.000 3.900 0.000 0.000 0.000 37.498 279.522 196.012 3.103 0.000 3.900 0.000 0.000 0.000 31.790 311.312 210.173 2.778 0.000 3.900 0.000 0.000 0.000 28.049 339.361 221.529 2.538 0.000 3.900 0.000 0.000 0.000 25.285 364.646 230.835 2.346 0.000 3.900 0.000 0.000 0.000 23.075 387.721 238.554 2.183 0.000 3.900 0.000 0.000 0.000 21.204 408.925 245.003 2.040 0.000 3.900 0.000 0.000 0.000 19.563 428.488 250.411 1.912 0.000 3.900 0.000 0.000 0.000 18.093 446.582 254.958 51.903 0.000 56.550 0.000 0.000 93.750 446.582 446.582 254.958 24.451 0.000 106.925 0.000 0.000 0.000 174.263 620.844 277.891 76.354 0.000 163.475 0.000 0.000 93.750 620.844 620.844 277.891 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 42.42 5.00 389.009 GROSS ULT., MB & MMF 47.100 217.241 DISCOUNT % 10.00 8.00 314.170 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 277.891 GROSS RES., MB & MMF 47.100 217.241 DISCOUNTED PAYOUT, YRS. 0.00 12.00 248.927 NET RES., MB & MMF 9.597 44.263 UNDISCOUNTED NET/INVEST. 7.62 15.00 215.156 NET REVENUE, M$ 838.454 115.969 DISCOUNTED NET/INVEST. 5.01 18.00 189.465 INITIAL PRICE, $ 87.370 2.620 RATE-OF-RETURN, PCT. 260.00 30.00 128.935 INITIAL N.I., PCT. 20.375 20.375 INITIAL W.I., PCT. 25.000 60.00 74.287 80.00 59.177 260.00 24.476 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 77 LANG 21-34DATE :04/01/2013FIELD: WATTENBERGTIME :14:03:14COUNTY: WELD STATE: CODBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTION---MBBLS--- GROSS GASPRODUCTION MMCF--- NET OILPRODUCTION---MBBLS--- NET GASPRODUCTION ---MMCF--- NET OILPRICE---$/BBL--- NET GASPRICE---$/MCF--- NETOIL SALES ---M$-- NETGAS SALES---M$--- TOTAL NETSALES ---M$--- 2.754 5.702 0.561 1.162 87.370 2.620 49.027 3.044 52.071 4.042 12.806 0.823 2.609 87.370 2.620 71.946 6.836 78.782 3.025 12.248 0.616 2.495 87.370 2.620 53.850 6.538 60.388 2.182 9.491 0.445 1.934 87.370 2.620 38.845 5.067 43.911 1.780 8.120 0.363 1.655 87.370 2.620 31.682 4.335 36.016 3.185 12.946 0.649 2.638 87.370 2.620 56.689 6.911 63.600 2.861 12.772 0.583 2.602 87.370 2.620 50.939 6.818 57.757 2.210 10.594 0.450 2.158 87.370 2.620 39.342 5.655 44.997 1.896 9.455 0.386 1.926 87.370 2.620 33.746 5.047 38.793 1.691 8.655 0.345 1.763 87.370 2.620 30.107 4.620 34.727 1.542 8.016 0.314 1.633 87.370 2.620 27.444 4.279 31.723 1.423 7.477 0.290 1.523 87.370 2.620 25.330 3.991 29.321 1.323 7.006 0.270 1.428 87.370 2.620 23.547 3.740 27.287 1.235 6.584 0.252 1.341 87.370 2.620 21.989 3.515 25.503 1.157 6.189 0.236 1.261 87.370 2.620 20.602 3.304 23.906 32.305 138.061 6.582 28.130 87.370 2.620 575.084 73.700 648.784 14.795 79.180 3.014 16.133 87.370 2.620 263.370 42.268 305.639 47.100 217.241 9.597 44.263 87.370 2.620 838.454 115.969 954.423 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX-----MS------ TAX-----MS------ EXPENSE-----MS------ PAID-----MS------ REPAYMENT-----MS------ INVESTMENT-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ 4.166 0.000 1.950 0.000 0.000 0.000 45.956 45.956 42.971 6.303 0.000 3.900 0.000 0.000 50.000 18.579 64.535 58.782 4.831 0.000 3.900 0.000 0.000 0.000 51.657 116.192 99.650 3.513 0.000 3.900 0.000 0.000 0.000 36.498 152.691 125.859 2.881 0.000 3.900 0.000 0.000 0.000 29.235 181.926 144.933 5.088 0.000 3.900 0.000 0.000 43.750 10.862 192.788 151.042 4.621 0.000 3.900 0.000 0.000 0.000 49.236 242.024 177.630 3.600 0.000 3.900 0.000 0.000 0.000 37.498 279.522 196.012 3.103 0.000 3.900 0.000 0.000 0.000 31.790 311.312 210.173 2.778 0.000 3.900 0.000 0.000 0.000 28.049 339.361 221.529 2.538 0.000 3.900 0.000 0.000 0.000 25.285 364.646 230.835 2.346 0.000 3.900 0.000 0.000 0.000 23.075 387.721 238.554 2.183 0.000 3.900 0.000 0.000 0.000 21.204 408.925 245.003 2.040 0.000 3.900 0.000 0.000 0.000 19.563 428.488 250.411 1.912 0.000 3.900 0.000 0.000 0.000 18.093 446.582 254.958 51.903 0.000 56.550 0.000 0.000 93.750 446.582 446.582 254.958 24.451 0.000 106.925 0.000 0.000 0.000 174.263 620.844 277.891 76.354 0.000 163.475 0.000 0.000 93.750 620.844 620.844 277.891 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 42.42 5.00 389.009 GROSS ULT., MB & MMF 47.100 217.241 DISCOUNT % 10.00 8.00 314.170 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 277.891 GROSS RES., MB & MMF 47.100 217.241 DISCOUNTED PAYOUT, YRS. 0.00 12.00 248.927 NET RES., MB & MMF 9.597 44.263 UNDISCOUNTED NET/INVEST. 7.62 15.00 215.156 NET REVENUE, M$ 838.454 115.969 DISCOUNTED NET/INVEST. 5.01 18.00 189.465 INITIAL PRICE, $ 87.370 2.620 RATE-OF-RETURN, PCT. 260.00 30.00 128.935 INITIAL N.I., PCT. 20.375 20.375 INITIAL W.I., PCT. 25.000 60.00 74.287 80.00 59.177 260.00 24.476 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 78 LANG 2-2-34 DATE :04/01/2013FIELD: WATTENBERGTIME :14:03:14COUNTY: WELD STATE: CODBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTION---MBBLS--- GROSS GASPRODUCTION MMCF--- NET OILPRODUCTION---MBBLS--- NET GASPRODUCTION ---MMCF--- NET OILPRICE---$/BBL--- NET GASPRICE---$/MCF--- NETOIL SALES ---M$-- NETGAS SALES---M$--- TOTAL NETSALES ---M$--- 2.754 5.702 0.561 1.162 87.370 2.620 49.027 3.044 52.071 4.042 12.806 0.823 2.609 87.370 2.620 71.946 6.836 78.782 3.025 12.248 0.616 2.495 87.370 2.620 53.850 6.538 60.388 2.182 9.491 0.445 1.934 87.370 2.620 38.845 5.067 43.911 1.780 8.120 0.363 1.655 87.370 2.620 31.682 4.335 36.016 3.185 12.946 0.649 2.638 87.370 2.620 56.689 6.911 63.600 2.861 12.772 0.583 2.602 87.370 2.620 50.939 6.818 57.757 2.210 10.594 0.450 2.158 87.370 2.620 39.342 5.655 44.997 1.896 9.455 0.386 1.926 87.370 2.620 33.746 5.047 38.793 1.691 8.655 0.345 1.763 87.370 2.620 30.107 4.620 34.727 1.542 8.016 0.314 1.633 87.370 2.620 27.444 4.279 31.723 1.423 7.477 0.290 1.523 87.370 2.620 25.330 3.991 29.321 1.323 7.006 0.270 1.428 87.370 2.620 23.547 3.740 27.287 1.235 6.584 0.252 1.341 87.370 2.620 21.989 3.515 25.503 1.157 6.189 0.236 1.261 87.370 2.620 20.602 3.304 23.906 32.305 138.061 6.582 28.130 87.370 2.620 575.084 73.700 648.784 14.795 79.180 3.014 16.133 87.370 2.620 263.370 42.268 305.639 47.100 217.241 9.597 44.263 87.370 2.620 838.454 115.969 954.423 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX-----MS------ TAX-----MS------ EXPENSE-----MS------ PAID-----MS------ REPAYMENT-----MS------ INVESTMENT-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ 4.166 0.000 1.950 0.000 0.000 0.000 45.956 45.956 42.971 6.303 0.000 3.900 0.000 0.000 50.000 18.579 64.535 58.782 4.831 0.000 3.900 0.000 0.000 0.000 51.657 116.192 99.650 3.513 0.000 3.900 0.000 0.000 0.000 36.498 152.691 125.859 2.881 0.000 3.900 0.000 0.000 0.000 29.235 181.926 144.933 5.088 0.000 3.900 0.000 0.000 43.750 10.862 192.788 151.042 4.621 0.000 3.900 0.000 0.000 0.000 49.236 242.024 177.630 3.600 0.000 3.900 0.000 0.000 0.000 37.498 279.522 196.012 3.103 0.000 3.900 0.000 0.000 0.000 31.790 311.312 210.173 2.778 0.000 3.900 0.000 0.000 0.000 28.049 339.361 221.529 2.538 0.000 3.900 0.000 0.000 0.000 25.285 364.646 230.835 2.346 0.000 3.900 0.000 0.000 0.000 23.075 387.721 238.554 2.183 0.000 3.900 0.000 0.000 0.000 21.204 408.925 245.003 2.040 0.000 3.900 0.000 0.000 0.000 19.563 428.488 250.411 1.912 0.000 3.900 0.000 0.000 0.000 18.093 446.582 254.958 51.903 0.000 56.550 0.000 0.000 93.750 446.582 446.582 254.958 24.451 0.000 106.925 0.000 0.000 0.000 174.263 620.844 277.891 76.354 0.000 163.475 0.000 0.000 93.750 620.844 620.844 277.891 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 42.42 5.00 389.009 GROSS ULT., MB & MMF 47.100 217.241 DISCOUNT % 10.00 8.00 314.170 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 277.891 GROSS RES., MB & MMF 47.100 217.241 DISCOUNTED PAYOUT, YRS. 0.00 12.00 248.927 NET RES., MB & MMF 9.597 44.263 UNDISCOUNTED NET/INVEST. 7.62 15.00 215.156 NET REVENUE, M$ 838.454 115.969 DISCOUNTED NET/INVEST. 5.01 18.00 189.465 INITIAL PRICE, $ 87.370 2.620 RATE-OF-RETURN, PCT. 260.00 30.00 128.935 INITIAL N.I., PCT. 20.375 20.375 INITIAL W.I., PCT. 25.000 60.00 74.287 80.00 59.177 260.00 24.476 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 79 LANG 22-34DATE :04/01/2013FIELD: WATTENBERGTIME :14:03:14COUNTY: WELD STATE: CODBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTION---MBBLS--- GROSS GASPRODUCTION MMCF--- NET OILPRODUCTION---MBBLS--- NET GASPRODUCTION ---MMCF--- NET OILPRICE---$/BBL--- NET GASPRICE---$/MCF--- NETOIL SALES----M$-- NETGAS SALES--M$-- TOTAL NETSALES ---M$-- 2.754 5.702 0.561 1.162 87.370 2.620 49.027 3.044 52.071 4.042 12.806 0.823 2.609 87.370 2.620 71.946 6.836 78.782 3.025 12.248 0.616 2.495 87.370 2.620 53.850 6.538 60.388 2.182 9.491 0.445 1.934 87.370 2.620 38.845 5.067 43.911 1.780 8.120 0.363 1.655 87.370 2.620 31.682 4.335 36.016 3.185 12.946 0.649 2.638 87.370 2.620 56.689 6.911 63.600 2.861 12.772 0.583 2.602 87.370 2.620 50.939 6.818 57.757 2.210 10.594 0.450 2.158 87.370 2.620 39.342 5.655 44.997 1.896 9.455 0.386 1.926 87.370 2.620 33.746 5.047 38.793 1.691 8.655 0.345 1.763 87.370 2.620 30.107 4.620 34.727 1.542 8.016 0.314 1.633 87.370 2.620 27.444 4.279 31.723 1.423 7.477 0.290 1.523 87.370 2.620 25.330 3.991 29.321 1.323 7.006 0.270 1.428 87.370 2.620 23.547 3.740 27.287 1.235 6.584 0.252 1.341 87.370 2.620 21.989 3.515 25.503 1.157 6.189 0.236 1.261 87.370 2.620 20.602 3.304 23.906 32.305 138.061 6.582 28.130 87.370 2.620 575.084 73.700 648.784 14.795 79.180 3.014 16.133 87.370 2.620 263.370 42.268 305.639 47.100 217.241 9.597 44.263 87.370 2.620 838.454 115.969 954.423 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX-----MS------ TAX-----MS------ EXPENSE-----MS------ PAID-----MS------ REPAYMENT-----MS------ INVESTMENT-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ CASHFLOW-----MS------ 4.166 0.000 1.950 0.000 0.000 0.000 45.956 45.956 42.971 6.303 0.000 3.900 0.000 0.000 50.000 18.579 64.535 58.782 4.831 0.000 3.900 0.000 0.000 0.000 51.657 116.192 99.650 3.513 0.000 3.900 0.000 0.000 0.000 36.498 152.691 125.859 2.881 0.000 3.900 0.000 0.000 0.000 29.235 181.926 144.933 5.088 0.000 3.900 0.000 0.000 43.750 10.862 192.788 151.042 4.621 0.000 3.900 0.000 0.000 0.000 49.236 242.024 177.630 3.600 0.000 3.900 0.000 0.000 0.000 37.498 279.522 196.012 3.103 0.000 3.900 0.000 0.000 0.000 31.790 311.312 210.173 2.778 0.000 3.900 0.000 0.000 0.000 28.049 339.361 221.529 2.538 0.000 3.900 0.000 0.000 0.000 25.285 364.646 230.835 2.346 0.000 3.900 0.000 0.000 0.000 23.075 387.721 238.554 2.183 0.000 3.900 0.000 0.000 0.000 21.204 408.925 245.003 2.040 0.000 3.900 0.000 0.000 0.000 19.563 428.488 250.411 1.912 0.000 3.900 0.000 0.000 0.000 18.093 446.582 254.958 51.903 0.000 56.550 0.000 0.000 93.750 446.582 446.582 254.958 24.451 0.000 106.925 0.000 0.000 0.000 174.263 620.844 277.891 76.354 0.000 163.475 0.000 0.000 93.750 620.844 620.844 277.891 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 42.42 5.00 389.009 GROSS ULT., MB & MMF 47.100 217.241 DISCOUNT % 10.00 8.00 314.170 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 277.891 GROSS RES., MB & MMF 47.100 217.241 DISCOUNTED PAYOUT, YRS. 0.00 12.00 248.927 NET RES., MB & MMF 9.597 44.263 UNDISCOUNTED NET/INVEST. 7.62 15.00 215.156 NET REVENUE, M$ 838.454 115.969 DISCOUNTED NET/INVEST. 5.01 18.00 189.465 INITIAL PRICE, $ 87.370 2.620 RATE-OF-RETURN, PCT. 260.00 30.00 128.935 INITIAL N.I., PCT. 20.375 20.375 INITIAL W.I., PCT. 25.000 60.00 74.287 80.00 59.177 260.00 24.476 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 80 PALM 11-20DATE :04/01/2013FIELD: ALBIN WEST TIME :14:03:15COUNTY: BANNER STATE: NEDBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 MO-YEAR GROSS OILPRODUCTION---MBBLS--- GROSS GASPRODUCTION ---MMCF--- NET OILPRODUCTION---MBBLS--- NET GASPRODUCTION--- MMCF--- NET OILPRICE---$/BBL--- NET GASPRICE---$/MCF--- NETOIL SALES-- -M$--- NETGAS SALES ---M$--- TOTALNETSALES-- -M$--- 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 10.559 0.000 2.178 0.000 87.370 0.000 190.282 0.000 190.282 2015 13.693 0.000 2.824 0.000 87.370 0.000 246.748 0.000 246.748 2016 8.331 0.000 1.718 0.000 87.370 0.000 150.118 0.000 150.118 5.508 0.000 1.136 0.000 87.370 0.000 99.258 0.000 99.258 3.864 0.000 0.797 0.000 87.370 0.000 69.631 0.000 69.631 2019 2.833 0.000 0.584 0.000 87.370 0.000 51.059 0.000 51.059 2.150 0.000 0.444 0.000 87.370 0.000 38.751 0.000 38.751 1.678 0.000 0.346 0.000 87.370 0.000 30.230 0.000 30.230 1.338 0.000 0.276 0.000 87.370 0.000 24.119 0.000 24.119 1.088 0.000 0.224 0.000 87.370 0.000 19.608 0.000 19.608 0.899 0.000 0.185 0.000 87.370 0.000 16.196 0.000 16.196 2025 0.258 0.000 0.053 0.000 87.370 0.000 4.648 0.000 4.648 2026 S TOT 52.200 0.000 10.766 0.000 87.370 0.000 940.647 0.000 940.647 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 TOTAL 52.200 0.000 10.766 0.000 87.370 0.000 940.647 0.000 940.647 YEAR ADVALOREMTAX-----MS------ PRODUCTIONTAX-----MS------ DIRECTOPEREXPENSE-----MS------ INTEREST -----MS------ CAPITALREPAYMENT-----MS------ EQUITYINVESTMENT-----MS------ FUTURENETCASHFLOW-----MS------ CUMULATIVECASHFLOW-----MS------ TOTALNETSALES---M$--- 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 3.691 5.708 6.600 0.000 0.000 0.000 174.282 174.282 147.713 2015 4.787 7.402 13.200 0.000 0.000 0.000 221.358 395.640 323.000 2016 2.912 4.504 13.200 0.000 0.000 0.000 129.502 525.142 416.164 1.926 2.978 13.200 0.000 0.000 0.000 81.155 606.297 469.218 1.351 2.089 13.200 0.000 0.000 0.000 52.991 659.288 500.703 2019 0.991 1.532 13.200 0.000 0.000 0.000 35.336 694.625 519.789 0.752 1.163 13.200 0.000 0.000 0.000 23.636 718.261 531.395 0.586 0.907 13.200 0.000 0.000 0.000 15.536 733.797 538.331 0.468 0.724 13.200 0.000 0.000 0.000 9.728 743.525 542.282 0.380 0.588 13.200 0.000 0.000 0.000 5.440 748.965 544.293 0.314 0.486 13.200 0.000 0.000 0.000 2.196 751.161 545.035 2025 0.090 0.139 4.400 0.000 0.000 0.000 0.018 751.179 545.042 2026 S TOT 18.249 28.219 143.000 0.000 0.000 0.000 751.179 751.179 545.042 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 751.179 545.042 TOTAL 18.249 28.219 143.000 0.000 0.000 0.000 751.179 751.179 545.042 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 12.33 5.00 634.966 GROSS ULT., MB & MMF 52.200 0.000 DISCOUNT % 10.00 8.00 578.408 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 545.042 GROSS RES., MB & MMF 52.200 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 514.650 NET RES., MB & MMF 10.766 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 473.884 NET REVENUE, M$ 940.647 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 438.045 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 330.342 INITIAL N.I., PCT. 20.625 0.000 INITIAL W.I., PCT. 25.000 60.00 190.497 80.00 142.712 260.00 31.360 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 81 PALM 42-20DATE :04/01/2013FIELD: ALBIN WESTTIME :14:03:15COUNTY: BANNER STATE: NEDBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTION---MBBLS--- GROSS GASPRODUCTION MMCF--- NET OILPRODUCTION---MBBLS--- NET GASPRODUCTION MMCF--- NET OILPRICE---$/BBL--- NET GASPRICE---$/MCF--- NETOIL SALES-- -M$---- NETGAS SALES ---M$--- TOTAL NETSALES---M$--- 9.143 0.000 1.886 0.000 87.370 0.000 164.761 0.000 164.761 15.054 0.000 3.105 0.000 87.370 0.000 271.279 0.000 271.279 9.437 0.000 1.946 0.000 87.370 0.000 170.057 0.000 170.057 6.371 0.000 1.314 0.000 87.370 0.000 114.814 0.000 114.814 4.539 0.000 0.936 0.000 87.370 0.000 81.794 0.000 81.794 3.368 0.000 0.695 0.000 87.370 0.000 60.692 0.000 60.692 2.580 0.000 0.532 0.000 87.370 0.000 46.496 0.000 46.496 2.028 0.000 0.418 0.000 87.370 0.000 36.550 0.000 36.550 1.629 0.000 0.336 0.000 87.370 0.000 29.347 0.000 29.347 1.331 0.000 0.275 0.000 87.370 0.000 23.986 0.000 23.986 1.104 0.000 0.228 0.000 87.370 0.000 19.902 0.000 19.902 0.928 0.000 0.191 0.000 87.370 0.000 16.729 0.000 16.729 0.486 0.000 0.100 0.000 87.370 0.000 8.757 0.000 8.757 58.000 0.000 11.962 0.000 87.370 0.000 1045.163 0.000 1045.163 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 58.000 0.000 11.962 0.000 87.370 0.000 1045.163 0.000 1045.163 ADVALOREMTAX-----MS------ PRODUCTIONTAX DIRECTOPEREXPENSE-----MS------ INTEREST -----MS------ CAPITALREPAYMENT-----MS------ EQUITYINVESTMENT FUTURENETCASHFLOW CUMULATIVECASHFLOW CUM. DISC.CASHFLOW 3.196 4.943 5.500 0.000 0.000 0.000 151.122 151.122 140.262 5.263 8.138 13.200 0.000 0.000 0.000 244.677 395.799 353.322 3.299 5.102 13.200 0.000 0.000 0.000 148.456 544.256 470.772 2.227 3.444 13.200 0.000 0.000 0.000 95.942 640.198 539.749 1.587 2.454 13.200 0.000 0.000 0.000 64.553 704.751 581.930 1.177 1.821 13.200 0.000 0.000 0.000 44.494 749.245 608.356 0.902 1.395 13.200 0.000 0.000 0.000 30.999 780.244 625.094 0.709 1.096 13.200 0.000 0.000 0.000 21.544 801.788 635.670 0.569 0.880 13.200 0.000 0.000 0.000 14.697 816.486 642.230 0.465 0.720 13.200 0.000 0.000 0.000 9.601 826.086 646.128 0.386 0.597 13.200 0.000 0.000 0.000 5.719 831.805 648.241 0.325 0.502 13.200 0.000 0.000 0.000 2.703 834.508 649.151 0.170 0.263 8.800 0.000 0.000 0.000 -0.476 834.032 649.014 20.276 31.355 159.500 0.000 0.000 0.000 834.032 834.032 649.014 0.000 0.000 0.000 0.000 0.000 0.000 0.000 834.032 649.014 20.276 31.355 159.500 0.000 0.000 0.000 834.032 834.032 649.014 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 12.67 5.00 730.144GROSS ULT., MB & MMF 58.000 0.000 DISCOUNT % 10.00 8.00 679.217GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 649.014GROSS RES., MB & MMF 58.000 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 621.379NET RES., MB & MMF 11.962 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 584.085NET REVENUE, M$ 1045.163 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 551.041INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 449.673INITIAL N.I., PCT. 20.625 0.000 INITIAL W.I., PCT. 25.000 60.00 309.376 80.00 256.831 260.00 104.754 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 82 LARSON 24-20DATE :04/01/2013FIELD: RANCHERTIME :14:03:15COUNTY: KIMBALL STATE: NEDBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTION MMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTION MMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 8.757 0.000 1.916 0.000 87.370 0.000 167.366 0.000 167.366 7.545 0.000 1.650 0.000 87.370 0.000 144.199 0.000 144.199 5.858 0.000 1.281 0.000 87.370 0.000 111.956 0.000 111.956 4.837 0.000 1.058 0.000 87.370 0.000 92.451 0.000 92.451 4.146 0.000 0.907 0.000 87.370 0.000 79.245 0.000 79.245 3.644 0.000 0.797 0.000 87.370 0.000 69.648 0.000 69.648 3.261 0.000 0.713 0.000 87.370 0.000 62.326 0.000 62.326 2.958 0.000 0.647 0.000 87.370 0.000 56.537 0.000 56.537 2.359 0.000 0.516 0.000 87.370 0.000 45.078 0.000 45.078 1.137 0.000 0.249 0.000 87.370 0.000 21.736 0.000 21.736 0.061 0.000 0.013 0.000 87.370 0.000 1.159 0.000 1.159 44.563 0.000 9.748 0.000 87.370 0.000 851.702 0.000 851.702 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44.563 0.000 9.748 0.000 87.370 0.000 851.702 0.000 851.702 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW M$ M$ M$ M$ M$ M$ M$ M$ M$ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 3.247 5.021 11.000 0.000 0.000 0.000 148.098 148.098 127.720 2.797 4.326 13.200 0.000 0.000 0.000 123.876 271.973 225.621 2.172 3.359 13.200 0.000 0.000 0.000 93.226 365.199 292.558 1.794 2.774 13.200 0.000 0.000 0.000 74.684 439.883 341.289 1.537 2.377 13.200 0.000 0.000 0.000 62.130 502.013 378.134 1.351 2.089 13.200 0.000 0.000 0.000 53.007 555.020 406.707 1.209 1.870 13.200 0.000 0.000 0.000 46.047 601.067 429.269 1.097 1.696 13.200 0.000 0.000 0.000 40.544 641.612 447.327 0.875 1.352 13.200 0.000 0.000 0.000 29.651 671.263 459.400 0.422 0.652 13.200 0.000 0.000 0.000 7.462 678.725 462.191 0.022 0.035 1.100 0.000 0.000 0.000 0.002 678.728 462.191 16.523 25.551 130.900 0.000 0.000 0.000 678.728 678.728 462.191 0.000 0.000 0.000 0.000 0.000 0.000 0.000 678.728 462.191 16.523 25.551 130.900 0.000 0.000 0.000 678.728 678.728 462.191 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 11.08 5.00 553.935 GROSS ULT., MB & MMF 44.563 0.000 DISCOUNT % 10.00 8.00 495.712 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 462.191 GROSS RES., MB & MMF 44.563 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 432.214 NET RES., MB & MMF 9.748 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 392.861 NET REVENUE, M$ 851.702 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 359.099 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 262.525 INITIAL N.I., PCT. 21.875 0.000 INITIAL W.I., PCT. 25.000 60.00 148.158 80.00 111.635 260.00 28.189 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 83 OLIVERIUS 32-33DATE :04/01/2013FIELD: STATELINETIME :14:03:15COUNTY: BANNER STATE: NEDBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 15.050 0.000 2.897 0.000 87.370 0.000 253.130 0.000 253.130 13.303 0.000 2.561 0.000 87.370 0.000 223.735 0.000 223.735 5.770 0.000 1.111 0.000 87.370 0.000 97.043 0.000 97.043 3.100 0.000 0.597 0.000 87.370 0.000 52.137 0.000 52.137 1.888 0.000 0.363 0.000 87.370 0.000 31.756 0.000 31.756 0.884 0.000 0.170 0.000 87.370 0.000 14.866 0.000 14.866 39.995 0.000 7.699 0.000 87.370 0.000 672.666 0.000 672.666 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 39.995 0.000 7.699 0.000 87.370 0.000 672.666 0.000 672.666 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW M$ M$ M$ M$ M$ M$ M$ M$ M$ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 17.130 16.200 6.600 0.000 0.000 0.000 213.200 213.200 180.946 15.141 14.319 13.200 0.000 0.000 0.000 181.075 394.275 324.845 6.567 6.211 13.200 0.000 0.000 0.000 71.065 465.339 376.102 3.528 3.337 13.200 0.000 0.000 0.000 32.072 497.411 397.122 2.149 2.032 13.200 0.000 0.000 0.000 14.375 511.786 405.693 1.006 0.951 8.800 0.000 0.000 0.000 4.108 515.894 407.949 45.521 43.051 68.200 0.000 0.000 0.000 515.894 515.894 407.949 0.000 0.000 0.000 0.000 0.000 0.000 0.000 515.894 407.949 45.521 43.051 68.200 0.000 0.000 0.000 515.894 515.894 407.949 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 6.67 5.00 456.988 GROSS ULT., MB & MMF 39.995 0.000 DISCOUNT % 10.00 8.00 426.530 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 407.949 GROSS RES., MB & MMF 39.995 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 390.603 NET RES., MB & MMF 7.699 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 366.665 NET REVENUE, M$ 672.666 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 344.945 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 275.407 INITIAL N.I., PCT. 19.250 0.000 INITIAL W.I., PCT. 25.000 60.00 173.470 80.00 134.812 260.00 33.665 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 84 VRTATKO 44-22DATE :04/01/2013FIELD: SURGETIME :14:03:15COUNTY: KIIMBALL STATE: NEDBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 8.757 0.000 1.697 0.000 87.370 0.000 148.238 0.000 148.238 7.545 0.000 1.462 0.000 87.370 0.000 127.719 0.000 127.719 5.858 0.000 1.135 0.000 87.370 0.000 99.161 0.000 99.161 4.837 0.000 0.937 0.000 87.370 0.000 81.885 0.000 81.885 4.146 0.000 0.803 0.000 87.370 0.000 70.188 0.000 70.188 3.644 0.000 0.706 0.000 87.370 0.000 61.688 0.000 61.688 3.261 0.000 0.632 0.000 87.370 0.000 55.203 0.000 55.203 2.958 0.000 0.573 0.000 87.370 0.000 50.076 0.000 50.076 2.359 0.000 0.457 0.000 87.370 0.000 39.926 0.000 39.926 1.073 0.000 0.208 0.000 87.370 0.000 18.156 0.000 18.156 44.438 0.000 8.610 0.000 87.370 0.000 752.242 0.000 752.242 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44.438 0.000 8.610 0.000 87.370 0.000 752.242 0.000 752.242 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW M$ M$ M$ M$ M$ M$ M$ M$ M$ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 2.876 4.447 11.000 0.000 0.000 0.000 129.915 129.915 112.042 2.478 3.832 13.200 0.000 0.000 0.000 108.210 238.125 197.565 1.924 2.975 13.200 0.000 0.000 0.000 81.063 319.188 255.771 1.589 2.457 13.200 0.000 0.000 0.000 64.640 383.828 297.950 1.362 2.106 13.200 0.000 0.000 0.000 53.521 437.348 329.691 1.197 1.851 13.200 0.000 0.000 0.000 45.441 482.789 354.186 1.071 1.656 13.200 0.000 0.000 0.000 39.276 522.065 373.431 0.971 1.502 13.200 0.000 0.000 0.000 34.402 556.467 388.754 0.775 1.198 13.200 0.000 0.000 0.000 24.754 581.221 398.837 0.352 0.545 12.100 0.000 0.000 0.000 5.160 586.381 400.775 14.593 22.567 128.700 0.000 0.000 0.000 586.381 586.381 400.775 0.000 0.000 0.000 0.000 0.000 0.000 0.000 586.381 400.775 14.593 22.567 128.700 0.000 0.000 0.000 586.381 586.381 400.775 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 10.92 5.00 479.530 GROSS ULT., MB & MMF 44.438 0.000 DISCOUNT % 10.00 8.00 429.572 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 400.775 GROSS RES., MB & MMF 44.438 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 374.999 NET RES., MB & MMF 8.610 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 341.125 NET REVENUE, M$ 752.242 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 312.031 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 228.613 INITIAL N.I., PCT. 19.375 0.000 INITIAL W.I., PCT. 25.000 60.00 129.389 80.00 97.588 260.00 24.703 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 85 LUKASSEN 42-7 NE TERRESTRIAL WYKDATE :04/01/2013 TIME :14:03:15 DBS :DEMO SETTINGS :RED_JAN13 SCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTION MMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTION MMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 5.387 0.000 1.010 0.000 87.370 0.000 88.246 0.000 88.246 7.474 0.000 1.401 0.000 87.370 0.000 122.439 0.000 122.439 5.653 0.000 1.060 0.000 87.370 0.000 92.600 0.000 92.600 4.722 0.000 0.885 0.000 87.370 0.000 77.352 0.000 77.352 4.132 0.000 0.775 0.000 87.370 0.000 67.689 0.000 67.689 3.704 0.000 0.694 0.000 87.370 0.000 60.677 0.000 60.677 3.334 0.000 0.625 0.000 87.370 0.000 54.610 0.000 54.610 3.000 0.000 0.563 0.000 87.370 0.000 49.149 0.000 49.149 2.700 0.000 0.506 0.000 87.370 0.000 44.234 0.000 44.234 2.430 0.000 0.456 0.000 87.370 0.000 39.810 0.000 39.810 2.187 0.000 0.410 0.000 87.370 0.000 35.829 0.000 35.829 1.968 0.000 0.369 0.000 87.370 0.000 32.246 0.000 32.246 1.772 0.000 0.332 0.000 87.370 0.000 29.022 0.000 29.022 1.594 0.000 0.299 0.000 87.370 0.000 26.120 0.000 26.120 1.435 0.000 0.269 0.000 87.370 0.000 23.508 0.000 23.508 51.492 0.000 9.655 0.000 87.370 0.000 843.532 0.000 843.532 4.876 0.000 0.914 0.000 87.370 0.000 79.882 0.000 79.882 56.368 0.000 10.569 0.000 87.370 0.000 923.414 0.000 923.414 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW M$ M$ M$ M$ M$ M$ M$ M$ M$ 1.712 2.647 6.600 0.000 0.000 0.000 77.287 77.287 72.071 2.375 3.673 13.200 0.000 0.000 0.000 103.190 180.477 161.837 1.796 2.778 13.200 0.000 0.000 0.000 74.826 255.303 220.937 1.501 2.321 13.200 0.000 0.000 0.000 60.331 315.634 264.234 1.313 2.031 13.200 0.000 0.000 0.000 51.146 366.780 297.593 1.177 1.820 13.200 0.000 0.000 0.000 44.480 411.260 323.965 1.059 1.638 13.200 0.000 0.000 0.000 38.712 449.972 344.831 0.953 1.474 13.200 0.000 0.000 0.000 33.521 483.492 361.257 0.858 1.327 13.200 0.000 0.000 0.000 28.849 512.341 374.109 0.772 1.194 13.200 0.000 0.000 0.000 24.644 536.985 384.090 0.695 1.075 13.200 0.000 0.000 0.000 20.859 557.844 391.772 0.626 0.967 13.200 0.000 0.000 0.000 17.453 575.298 397.615 0.563 0.871 13.200 0.000 0.000 0.000 14.388 589.686 401.995 0.507 0.784 13.200 0.000 0.000 0.000 11.629 601.315 405.214 0.456 0.705 13.200 0.000 0.000 0.000 9.146 610.461 407.516 16.365 25.306 191.400 0.000 0.000 0.000 610.461 610.461 407.516 1.550 2.396 59.400 0.000 0.000 0.000 16.536 626.997 410.984 17.914 27.702 250.800 0.000 0.000 0.000 626.997 626.997 410.984 OIL GAS P.W. % P.W., M$ - - -- GROSS WELLS 1.0 0.0 LIFE, YRS. 19.50 5.00 497.302 GROSS ULT., MB & MMF 56.368 0.000 DISCOUNT % 10.00 8.00 441.693 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 410.984 GROSS RES., MB & MMF 56.368 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 384.286 NET RES., MB & MMF 10.569 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 350.263 NET REVENUE, M$ 923.414 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 321.932 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 244.481 INITIAL N.I., PCT. 18.750 0.000 INITIAL W.I., PCT. 25.000 60.00 156.170 80.00 127.309 260.00 51.841 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 86 LUKASSEN 44-18 NE TERRESTRIAL WYDATE :04/01/2013 TIME :14:03:16 DBS :DEMO SETTINGS :RED_JAN13 SCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 5.387 0.000 1.010 0.000 87.370 0.000 88.246 0.000 88.246 7.474 0.000 1.401 0.000 87.370 0.000 122.439 0.000 122.439 5.653 0.000 1.060 0.000 87.370 0.000 92.600 0.000 92.600 4.722 0.000 0.885 0.000 87.370 0.000 77.352 0.000 77.352 4.132 0.000 0.775 0.000 87.370 0.000 67.689 0.000 67.689 3.704 0.000 0.694 0.000 87.370 0.000 60.677 0.000 60.677 3.334 0.000 0.625 0.000 87.370 0.000 54.610 0.000 54.610 3.000 0.000 0.563 0.000 87.370 0.000 49.149 0.000 49.149 2.700 0.000 0.506 0.000 87.370 0.000 44.234 0.000 44.234 2.430 0.000 0.456 0.000 87.370 0.000 39.810 0.000 39.810 2.187 0.000 0.410 0.000 87.370 0.000 35.829 0.000 35.829 1.968 0.000 0.369 0.000 87.370 0.000 32.246 0.000 32.246 1.772 0.000 0.332 0.000 87.370 0.000 29.022 0.000 29.022 1.594 0.000 0.299 0.000 87.370 0.000 26.120 0.000 26.120 1.435 0.000 0.269 0.000 87.370 0.000 23.508 0.000 23.508 51.492 0.000 9.655 0.000 87.370 0.000 843.532 0.000 843.532 4.876 0.000 0.914 0.000 87.370 0.000 79.882 0.000 79.882 56.368 0.000 10.569 0.000 87.370 0.000 923.414 0.000 923.414 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW M$ M$ M$ M$ M$ M$ M$ M$ M$ 1.712 2.647 6.600 0.000 0.000 0.000 77.287 77.287 72.071 2.375 3.673 13.200 0.000 0.000 0.000 103.190 180.477 161.837 1.796 2.778 13.200 0.000 0.000 0.000 74.826 255.303 220.937 1.501 2.321 13.200 0.000 0.000 0.000 60.331 315.634 264.234 1.313 2.031 13.200 0.000 0.000 0.000 51.146 366.780 297.593 1.177 1.820 13.200 0.000 0.000 0.000 44.480 411.260 323.965 1.059 1.638 13.200 0.000 0.000 0.000 38.712 449.972 344.831 0.953 1.474 13.200 0.000 0.000 0.000 33.521 483.492 361.257 0.858 1.327 13.200 0.000 0.000 0.000 28.849 512.341 374.109 0.772 1.194 13.200 0.000 0.000 0.000 24.644 536.985 384.090 0.695 1.075 13.200 0.000 0.000 0.000 20.859 557.844 391.772 0.626 0.967 13.200 0.000 0.000 0.000 17.453 575.298 397.615 0.563 0.871 13.200 0.000 0.000 0.000 14.388 589.686 401.995 0.507 0.784 13.200 0.000 0.000 0.000 11.629 601.315 405.214 0.456 0.705 13.200 0.000 0.000 0.000 9.146 610.461 407.516 16.365 25.306 191.400 0.000 0.000 0.000 610.461 610.461 407.516 1.550 2.396 59.400 0.000 0.000 0.000 16.536 626.997 410.984 17.914 27.702 250.800 0.000 0.000 0.000 626.997 626.997 410.984 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 19.50 5.00 497.302 GROSS ULT., MB &MMF 56.368 0.000 DISCOUNT % 10.00 8.00 441.693 GROSS CUM., MB &MMF 0.000 0.000 UNDISCOUNTED PAYOUT,YRS. 0.00 10.00 410.984 GROSS RES., MB &MMF 56.368 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 384.286 NET RES., MB & MMF 10.569 0.000 UNDISCOUNTEDNET/INVEST. 0.00 15.00 350.263 NET REVENUE, M$ 923.414 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 321.932 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 244.481 INITIAL N.I., PCT. 18.750 0.000 INITIAL W.I., PCT. 25.000 60.00 156.170  80.00 127.309 260.00 51.841 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 87 WILKE 44A-5DATE :04/01/2013FIELD: WILKETIME :14:03:16COUNTY: KIIMBALL STATE: NEDBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 --END--MO-YEAR GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTION MMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTION MMCF NET OILPRICE$/BBL NETGASPRICE$/MCF NETOILSALESM$ NETGASSALESM$ TOTALNETSALESM$ 12-2013 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 12-2014 11.887 0.000 2.028 0.000 87.370 0.000 177.206 0.000 177.206 12-2015 11.212 0.000 1.913 0.000 87.370 0.000 167.150 0.000 167.150 12-2016 6.995 0.000 1.193 0.000 87.370 0.000 104.272 0.000 104.272 12-2017 4.706 0.000 0.803 0.000 87.370 0.000 70.158 0.000 70.158 12-2018 3.344 0.000 0.571 0.000 87.370 0.000 49.854 0.000 49.854 12-2019 2.477 0.000 0.423 0.000 87.370 0.000 36.919 0.000 36.919 12-2020 1.894 0.000 0.323 0.000 87.370 0.000 28.240 0.000 28.240 12-2021 1.487 0.000 0.254 0.000 87.370 0.000 22.170 0.000 22.170 12-2022 0.997 0.000 0.170 0.000 87.370 0.000 14.868 0.000 14.868 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT 45.000 0.000 7.678 0.000 87.370 0.000 670.838 0.000 670.838 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 TOTAL 45.000 0.000 7.678 0.000 87.370 0.000 670.838 0.000 670.838 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. --END-- TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW MO-YEAR M$ M$ M$ M$ M$ M$ M$ M$ M$ 12-2013 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 12-2014 3.438 5.316 8.800 0.000 0.000 0.000 159.652 159.652 136.536 12-2015 3.243 5.015 13.200 0.000 0.000 0.000 145.693 305.345 251.891 12-2016 2.023 3.128 13.200 0.000 0.000 0.000 85.921 391.267 313.703 12-2017 1.361 2.105 13.200 0.000 0.000 0.000 53.492 444.759 348.677 12-2018 0.967 1.496 13.200 0.000 0.000 0.000 34.191 478.950 368.997 12-2019 0.716 1.108 13.200 0.000 0.000 0.000 21.895 500.845 380.827 12-2020 0.548 0.847 13.200 0.000 0.000 0.000 13.645 514.490 387.532 12-2021 0.430 0.665 13.200 0.000 0.000 0.000 7.875 522.365 391.053 12-2022 0.288 0.446 11.000 0.000 0.000 0.000 3.134 525.498 392.340 12-2023 12-2024 12-2025 12-2026 12-2027 S TOT 13.014 20.125 112.200 0.000 0.000 0.000 525.498 525.498 392.340 AFTER 0.000 0.000 0.000 0.000 0.000 0.000 0.000 525.498 392.340 TOTAL 13.014 20.125 112.200 0.000 0.000 0.000 525.498 525.498 392.340 OIL GAS P.W. % P.W., M$ - - -- GROSS WELLS 1.0 0.0 LIFE, YRS. 9.83 5.00 451.098 GROSS ULT., MB & MMF 45.000 0.000 DISCOUNT % 10.00 8.00 414.269 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 392.340 GROSS RES., MB & MMF 45.000 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 372.232 NET RES., MB & MMF 7.678 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 345.052 NET REVENUE, M$ 670.838 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 320.953 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 247.302 INITIAL N.I., PCT. 17.062 0.000 INITIAL W.I., PCT. 25.000 60.00 148.445 80.00 113.570 260.00 28.068  RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 88 MALM 32-34DATE :04/01/2013FIELD: ALBIN WESTTIME :14:03:16COUNTY: LARAMIE STATE: WYDBS :DEMOOPERATOR: RECOVERY ENERGY COMPASETTINGS :RED_JAN133PUDSCENARIO :RED_JAN13 R E S E R V E S A N D E C O N O M I C S AS OF DATE: 12/31/2012 GROSS OILPRODUCTIONMBBLS GROSS GASPRODUCTIONMMCF NET OILPRODUCTIONMBBLS NET GASPRODUCTIONMMCF NET OILPRICE$/BBL NET GASPRICE$/MCF NETOIL SALESM$ NETGAS SALESM$ TOTAL NETSALESM$ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 18.417 0.000 3.637 0.000 87.370 0.000 317.801 0.000 317.801 11.533 0.000 2.278 0.000 87.370 0.000 199.011 0.000 199.011 7.781 0.000 1.537 0.000 87.370 0.000 134.263 0.000 134.263 5.540 0.000 1.094 0.000 87.370 0.000 95.596 0.000 95.596 4.109 0.000 0.812 0.000 87.370 0.000 70.903 0.000 70.903 3.147 0.000 0.622 0.000 87.370 0.000 54.301 0.000 54.301 2.473 0.000 0.488 0.000 87.370 0.000 42.673 0.000 42.673 1.985 0.000 0.392 0.000 87.370 0.000 34.256 0.000 34.256 1.622 0.000 0.320 0.000 87.370 0.000 27.992 0.000 27.992 1.346 0.000 0.266 0.000 87.370 0.000 23.223 0.000 23.223 1.131 0.000 0.223 0.000 87.370 0.000 19.518 0.000 19.518 0.961 0.000 0.190 0.000 87.370 0.000 16.591 0.000 16.591 0.564 0.000 0.111 0.000 87.370 0.000 9.727 0.000 9.727 60.610 0.000 11.970 0.000 87.370 0.000 1045.854 0.000 1045.854 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 60.610 0.000 11.970 0.000 87.370 0.000 1045.854 0.000 1045.854 ADVALOREM PRODUCTION DIRECTOPER INTEREST CAPITAL EQUITY FUTURENET CUMULATIVE CUM. DISC. TAX TAX EXPENSE PAID REPAYMENT INVESTMENT CASHFLOW CASHFLOW CASHFLOW M$ M$ M$ M$ M$ M$ M$ M$ M$ 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 6.165 9.534 13.200 0.000 0.000 0.000 288.901 288.901 251.563 3.861 5.970 13.200 0.000 0.000 0.000 175.980 464.881 390.783 2.605 4.028 13.200 0.000 0.000 0.000 114.430 579.311 473.047 1.855 2.868 13.200 0.000 0.000 0.000 77.674 656.985 523.797 1.376 2.127 13.200 0.000 0.000 0.000 54.201 711.186 555.986 1.053 1.629 13.200 0.000 0.000 0.000 38.418 749.604 576.726 0.828 1.280 13.200 0.000 0.000 0.000 27.365 776.969 590.156 0.665 1.028 13.200 0.000 0.000 0.000 19.363 796.333 598.796 0.543 0.840 13.200 0.000 0.000 0.000 13.409 809.742 604.237 0.451 0.697 13.200 0.000 0.000 0.000 8.875 818.617 607.512 0.379 0.586 13.200 0.000 0.000 0.000 5.354 823.971 609.310 0.322 0.498 13.200 0.000 0.000 0.000 2.571 826.542 610.097 0.189 0.292 8.800 0.000 0.000 0.000 0.446 826.989 610.224 20.290 31.376 167.200 0.000 0.000 0.000 826.989 826.989 610.224 0.000 0.000 0.000 0.000 0.000 0.000 0.000 826.989 610.224 20.290 31.376 167.200 0.000 0.000 0.000 826.989 826.989 610.224 OIL GAS P.W. % P.W., M$ GROSS WELLS 1.0 0.0 LIFE, YRS. 13.67 5.00 704.105 GROSS ULT., MB & MMF 60.610 0.000 DISCOUNT % 10.00 8.00 644.949 GROSS CUM., MB & MMF 0.000 0.000 UNDISCOUNTED PAYOUT, YRS. 0.00 10.00 610.224 GROSS RES., MB & MMF 60.610 0.000 DISCOUNTED PAYOUT, YRS. 0.00 12.00 578.694 NET RES., MB & MMF 11.970 0.000 UNDISCOUNTED NET/INVEST. 0.00 15.00 536.526 NET REVENUE, M$ 1045.854 0.000 DISCOUNTED NET/INVEST. 0.00 18.00 499.548 INITIAL PRICE, $ 87.370 0.000 RATE-OF-RETURN, PCT. 260.00 30.00 388.582 INITIAL N.I., PCT. 19.750 0.000 INITIAL W.I., PCT. 25.000 60.00 242.569 80.00 190.922 260.00 57.542 RALPH E. DAVIS ASSOCIATES, INC.Texas Registered Engineering Firm F-1529 89 This Page Is Intentionally Left Blank 90 Certificate ofQualifications Certificate of Qualifications 91 CERTIFICATE OF QUALIFICATION I, Allen C. Barron, of 1717 St. James Place, Suite 460, Houston, Texas 77056 hereby certify: 1.I am an employee of Ralph E. Davis Associates, Inc., that has prepared an estimate of the oil and natural gas reserves on specific leaseholds inwhich Recovery Energy Company, Inc. has certain interests. The effective date of this evaluation is December 31, 2012. 2.I am Licensed Professional Engineer by the State of Texas, P.E. License number 48284. 3.I attended the University of Houston in Houston, Texas and graduated with a Bachelor of Science Degree in Chemical Engineering with a PetroleumEngineering option in 1968. I have in excess of forty-four years experience in the Petroleum Industry of which over thirty-four years of experienceare in the conduct of evaluation and engineering studies relating to both domestic U.S. oil and gas fields and international energy assets. 4. I have prepared reserve evaluation studies and reserve audits for public and private companies for the purpose of reserve certification filings inforeign countries, domestic regulatory filings, financial disclosures and corporate strategic planning. I personally supervised and participated inthe evaluation of the Recovery Energy Company, Inc. properties that are the subject of this report. 5.I do not have, nor do I expect to receive, any direct or indirect interest in the securities of Recovery Energy Company, Inc. or any affiliatedcompanies. 6.A personal field inspection of the properties was not made, however, such an inspection was not considered necessary in view of the informationavailable from public information, records and the files of the operator of the properties. SIGNED: April 3, 2013 /s/ Allen C. Barron Allen C. Barron, P.E. President Ralph E. Davis Associates, Inc. 92

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