S-1 1 fs12013_recovery.htm REGISTRATION STATEMENT fs12013_recovery.htm
 


As filed with the Securities and Exchange Commission on January 18, 2013
Registration No. 333-

United States
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________

FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
______________________

RECOVERY ENERGY, INC.
(Exact name of registrant as specified in its charter)

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

A. Bradley Gabbard
President and Chief Financial Officer
Recovery Energy, Inc.
1900 Grant Street, Suite #720
Denver, CO   80203
1-888-887-4449
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices and agent for service)

Copies to:
Ronald R. Levine, II, Esq.
Davis Graham & Stubbs LLP
1550 Seventeenth Street, Suite 500
Denver, CO 80202



 
Approximate date of commencement of proposed sale to public: as soon as practicable after the registration statement becomes effective.
 
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. x
 
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earliest effective registration statement for the same offering.  o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer.  o
 
Accelerated Filer.  o
Non-accelerated filer.  o
Smaller reporting company.  x

CALCULATION OF REGISTRATION FEE

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

(1)
Represents (a) 1,176,483 shares of common stock that may be offered by us to the holders of an aggregate principal amount of $5,000,000 of our 8% Senior Secured Debentures due February 8, 2014 (the “Debentures”) in the event of conversion of the Debentures (at a conversion price of $4.25 per share), (b) 423,517 shares of common stock that may be offered by us to holders of the Debentures as interest payments in connection with the Debentures (at a conversion price equal to the fair market value of such shares on the date of the interest payment), (c) 30,096 shares of common stock issued previously on a restricted basis to holders of the Debentures as interest payments and being registered for resale on behalf of such holders and (d) pursuant to Rule 416 under the Securities Act, an indeterminate number of shares of common stock that are issuable upon stock splits, stock dividends, recapitalizations or other similar transactions affecting such shares.
 
(2)
Estimated solely for the purpose of determining the registration fee pursuant to Rule 457 promulgated under the Securities Act of 1933, as amended (the “Securities Act”), based upon the high and low prices of the common stock of Recovery Energy, Inc. (the “Registrant”) as quoted on the Nasdaq Global Market on January 14, 2013.

The information in this prospectus is not complete and may be changed without notice.  The shares of common stock offered hereby may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and Recovery Energy, Inc. is not soliciting offers to buy these securities, in any state where the offer or sale of these securities is not permitted.
 
Recovery Energy, Inc. hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
 
 
The information in this prospectus is not complete and may be changed. We and the selling stockholder may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and we and the selling stockholder are not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to completion, dated January 18, 2013
 
1,630,096 shares of Common Stock

RECOVERY ENERGY, INC.

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

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

Our common stock is quoted on the Nasdaq Global Market under the symbol “RECV”.   On January 17, 2013, the last reported sale price of our common stock was $2.25 per share.
 
Investing in our common stock involves a high degree of risk. Please carefully consider the “Risk Factors” beginning on page 3 of this prospectus.
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved the securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
 
The date of this prospectus is _________, 2013.
 
 
 
 
We have not authorized any dealer, salesperson or other person to give any information or represent anything not contained in this prospectus.  You should not rely on any unauthorized information.  This prospectus does not offer to sell or buy any shares in any jurisdiction in which it is unlawful.  The information in this prospectus is current as of the date on the cover.  You should rely only on the information contained or incorporated by reference in this prospectus.
 
 

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

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

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

estimated quantities and quality of oil and natural gas reserves;
exploration, exploitation and development results;
fluctuations in the price of oil and natural gas, including reductions in prices that would adversely affect our revenue, cash flow, liquidity, reserves and access to capital;
availability of capital on an economic basis, or at all, to fund our capital needs;
availability of, or delays related to, drilling, completion and production, personnel, supplies and equipment;
the timing and amount of future production of oil and gas;
the completion, timing and success of our drilling activity;
the inability of management to effectively implement our strategies and business plans;
potential default under our secured obligations or material debt agreements;
lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements;
declines in the values of our natural gas and oil properties resulting in write-downs;
inability to hire or retain sufficient qualified operating field personnel;
increases in interest rates or our cost of borrowing;
deterioration in general or regional (especially Rocky Mountain) economic conditions;
the strength and financial resources of our competitors;
the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;
inability to acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts;
delays, denials or other problems relating to our receipt of operational consents and approvals from governmental entities and other parties
unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids;
environmental liabilities;
loss of senior management or technical personnel;
adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations;
changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate; and
other factors, many of which are beyond our control.
   
Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.

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

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

Overview of Our Business

Recovery Energy, Inc. (NASDAQ: RECV), sometimes referred to in this prospectus as “we,” “us,” “our,” “Recovery Energy,” “Recovery,” or the “Company,” is a Denver based independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. Our current activities are focused on the Denver-Julesburg (“DJ”) Basin in Colorado, Wyoming and Nebraska. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team and via the future exploration and development of the approximate 125,000 net acres of developed and undeveloped leases that are currently held by the Company, primarily in the northern DJ Basin.
 
We have developed and acquired an oil and natural gas base of proved reserves, as well as a portfolio of exploration and development prospects with high-impact conventional and non-conventional reservoir opportunities with an emphasis on multiple producing horizons and the Niobrara, Codell and Greenhorn shale resource plays. Since early 2010, we have acquired and/or developed 29 producing wells. As of December 31, 2011 we owned interests in approximately 140,000 gross (125,000 net) leasehold acres, of which 118,000 gross (103,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska in the DJ Basin.  We intend to continue to evaluate and invest in acquisitions and internally generated prospects in the DJ Basin and elsewhere.  It is our long-term goal to maximize our DJ Basin acreage position through development drilling of our conventional horizons as well as development of our Niobrara shale potential.
 
We were incorporated in August of 2007 in the State of Nevada as Universal Holdings, Inc.  In October 2009, we changed our name to Recovery Energy, Inc.  Our executive offices are located at 1900 Grant Street, Suite #720, Denver, CO 80203.  Our telephone number is 1-303-951-7920.  Our website is www.recoveryenergyco.com.  The information on our website is not intended to be a part of this prospectus, and you should not rely on any of the information provided there in making your decision to invest in our common stock.
 
The Offering
 
The shares offered hereby consist of (a) 1,176,483 shares of common stock that may be offered by us to the holders of an aggregate principal amount of $5,000,000 of our 8% Senior Secured Debentures due February 8, 2014 (the “Debentures”) in the event of conversion of the Debentures (at a conversion price of $4.25 per share), (b) 423,517 shares of common stock that may be offered by us to holders of the Debentures as interest payments in connection with the Debentures (at a conversion price equal to the fair market value of such shares on the date of the interest payment), and (c) 30,096 shares of common stock issued previously on a restricted basis to holders of the Debentures as interest payments and being registered for resale on behalf of such holders.
 
 
Investing in our shares involves significant risks, including the potential loss of all or part of your investment.  These risks could materially affect our business, financial condition and results of operations and cause a decline in the market price of our shares.  You should carefully consider all of the risks described in this prospectus, in addition to the other information contained in this prospectus, before you make an investment in our shares. In addition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors, include the following:
 
Risks Related to Our Company
 
We have historically incurred losses and cannot assure investors as to future profitability. We have historically incurred losses from operations during our history in the oil and natural gas business. We had a cumulative deficit of approximately $68.0 million as of December 31, 2011 and $81 million for September 30, 2012. Many of our properties are in the exploration stage, and to date we have established a limited volume of proved reserves on our properties. Our ability to be profitable in the future will depend on successfully implementing our acquisition, exploration, development and production activities, all of which are subject to many risks beyond our control. Even if we become profitable on an annual basis, we cannot assure you that our profitability will be sustainable or increase on a periodic basis. In addition, should we be unable to continue as a going concern, realization of assets and settlement of liabilities in other than the normal course of business may be at amounts significantly different from those in the financial statements included in this prospectus.
 
 
Our credit agreements mature on December 31, 2013, and our lender can foreclose on several of our properties if we do not pay off or refinance our approximately $19.5 million of loans. Some of our oil and gas properties, including many of our producing properties,  are pledged as collateral for our credit agreements. Failure to repay these loans at maturity or refinance them could cause a default under the credit agreements and allow the lender to foreclose on these properties.

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

Currently, the majority of our revenue after field level operating expenses is required to be paid to our lender as debt service. The terms of our credit agreements require us to pay a significant portion of our operating cash flow as debt service. In 2011, we paid $842,000 in principal and $3,156,000 in interest pursuant to such requirements, representing approximately 700% of our cash flow from operations, and in 2012, we paid $0.68 million in principal and $3.22 million in interest. In 2011, our lender deferred the payment of approximately $2 million of revenue toward debt service, and there can be no assurance that our lender will continue to permit deferrals. As of September 30, 2012, we had working capital of ($0.90) million.  In February 2012, we completed the sale of certain rights in our Grover field property for $4.5 million, and in December 2012 we granted a four-year lease for the deep rights on approximately 6,300 net acres of our undeveloped leasehold acreage in the Denver-Julesburg Basin for approximately $1.5 million. Additionally, we will seek to obtain additional capital through the sale of our equity or debt securities, the successful deployment of our cash on hand, bank lines of credit, joint ventures, and project financing. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price could be materially adversely affected.
 
We will require additional capital in order to achieve commercial success and, if necessary, to finance future losses from operations as we endeavor to build revenue, but we do not have any commitments to obtain such capital and we cannot assure you that we will be able to obtain adequate capital as and when required. The business of oil and gas acquisition, drilling and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. We believe that our ability to achieve commercial success and our continued growth will be dependent on our continued access to capital either through the additional sale of our equity or debt securities, bank lines of credit, project financing, joint ventures, sale or lease of undeveloped properties, or cash generated from oil and gas operations.
 
We do not have a significant operating history and, as a result, there is a limited amount of information about us on which to make an investment decision. In January 2010, we acquired our first oil and gas prospects and received our first revenues from oil and gas production in February 2010. In November 2012, our chairman and chief executive officer retired, and we appointed W. Phillip Marcum to the position of chairman and chief executive officer, and appointed A. Bradley Gabbard to the position of president (in addition to his current position as chief financial officer). Accordingly, there is little operating history upon which to judge our business strategy, our management team or our current operations.
  
We have limited management and staff and will be dependent upon partnering arrangements. We have seven employees. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:
 
the possibility that such third parties may not be available to us as and when needed; and
the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.
 
If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price could be materially adversely affected.
 
 
The loss of our chief executive officer or our president and chief financial officer could adversely affect us. We are dependent on the experience of our executive officers to implement our operational objectives and growth strategy. The loss of the services of either of these individuals could have a negative impact on our operations and our ability to implement our strategy.
 
We experienced a material weakness in our disclosure controls and systems. In our Annual Report on Form 10K/A for the year ended December 31, 2011, we noted that the following material weaknesses in our internal control over financial reporting existed as of December 31, 2011:

Insufficient independent internal review and approval of critical accounting schedules used in the preparation of financial statements.
The financial statement close process did not permit timely preparation of necessary financial information and there is inadequate documentation of internal controls for some assertions in certain significant accounts.
Lack of effective controls over general ledger processing, spreadsheets and data back-up.

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

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

Remediation Activities:

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

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

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

Other than as noted above, there were no other changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
In addition to acquiring producing properties, we may also grow our business through the acquisition and development of exploratory oil and gas prospects, which is the riskiest method of establishing oil and gas reserves. In addition to acquiring producing properties, we may acquire, drill and develop exploratory oil and gas prospects that are profitable to produce. Developing exploratory oil and gas properties requires significant capital expenditures and involves a high degree of financial risk. The budgeted costs of drilling, completing, and operating exploratory wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an exploratory oil or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. We cannot assure you that our exploration, exploitation and development activities will result in profitable operations. If we are unable to successfully acquire and develop exploratory oil and gas prospects, our results of operations, financial condition and stock price may be materially adversely affected.
 
 
If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, wells in progress are deemed unsuccessful, or major tracts of undeveloped leases expire, or other similar adverse events occur, we may be required to write-down the carrying value of our evaluated properties.
 
We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling wells, completing productive wells, or plugging and abandoning non-productive wells, costs related to expired leases, or leases underlying  producing and non-producing wells, and overhead charges directly related to acquisition and exploration activities.  Under the full cost method of accounting, capitalized oil and natural gas property that comprise the full cost pool, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves.  This ceiling test is performed at least quarterly.  Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize impairment expense.  Effective with our report on Form 10-Q for the quarter ended March 31, 2012, we recognized impairment expenses in the amount of approximately $3.3 million related to impairment of the carrying value of the evaluated properties that comprised the full cost pool.  Future write-downs could occur for numerous reasons, including, but not limited to reductions in oil and gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserve estimates, or from the addition of non-productive capitalized costs to the full cost pool that do not result in corresponding increase in oil and gas reserves.  Impairments of undeveloped leases and plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full cost pool, without any corresponding increase in reserve values; as such, these situations could result in future additional impairment expenses.

Hedging transactions may limit our potential gains or result in losses. In order to manage our exposure to price risks in the marketing of our oil and natural gas, from time to time, we may enter into derivative contracts that economically hedge our oil and gas price on a portion of our production. These contracts may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: 
 
there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;
our production and/or sales of oil or natural gas are less than expected;
payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
the other party to the hedging contract defaults on its contract obligations.
 
Hedging transactions we may enter into may not adequately protect us from declines in the prices of oil and natural gas. Further, where we choose not to engage in hedging transactions, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

Our large inventory of undeveloped acreage and large percentage of undeveloped proved reserves may create additional economic risk.  Our success is largely dependent upon our ability to develop our large inventory of future drilling locations, undeveloped acreage and undeveloped reserves. As of December 31, 2011, approximately 47% of our total proved reserves were undeveloped.  To the extent our drilling results are not as successful as we anticipate, natural gas and oil prices decline, or sufficient funds are not available to drill these locations and reserves, we may not capture the expected or projected value of these properties. In addition, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.
 
We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations. Significant growth in the size and scope of our operations would place a strain on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
 
 
The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, the present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. This prospectus contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves contained in our filings with the SEC. The December 31, 2011, reserve estimate was prepared by our current reserve engineer consultant and audited by RE Davis. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development and operating expenses, and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control. You should also not assume that our initial rates of production of our wells will lead to greater overall production over the life of the wells, or that early results suggesting lack of reservoir continuity will prove to be accurate.
 
You should not assume that the present value of future net revenues referred to in this prospectus is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the un-weighted average of the closing prices during the first day of each of the twelve months preceding the end of the fiscal year. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any change in consumption by oil or natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of our oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor nor does it reflect discount factors used in the market place for the purchase and sale of oil and natural gas.
 
Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.   One of our growth strategies is to pursue selective acquisitions of undeveloped leasehold oil and natural gas reserves. If we choose to pursue an acquisition, we will perform a review of the target properties; however, these reviews are inherently incomplete. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties.
  
All of our producing properties and operations are located in the DJ Basin region, making us vulnerable to risks associated with operating in one major geographic area.  All of our estimated proved reserves at December 31, 2011, and our 2010, 2011 and 2012 sales were generated in the DJ Basin in southeastern Wyoming, northeastern Colorado and southwestern Nebraska. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the DJ Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
 
Unless we find new oil and gas reserves, our reserves and production will decline, which would materially and adversely affect our business, financial condition and results of operations. Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Thus, our future oil and gas reserves and production and, therefore, our cash flow and revenue are highly dependent on our success in efficiently obtaining reserves and acquiring additional recoverable reserves. We may not be able to develop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would be materially and adversely affected.
 
 
Part of our strategy involves drilling in existing or emerging unconventional shale plays using available horizontal drilling and completion techniques. The results of our planned exploratory and development drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.  Unconventional operations involve utilizing drilling and completion techniques as developed by ourselves and our service providers. Risks that we face while drilling include, but are not limited to, landing our wellbore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the wellbore and being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the wellbore during completion operations and successfully cleaning out the wellbore after completion of the final fracture stimulation stage.
 
Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Niobrara is limited. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and the value of our undeveloped acreage could decline in the future.
  
The unavailability or high cost of drilling rigs, equipment supplies or personnel could adversely affect our ability to execute our exploration and development plans. The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies may increase substantially and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. The higher prices of oil and gas during the last several years have resulted in shortages of drilling rigs, equipment and personnel, which have resulted in increased costs and shortages of equipment in the areas where we operate. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our financial condition and results of operations could be materially and adversely affected.
 
Covenants in our credit agreements impose significant restrictions and requirements on us. Our three credit agreements contain a number of covenants imposing significant restrictions on us, including restrictions on our repurchase of, and payment of dividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets and create liens on our assets. These restrictions may affect our ability to operate our business, to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial conditions and results of operations.
 
We could be required to pay liquidated damages to some of our investors if we fail to maintain the effectiveness of a prior registration statement. We could default and accrue liquidated damages under registration rights agreements covering approximately 3.2 million shares of our common stock if we fail to maintain the effectiveness of a prior registration statement as required in the agreements. In such case, we would be required to pay monthly liquidated damages of up to $228,050. The maximum aggregate liquidated damages are capped at $1,368,300. If we do not make a monthly payment within seven days after the date payable, we are required to pay interest at an annual rate of 18% on the unpaid amount. If we default under the registration rights agreement and accrue liquidated damages, we could be required to either raise additional outside funds through financing or curtail or cease operations.
 
We are exposed to operating hazards and uninsured risks. Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:
 
fire, explosions and blowouts;
pipe failure;
abnormally pressured formations; and
environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).
 
 
These events may result in substantial losses to us from: 
 
injury or loss of life;
severe damage to or destruction of property, natural resources and equipment;
pollution or other environmental damage;
clean-up responsibilities;
regulatory investigation;
penalties and suspension of operations; or
attorney's fees and other expenses incurred in the prosecution or defense of litigation.
 
We maintain insurance against some, but not all, of these risks. We cannot assure you that our insurance will be adequate to cover these losses or liabilities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations.
 
The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions and weather conditions. These curtailments can last from a few days to many months.
 
We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult. We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:
 
recoverable reserves;
future oil and natural gas prices and their appropriate differentials;
development and operating costs; and
potential environmental and other liabilities.
 
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.
 
Significant acquisitions and other strategic transactions may involve other risks, including:
 
diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;
difficulty associated with coordinating geographically separate organizations;
challenge of attracting and retaining personnel associated with acquired operations; and
failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.
 
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
 
Prospects that we decide in which to participate may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return. A prospect is a property in which we own an interest and have what we believe, based on available seismic and geological information, to be indications of oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion cost or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analysis we perform using data from other wells, more fully explored prospects or producing fields will be useful in predicting the characteristics and potential reserves associated with our drilling prospects.
 
 
Our reserve estimates will depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of reserves shown in these reports.
 
In order to prepare reserve estimates in its reports, our independent petroleum consultant projected production rates and timing of development expenditures. Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary and may not be in our control. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
 
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
 
Risks relating to the oil and gas industry
 
Oil and natural gas prices are highly volatile, and our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following: 
  
changes in global supply and demand for oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries, or OPEC;
the price and quantity of imports of foreign oil and natural gas;
acts of war or terrorism;
political conditions and events, including embargoes, affecting oil-producing activity;
the level of global oil and natural gas exploration and production activity;
the level of global oil and natural gas inventories;
weather conditions;
technological advances affecting energy consumption;
the price and availability of alternative fuels; and
market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives.
 
Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.
 
Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.
 
 
Our industry is highly competitive which may adversely affect our performance, including our ability to participate in ready to drill prospects in our core areas. We operate in a highly competitive environment. In addition to capital, the principal resources necessary for the exploration and production of oil and natural gas are: 
 
leasehold prospects under which oil and natural gas reserves may be discovered;
drilling rigs and related equipment to explore for such reserves; and
knowledgeable personnel to conduct all phases of oil and natural gas operations.
 
We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these competitors have financial and other resources substantially greater than ours. We cannot assure you that such materials and resources will be available when needed. If we are unable to access material and resources when needed, we risk suffering a number of adverse consequences, including:
  
the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests;
loss of reputation in the oil and gas community;
a general slowdown in our operations and decline in revenue; and
decline in market price of our common shares.
 
Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.  In December 2009, the Environment Protection Agency (“EPA”) determined that emissions of carbon dioxide, methane and other ‘‘greenhouse gases’’ present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act, or CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011.  The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
 
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
 
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs, and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
 
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells.
 
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the federal Safe Drinking Water Act. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Under the proposed legislation, this information would be available to the public via the internet, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.  At the state level, some states have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
 
 
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.
 
We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business. Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, and operating safety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may result in substantial penalties and harm to our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as: 
 
land use restrictions;
lease permit restrictions;
drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds;
spacing of wells;
unitization and pooling of properties;
safety precautions;
operational reporting; and
taxation.
 
 Under these laws and regulations, we could be liable for:
 
personal injuries;
property and natural resource damages;
well reclamation cost; and
governmental sanctions, such as fines and penalties.
 
Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is also possible that a portion of our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See “Business and Properties—Government Regulations” for a more detailed description of our regulatory risks.
 
Our operations may incur substantial expenses and resulting liabilities from compliance with environmental laws and regulations. Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations: 
 
require the acquisition of a permit before drilling commences;
restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, including new environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
impose substantial liabilities for pollution resulting from our operations.
 
 
Failure to comply with these laws and regulations may result in:
 
the assessment of administrative, civil and criminal penalties;
incurrence of investigatory or remedial obligations; and
the imposition of injunctive relief.
 
Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Our permits require that we report any incidents that cause or could cause environmental damages. See “Business and Properties—Government Regulations” for a more detailed description of our environmental risks.
 
Risks Relating to Our Common Stock
 
There is a limited public market for our shares and we cannot assure you that an active trading market or a specific share price will be established or maintained.
 
Our common stock trades on the Nasdaq Global Market, generally in small volumes each day.  The value of our common stock could be affected by:
 
actual or anticipated variations in our operating results;
changes in the market valuations of other oil and gas companies;
announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;
adoption of new accounting standards affecting our industry;
additions or departures of key personnel;
sales of our common stock or other securities in the open market;
actions taken by our lenders or the holders of our convertible debentures;
changes in financial estimates by securities analysts;
conditions or trends in the market in which we operate;
changes in earnings estimates and recommendations by financial analysts;
our failure to meet financial analysts’ performance expectations; and
other events or factors, many of which are beyond our control.
 
In a volatile market, you may experience wide fluctuations in the market price of our securities. These fluctuations may have an extremely negative effect on the market price of our common stock and may prevent you from obtaining a market price equal to your purchase price when you attempt to sell our common stock in the open market. In these situations, you may be required either to sell at a market price which is lower than your purchase price, or to hold our common stock for a longer period of time than you planned. An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or oil and gas properties by using common stock as consideration.
 
Securities analysts may not initiate coverage of our shares or may issue negative reports, which may adversely affect the trading price of the shares.
 
We cannot assure you that securities analysts will cover our company. If securities analysts do not cover our company, this lack of coverage may adversely affect the trading price of our shares. The trading market for our shares will rely in part on the research and reports that securities analysts publish about us and our business. If one or more of the analysts who cover our company downgrades our shares, the trading price of our shares may decline. If one or more of these analysts ceases to cover our company, we could lose visibility in the market, which, in turn, could also cause the trading price of our shares to decline. Further, because of our small market capitalization, it may be difficult for us to attract securities analysts to cover our company, which could significantly and adversely affect the trading price of our shares.
 
 
 
We will not receive any proceeds from the sale or issuance of the shares of common stock offered by this prospectus.  

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

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

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

30,096 of the shares offered pursuant to this prospectus may be offered for resale by selling stockholders. Each selling stockholder of the shares and any of their pledgees, assignees and successors-in-interest may, from time to time, sell any or all of their shares covered hereby on the NASDAQ Global Market or any other stock exchange, market or trading facility on which our common stock is traded or in private transactions. These sales may be at fixed or negotiated prices. A selling stockholder may use any one or more of the following methods when selling shares:
 
ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;
block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;
purchases by a broker-dealer as principal and resale by the broker-dealer for its account;
an exchange distribution in accordance with the rules of the applicable exchange;
privately negotiated transactions;
settlement of short sales entered into after the effective date of the registration statement of which this prospectus is a part;
in transactions through broker-dealers that agree with the selling stockholders to sell a specified number of such shares at a stipulated price per share;
through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise;
a combination of any such methods of sale; or
any other method permitted pursuant to applicable law.

The selling stockholders may also sell shares under Rule 144 under the Securities Act of 1933, if available, rather than under this prospectus.
 
 
Broker-dealers engaged by the selling stockholders may arrange for other brokers-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the selling stockholders (or, if any broker-dealer acts as agent for the purchaser of shares, from the purchaser) in amounts to be negotiated, but, except as set forth in a supplement to this prospectus, in the case of an agency transaction not in excess of a customary brokerage commission in compliance with FINRA Rule 2440; and in the case of a principal transaction a markup or markdown in compliance with FINRA IM-2440.
 
In connection with the sale of the shares or interests therein, the selling stockholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of the shares in the course of hedging the positions they assume. The selling stockholders may also sell shares short and deliver these shares to close out their short positions, or loan or pledge the shares to broker-dealers that in turn may sell these shares. The selling stockholders may also enter into option or other transactions with broker-dealers or other financial institutions or create one or more derivative securities which require the delivery to such broker-dealer or other financial institution of shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).

 
The following description of our common stock is derived from our articles of incorporation and bylaws as well as relevant provisions of applicable law.  Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.0001 per share, and 10,000,000 shares of preferred stock, par value $0.0001 per share.
 
Except as otherwise required by law or provided in any designation of rights of preferred stock, the holders of our common stock are entitled to one vote per share on all matters submitted to a vote of the stockholders, including the election of directors.  Generally, all matters to be voted on by stockholders must be approved by a majority (or, in the case of election of directors, by a plurality) of the votes entitled to be cast by all shares of common stock that are present in person or represented by proxy, subject to any voting rights granted to holders of preferred stock.  Except as otherwise provided by law, and subject to any voting rights granted holders of preferred stock, amendments to our articles of incorporation generally must be approved by a majority of the votes entitled to be cast by all outstanding shares of common stock.  Our articles of incorporation and bylaws do not provide for cumulative voting in the election of directors.
 
 
Industry terms used in this prospectus are defined in the Glossary of Oil and Natural Gas Terms located at the end of this section.
 
General

Recovery Energy, Inc. (NASDAQ: RECV), sometimes referred to in this prospectus as “we,” “us,” “our,” “Recovery Energy,” “Recovery,” or the “Company” is a Denver based independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects. Our current activities are focused on the Denver-Julesburg (“DJ”) Basin in Colorado, Wyoming and Nebraska. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team and via the future exploration and development of the approximate 125,000 net acres of developed and undeveloped leases that are currently held by the Company, primarily in the northern DJ Basin.
 
Our executive offices are located at 1900 Grant Street, Suite #720, Denver, CO 80203, and our telephone number is (303) 951-7920.  Our web site is www.recoveryenergyco.com.  Additional information which may be obtained through our web site does not constitute part of this prospectus.  Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are accessible free of charge at our website.  The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings at www.sec.gov.
    
Company Overview & Strategy

We have developed and acquired an oil and natural gas base of proved reserves, as well as a portfolio of exploration and development prospects with  conventional and non-conventional reservoir opportunities with an emphasis on multiple producing horizons and the Niobrara, Codell and Greenhorn shale resource plays. We believe these prospects offer the possibility of repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Colorado, Nebraska, and Wyoming. Since early 2010 we have acquired and/or developed 29 producing wells. As of December 31, 2012 we owned interests in approximately 140,000 gross (125,000 net) leasehold acres, of which 118,000 gross (103,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska in the DJ Basin.  We intend to continue to evaluate and invest in acquisitions and internally generated prospects.  It is our long-term goal to maximize our DJ Basin acreage position through development drilling of our conventional horizons as well as development of our Niobrara, Codell and Greenhorn shale potential.
 
 
We have invested, and intend to continue to invest, primarily in oil and natural gas interests, including producing properties, prospects, leases, wells, mineral rights, working interests, royalty interests, overriding royalty interests, net profits interests, production payments, farm-ins, drill to earn arrangements, partnerships, easements, rights of way, licenses and permits, in the DJ Basin in Colorado, Nebraska, and Wyoming.

As of December 31, 2009, we had not successfully acquired any properties; therefore our total production was 0 Mboe net. Subsequent to December 31, 2009, we successfully completed a number of acquisitions which resulted in 136 Mboe of production for the year ended December 31, 2010.  In 2011, we drilled and completed 6 gross (5 net) wells and recorded net production of 101 Mboe during the year. During the year ended December 31, 2012, we drilled 6 gross (4 net) wells and recorded net production of 95 Mboe during the year.
 
It is our belief that the exploration and production industry’s most significant value creation occurs through the drilling of successful development wells and the enhancement of oil recovery in mature fields given appropriate economic conditions. Our goal is to create significant value while maintaining a low cost structure. To this end, our business strategy includes the following elements:
 
Participation in development prospects in known producing basin. We pursue prospects in one known producing onshore basin, the DJ Basin, where we can capitalize on our development and production expertise. We intend to operate the majority of our properties and evaluate each prospect based on its geological and geophysical merits.
 
Negotiated acquisitions of properties. We acquire producing properties based on our view of the pricing cycles of oil and natural gas and available exploration and development opportunities of proved, probable and possible reserves.
 
Retain Operational Control and Significant Working Interest.  In our principal development targets, we typically seek to maintain operational control of our development and drilling activities.  As operator, we retain more control over the timing, selection and process of drilling prospects and completion design, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of our capital expenditures.   We have continued to maintain high working interest in our DJ Basin properties which maximizes our exposure to generated cash flows and increases in value as the properties are developed.  With operational control, we can also schedule our drilling program to satisfy most of our lease stipulations and continue to put our acreage into “held by production” status, thus eliminating expirations.  The majority of our acreage is contiguous which will permit efficiencies in drilling and production operations.

Leasing of Prospective Acreage. In the course of our business, we identify drilling opportunities on properties that have not yet been leased.  At times, we take the initiative to lease prospective acreage and we may sell all or any portion of the leased acreage to other companies that want to participate in the drilling and development of the prospect acreage.
 
Controlling Costs. We seek to maximize our returns on capital by minimizing our expenditures on general and administrative expenses. We also minimize initial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that have already invested capital in such. Historically, we also outsourced some of our geological, geophysical, reservoir engineering and land functions in order to help reduce capital requirements.  

From time to time, we use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. From time to time, we will enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts.  We intend to use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In the future we may also be required by our lenders to hedge a portion of production as part of any financing.
 
We currently own interest in 140,000 gross, 125,000 net developed and undeveloped acres in DJ basin leases, and will require access to substantial capital in order to fully assess and develop our inventory of undeveloped acreage.

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

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

During 2012, we made capital expenditures of approximately $3.27 million, including $0.50 million for the purchase of undeveloped leases, $4.28 million related to drilling and completion operations where we drilled and completed 6 gross (4 net) wells. We sold undeveloped property for $1.4 million and leased undeveloped property for $1.5 million.
 
As of December 31, 2011 we had net proved reserves of 633 Mboe, and for the year ending December 31, 2011 we produced 101 Mboe. During the year ended December 31, 2012, we produced 95 Mboe. 

2013 Capital Budget

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

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

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

Our 2013 capital program is subject to securing sufficient capital, principally via the issuance of additional equity and debt.   We may also secure additional capital by pursuing sales of certain assets that are considered non-strategic.  We may also seek to finance certain projects via joint venture agreements or other arrangements with strategic or industry partners.
 
We cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings, equity offerings or other financings, or sales of non-strategic assets will be sufficient to fund our anticipated 2013 capital expenditures.

 
Reserves
 
The table below presents summary information with respect to the estimates of our proved oil and gas reserves for the year ended December 31, 2011.  Prior to January 2010, we did not own any reserves nor did we have any production.  We engaged Ralph E Davis Associates, Inc. (“RE Davis”) to audit internal engineering estimates for 100 percent of the PV-10 value of our proved reserves in 2011.  The prices used in the calculation of proved reserve estimates as of December 31, 2011 were $88.16 per Bbl and $3.96 per Mcf and as of December 31, 2010, were $78.93 per Bbl and $4.39 per Mcf for oil and natural gas, respectively.  The prices were adjusted for basis differentials, pipeline adjustments, and BTU content.
  
We emphasize that reserve estimates are inherently imprecise and that estimates of all new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties.  Accordingly, these estimates are expected to change as new information becomes available.  The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by us.  Neither prices nor costs have been escalated.  The following table should be read along with the section entitled “Risk Factors — Risks Related to Our Company — The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated.”  No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the Securities and Exchange Commission ("SEC"), since the beginning of the last fiscal year. We did not have third party engineers review probable, possible and resource based reserves as of December 31, 2011.  These reserve categories are currently being determined across our substantial acreage position and are expected to identify significant potential in all unproven classifications and from multiple horizons.
 
   
As of December 31,
 
   
2011
   
2010 (1)
   
2009 (1)
 
Reserve data:
                 
Proved developed
                 
Oil (MBbl)
   
216
     
278
     
-
 
Gas (MMcf)
   
148
     
308
     
-
 
MBOE
   
240
     
329
     
-
 
Proved undeveloped
                       
Oil (MBbl)
   
392
     
415
     
-
 
Gas (MMcf)
           
-
     
-
 
MBOE
   
392
     
415
     
-
 
Total Proved
                       
Oil (MBbl)
   
608
     
693
     
-
 
Gas (MMcf)
   
148
     
308
     
-
 
MBOE
   
633
     
744
     
-
 
Proved developed reserves %
   
38
%
   
44
%
   
-
 
Proved undeveloped reserves %
   
62
%
   
56
%
   
-
 
                         
Reserve value data :
                       
Proved developed PV-10
 
$
10,204,160
   
$
11,377,009
   
$
-
 
Proved undeveloped PV-10
   
9,809,885
     
12,217,798
     
-
 
Total proved PV-10
 
$
20,014,045
   
$
23,594,807
   
$
-
 
Standardized measure of discounted future cash flows
 
$
20,014,045
   
$
23,594,807
   
$
-
 
Reserve life (years)
   
22.58
     
21.92
     
-
 
 
(1) Prior to January 2010, the Company did not own any oil and gas properties

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

Internal Controls Over Reserves Estimate

Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserve quantities and values in compliance with the regulations of the SEC. Responsibility for compliance in reserve bookings is delegated to our President with assistance from our Principal Accounting Officer and certain retained  consultants.
 
 
Technical reviews are performed throughout the year by engineering consultants and geologic staff who evaluate all available geological and engineering data.  This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserve quantities.  The 2011 reserve process was overseen by Kent Lina, then our Senior Reserve Engineer. Mr. Lina joined us in October 2010, and prior to that was employed by Delta Petroleum Company from March 2002 to September 2010 in various operations and reservoir engineering capacities culminating as the Senior V.P. of Corporate Engineering. Mr. Lina received a Bachelor of Science degree in Civil Engineering from University of Missouri at Rolla in 1981. Mr. Lina left the Company in December 2012, and continues to serve the Company in a consulting capacity.
 
Third-party Reserves Study

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

Oil and gas reserves and the estimates of the present value of future net revenues therefrom were determined based on prices and costs as prescribed by SEC and FASB guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods.  Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. For the year ended December 31, 2011, commodity prices over the prior 12-month period and year end costs were used in estimating net cash flows.
 
In addition to a third party reserve study, our reserves are reviewed by senior management and the audit committee of our board of directors.  Our chief executive officer is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate.  The audit committee reviews the final reserves estimate in conjunction with RE Davis’s audit letter. 
 
Production
 
The following table summarizes the average volumes and realized prices, including and excluding the effects of our economic hedges, of oil and gas produced from properties in which we held an interest during the periods indicated.  Also presented is a production cost per BOE summary: 
 
   
For the Year Ended December 31,
 
Net production
 
2012
   
2011
   
2010
 
Oil (MMBbl)
    81,999       81,433       133.709  
Gas (MMcf)
    76,265       115,583       14.914  
MBOE
    94,710       100,707       136.195  
Average net daily production
                       
Oil (Bbl)
    225       223       366  
Gas (Mcf)
    209       317       41  
BOE
    260       275       373  
Average realized sales price, excluding the effects of our economic hedges
                       
Oil (per Bbl)
  $ 85.38     $ 87.77     $ 71.08  
Gas (per Mcf)
  $ 5.27     $ 4.73     $ 4.56  
Per BOE
  $ 69.79     $ 76.41     $ 70.29  
Average realized sales price, including the effects of our economic hedges
                       
Oil (per Bbl)
  $ 94.833     $ 95.44     $ 75.27  
Gas (per Mcf)
  $ 5.27     $ 4.73     $ 4.56  
Per BOE
  $ 77.24     $ 82.62     $ 74.47  
Production costs per BOE
                       
Lease operating expense
  $ 14.58     $ 15.19     $ 6.33  
DD&A
  $ 40.88     $ 42.25     $ 36.98  
Production taxes
  $ 7.92     $ 8.18     $ 7.76  
 
 
 
Productive Wells
 
As of December 31, 2012, we had working interests in 29 gross (26 net) productive oil wells, and 1 gross (1 net) productive gas well. Productive wells are either wells producing in commercial quantities or wells capable of commercial production although currently shut-in.  Multiple completions in the same wellbore are counted as one well.  A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.

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

As of December 31, 2012 our primary assets included acreage located in Laramie County and Goshen counties in Wyoming, Banner, Kimball, and Scotts Bluff Counties in Nebraska, and Weld, Arapahoe and Elbert Counties in Colorado.  
 
The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 2012.

   
Undeveloped
   
Developed
 
   
Gross
   
Net
   
Gross
   
Net
 
DJ Basin
   
118,200
     
103,200
     
21,800
     
21,800
 
                                 
Total
   
118,200
     
103,200
     
21,800
     
21,800
 
 
Drilling Activity
 
The following table describes the development and exploratory wells we drilled during the years ended December 31, 2012, 2011, and 2010.

   
For the Year Ended December 31,
 
   
2012
   
2011
   
2010
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                     
Development:
                   
-
     
-
     
-
     
-
 
Productive wells
   
5
     
3
     
3.0
     
2.25
     
2.0
     
1.4
 
Dry wells
   
1
     
1
     
1.0
     
1.0
     
1.0
     
0.7
 
     
6
     
4
     
4.0
     
3.25
     
3.0
     
2.1
 
Exploratory:
                                               
Productive wells
   
-
     
-
     
-
     
-
     
-
     
-
 
Dry wells
   
-
     
-
     
-
     
-
     
-
     
-
 
     
-
     
-
     
-
     
-
     
-
     
-
 
                                                 
Total
   
6
     
4
     
4.0
     
3.25
     
3.0
     
2.1
 
 
 
A productive well is an exploratory, development or extension well that is not a dry well.  A dry well (hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

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

As of December 31, 2012 we had 1 gross (1 net) well in progress.
 
Major Customers
 
During 2012, 2011 and 2010, the Company had one customer, Shell Trading (US), individually accounting for approximately 72 percent, 76 percent and 64 percent, respectively, of our revenues. 
 
Employees
 
As of December 31, 2012 we had 7 full-time employees and no part-time employees. For the foreseeable future, we intend to only add additional personnel as our operational requirements grow. In the interim, we plan to continue to use the services of independent consultants and contractors to perform various professional services, including land, legal, environmental and tax services. We believe that by limiting our management and employee costs, we are able to better control total costs and retain flexibility in terms of project management.
 
Title to Properties
 
Substantially all of our interests are held pursuant to leases from third parties.  The majority of our producing properties are subject to mortgages securing indebtedness under our credit facility that we believe do not materially interfere with the use of or affect the value of such properties.  We typically perform only minimal title investigation before acquiring undeveloped leasehold acreage.

Seasonality
 
Generally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer.  However, increased summertime demand for electricity has placed increased demand on storage volumes.  Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season — although oil prices are much more driven by global supply and demand.  Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.  The impact of seasonality on crude oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of production capacity in excess of existing worldwide demand for crude oil.
  
Competition
 
The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties.  We believe our leasehold position provides a sound foundation for a solid drilling program and our future growth.  Our competitive position also depends on our geological, geophysical, and engineering expertise, and our financial resources.  We believe the location of our acreage; our exploration, drilling, operational, and production expertise; available technologies; our financial resources and expertise; and the experience and knowledge of our management and technical teams enable us to compete effectively in our core operating areas.  However, we face intense competition from a substantial number of major and independent oil and gas companies, which, in some cases, have larger technical staffs and greater financial and operational resources than we do.  Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, and generate electricity.
 
 
We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells.  Consequently, we may face shortages or delays in securing these services from time to time.  The oil and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas.  Competitive conditions may also be affected by future new energy, climate-related, financial, and other policies, legislation, and regulations.

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

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

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

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

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

In April, 2012, we made the decision to temporarily abandon one of our unconventional Niobrara wells that was categorized as a well in progress as of December 31, 2011.  In conjunction with that decision, all capitalized drilling, completion and allocable lease costs related to this well in the amount of $4.8 million were transferred to developed properties.  This transfer of costs contributed to a $3.27 impairment charge of developed properties derived from the ceiling test completed as of March 31, 2012.
  
In August 2012, the Company restructured the terms of the Supplemental Debenture offering and concluded the offering by issuing an additional $1.96 million of convertible debentures.  On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures.
 
On November 5, 2012, the Company liquidated all of its price derivatives (commodity hedges) for proceeds of $0.60 million.

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

In December 2012, the Company leased certain deep rights to 6,300 undeveloped acres to a private company for proceeds of approximately $1.50 million.
 
 
Marketing and Pricing
 
We will derive revenue and cash flow principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We will sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.
 
Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of natural gas and crude oil. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:
 
changes in global supply and demand for oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries, or OPEC;
the price and quantity of imports of foreign oil and natural gas;
acts of war or terrorism;
political conditions and events, including embargoes, affecting oil-producing activity;
the level of global oil and natural gas exploration and production activity;
the level of global oil and natural gas inventories;
weather conditions;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
  
From time to time, we enter into derivative contracts. These contracts economically hedge our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:
 
our production and/or sales of natural gas are less than expected;
payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
the counterparty to the hedging contract defaults on its contract obligations.
 
In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.

Government Regulations
 
General. Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and local laws and regulations. The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impact our operations and can affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different than our competitors. Matters regulated include permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements for the operation of wells, and taxation of production. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gas and other substances and materials produced or used in connection with oil and natural gas operations. While we believe we will be able to substantially comply with all applicable laws and regulations, the requirements of such laws and regulations are frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect on our actual operations.
 
Federal Income Tax. Federal income tax laws significantly affect our operations. The principal provisions that affect us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, our domestic “intangible drilling and development costs” and to claim depletion on a portion of our domestic oil and natural gas properties based on 15% of our oil and natural gas gross income from such properties (up to an aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas). 
 
 
Environmental, Health, and Safety Regulations. Our operations are subject to stringent federal, state, and local laws and regulations relating to the protection of the environment and human health and safety.  Environmental laws and regulations may require that permits be obtained before drilling commences, restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities, govern the handling and disposal of waste material, and limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, including areas containing endangered animal species.  As a result, these laws and regulations may substantially increase the costs of exploring for, developing, or producing oil and gas and may prevent or delay the commencement or continuation of certain projects.  In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligations in the event of any discharges or emissions in violation of these laws and regulations.  Further, legislative and regulatory initiatives related to global warming or climate change could have an adverse effect on our operations and the demand for oil and natural gas.  See Risk Factors — Risks Related to Oil and Gas Industry — Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.
  
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations.  For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors— Risks Related to Our Company.”   Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and gas wells.

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

The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of oil and gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoining property, giving rise to additional liabilities.
 
A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing and may, in addition to other laws, impose liability in the event of discharges, whether or not accidental, failure to notify the proper authorities of a discharge, and other noncompliance with those laws. Compliance with such laws and regulations may increase the cost of oil and gas exploration, development and production, although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.
 
The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “superfund law,” imposes liability, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that dispose or arrange for disposal of the hazardous substances found at the time. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and severable liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA because our jointly owned drilling and production activities generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA.
 
The Resource Conservation and Recovery Act of 1976, as amended, or RCRA, is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.
 
 
The Oil Pollution Act of 1990, or OPA, and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by OPA. In addition, to the extent we acquire offshore leases and those operations affect state waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws. OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. We cannot predict whether the financial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or impose substantial additional annual costs to us or otherwise materially adversely affect us. The impact, however, should not be any more adverse to us than it will be to other similarly situated owners or operators.
 
The Federal Water Pollution Control Act Amendments of 1972 and 1977, or Clean Water Act, imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the Environmental Protection Agency, or EPA, has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of crude oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.
  
Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from crude oil and natural gas production. The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. Failure to abide by our permits could subject us to civil or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.
 
The Clean Air Act of 1963 and subsequent extensions and amendments, known collectively as the Clean Air Act, and state air pollution laws adopted to fulfill its mandate provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.  Over the next several years, we may be required to incur capital expenditures for air pollution control equipment or other air emissions-related issues. For example, on July 28, 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production, including, among other things, the application of reduced emission completion techniques, referred to as “green completions,” for completion of newly drilled and fractured wells in addition to establishing specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. Final action on the proposed rules is expected no later than April 3, 2012. If this action is finalized, we do not believe that such requirements will have a material adverse effect on our operations.
 
There are numerous state laws and regulations in the states in which we operate which relate to the environmental aspects of our business. These state laws and regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and gas wells which have been unproductive. Numerous state laws and regulations also relate to air and water quality.
 
 
We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry. We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations. Nevertheless, we cannot assure you that environmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our financial condition and results of operations. Although we maintain liability insurance coverage for liabilities from pollution, environmental risks generally are not fully insurable.
 
In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.
  
Federal Leases. For those operations on federal oil and gas leases, such operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies. In addition, on federal lands in the United States, the Minerals Management Service, or MMS, prescribes or severely limits the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, MMS prohibits deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the MMS has been engaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculating royalties owed to the government. The natural gas and crude oil industry as a whole has resisted the proposed rules under an assumption that royalty burdens will substantially increase. We cannot predict what, if any, effect any new rule will have on our operations.

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

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

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

To date we have not experienced any materially adverse effect on our operations from obligations under environmental, health, and safety laws and regulations.  We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and that continued compliance with existing requirements would not have a materially adverse impact on us.
 
Glossary of Oil and Natural Gas Terms
 
The following is a description of the meanings of some of the oil and natural gas industry terms used in this prospectus.
 
bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in reference to crude oil or other liquid hydrocarbons.
 
 
Bcf. Billion cubic feet of natural gas.
 
boe. Barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
boe/d. boe per day.
 
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
 
Condensate. Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons.
 
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
 
Drilling locations. Total gross locations specifically quantified by management to be included in our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
 
Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
 
Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
 
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
Formation. An identifiable layer of rocks named after its geographical location and dominant rock type.
 
Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.
 
Leasehold. Mineral rights leased in a certain area to form a project area.
 
Mbbls. Thousand barrels of crude oil or other liquid hydrocarbons.
 
Mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
Mcf. Thousand cubic feet of natural gas.
 
Mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
MMbbls. Million barrels of crude oil or other liquid hydrocarbons.
 
MMboe. Million barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
MMbtu. Million British Thermal Units.
 
MMcf. Million cubic feet of natural gas.
 
Net acres, net wells, or net reserves. The sum of the fractional working interest owned in gross acres, gross wells, or gross reserves, as the case may be.
 
 
Net barrel of production. The sum of the fractional revenue interest in gross production owned by the company.
 
ngl. Natural gas liquids, or liquid hydrocarbons found in association with natural gas.
 
Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lesser or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.
 
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
 
Present value of future net revenues (PV-10). The present value of estimated future revenues to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using the simple 12 month first of month average price and current costs (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of Recovery Energy on a comparative basis to other companies and from period to period.
 
Production. Natural resources, such as oil or gas, taken out of the ground.
 
Proved reserves. The quantities of oil, natural gas and natural gas liquids, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs under existing economic conditions and operating conditions.
 
Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
 
Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.  
 
Probable Reserves. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P estimate.
 
Possible Reserves. Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10-percent probability that the actual quantities recovered will equal or exceed the 3P estimate.
 
 
Productive well. A well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
  
Project. A targeted development area where it is probable that commercial gas can be produced from new wells.
 
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
 
Recompletion. The process of re-entering an existing well bore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
 
Reserves. Oil, natural gas and gas liquids thought to be accumulated in known reservoirs.
 
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible nature gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
 
Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.
 
Shut-in. A well that has been capped (having the valves locked shut) for an undetermined amount of time. This could be for additional testing, could be to wait for pipeline or processing facility, or a number of other reasons.
 
Standardized measure. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
 
Successful. A well is determined to be successful if it is producing oil or natural gas, or awaiting hookup, but not abandoned or plugged.
 
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
 
Water flood. A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery.
 
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.


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

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

Recent Market Prices
 
On November 2, 2011 our common stock began trading on the Nasdaq Global Market under the symbol "RECV."  Between September 25, 2009 and November 1, 2011 our stock traded on the OTC Bulletin Board under the symbol "RECV.OB."
 
The following table shows the high and low reported sales prices of our common stock for the periods indicated.  Effective October 19, 2011 we completed a 1:4 reverse stock split, and stock prices prior to such date have been adjusted to reflect the effect of the stock split.
 
   
High
 
Low
 
2012
         
           
Fourth Quarter
 
$
4.95
    $
1.40
 
Third Quarter
 
$
4.75
    $
1.64
 
Second Quarter
 
$
3.99
    $
2.25
 
First Quarter
 
$
4.90
   
$
2.31
 
2011
         
           
Fourth Quarter
 
$
7.00
    $
2.99
 
Third Quarter
 
$
11.00
   
4.88
 
Second Quarter
 
$
13.00
    $
8.80
 
First Quarter
 
$
15.56
   
$
7.80
 
2010
         
Fourth Quarter
 
$
10.00
   
$
7.24
 
Third Quarter
 
$
10.00
   
$
6.00
 
Second Quarter
 
$
16.00
   
$
1.00
 
First Quarter
 
$
22.00
   
$
8.20
 
 
On January 18, 2013, there were approximately 30 owners of record of our common stock.
 
Dividend Policy
 
We have never paid any cash dividends on our common stock and do not anticipate paying any dividends in the foreseeable future. Our current business plan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at the discretion of our board of directors, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as our board may deem relevant at that time.
 
Equity Compensation Plan Information
 
The following table sets forth certain information regarding shares of our common stock issuable upon the exercise of options granted under our 2012 Equity Incentive Plan (the “Plan”) as of December 31, 2012.
 
Plan Category
 
Number of securities to be issued upon exercise of outstanding options, warrants and rights
 
Weighted-average exercise price of outstanding options, warrants and rights
 
Number of securities remaining available for future issuance  under equity compensation plans
 
Equity compensation plans approved by security holders
   
0
 
$
   
479,167
(1)
Equity compensation plans not approved by security holders
   
   
   
 
Total
   
0
 
$
   
479,167
 
 

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

 

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

General
 
We are an independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the DJ Basin. Our business strategy is designed to create shareholder value by developing our undeveloped properties and leveraging the knowledge, expertise and experience of our management team.
 
We principally target low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Colorado, Nebraska, and Wyoming.  
 
Results of Operations
 
Nine Months Ended September 30, 2012 compared to the Nine Months Ended September 30, 2011.
 
The Company reported a net loss for the nine months ended September 30, 2012 of approximately $12.78 million compared to a net loss of approximately $11.53 million for the nine months ended September 30, 2011.
 
   
Nine months ended September 30,
 
   
2012
   
2011
 
Revenues and other income:
           
Oil sales
 
$
4,685,713
   
$
5,534,325
 
Gas sales
   
397,298
     
446,386
 
Realized gain on commodity hedges
   
49,729
     
402,256
 
Unrealized gain on commodity price derivatives
   
445,609
     
222,788
 
Other
   
132,367
     
110,282
 
Total revenues and other income 
   
5,710,711
     
6,716,037
 
Expenses:
               
Production costs
   
1,033,635
     
1,114,220
 
Production taxes
   
561,278
     
630,718
 
General and administrative
   
5,099,932
     
8,837,802
 
Depreciation, depletion and amortization
   
2,897,156
     
3,194,301
 
Impairment of evaluated properties
   
3,274,718
     
-
 
Total expenses
   
12,866,719
     
13,777,041
 
                 
Loss from continuing operations
   
(7,156,009
)
   
(7,061,004
)
Interest expense
   
(6,320,919
)
   
(6,123,496
)
Other
   
(372
)
   
63,115
 
Conversion note derivative gain
   
700,000
     
1,587,699
 
Net loss
 
$
(12,777,299
)
 
$
(11,533,686
)
 
 
Oil and Gas Revenues and Production

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

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

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

Oil and gas production expenses, depreciation, depletion and amortization

 
Nine Months
Ended
September 30,
   
Nine Months
Ended
September 30,
 
 
2012
   
2011
 
   
(per BOE)
   
(per BOE)
 
Average price (1)
 
$
63.53
   
$
59.07
 
                 
Production costs
   
12.92
     
11.00
 
Production taxes
   
7.02
     
6.23
 
Depletion and amortization
   
36.21
     
31.55
 
                 
Total operating costs
   
56.15
     
48.78
 
                 
Gross margin
 
$
7.38
   
$
10.29
 
                 
Gross margin percentage
   
12
   
17
 
(1)
Does not include the realized price effects of hedges
 
Commodity Price Derivative Activities
 
Changes in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivative instruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted exclusively of swaps. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.
 
 
 
Commodity price derivative net realized gain was $0.05 million during the nine months ended September 30, 2012, as compared to a realized gain of $0.40 million for the nine months ended September 30, 2011, for a decrease in realized gain of $0.35 million, or 88%.  We also recorded an unrealized gain on commodity price derivatives of $0.45 million for the nine months ended September 30, 2012 compared to a gain of $0.22 million during the nine months ended September 30, 2011, for an increase of $0.23 million, or 105%.

Production costs
 
Production costs were $1.03 million during the nine months ended September 30, 2012, as compared to $1.11 million for the nine months ended September 30, 2012, a decrease of $0.08 million, or 7%.  Production costs decreased due to lower work over expenses during the nine months ended September 30, 2012.
 
Production taxes
 
Production taxes were $0.56 million during the nine months ended September 30, 2012, as compared to $0.63 million during the nine months ended September 30, 2011, a decrease of $0.07 million, or 11%. Production taxes decreased due to the decrease in revenues during the nine months ended September 30, 2012.

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

Depreciation, depletion and amortization
 
Depreciation, depletion, and amortization were $2.90 million during the nine months ended September 30, 2012, as compared to $3.19 million during the nine months ended September 30, 2011, a decrease of $.29 million, or 9%.  Depreciation, depletion, and amortization decreased due lower unit volumes of oil and gas sales and a declining cost center.
 
Expressed in dollars per BOE, depreciation, depletion, and amortization was $36.21 per BOE during the nine months ended September 30, 2012, as compared to $31.55 during the nine months ended September 30, 2011.
 
Impairment of evaluated properties
 
Impairment of evaluated properties was $3.27 million during the nine months ended September 30, 2012, as compared to no impairment during the nine months ended September 30, 2011. Impairment of evaluated properties increased due to capitalized costs exceeding the ceiling value as of the quarter ended March 31, 2012.

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

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

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

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

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

   
Year Ended December 31,
 
   
2011
   
2010
 
Oil Sales (net bbls)
   
81,443
     
133,709
 
Gas Sales (net mcf)
   
115,583
     
14,914
 
                 
Average Oil Price
 
$
87.77
   
$
71.08
 
Average Gas Price
 
$
4.73
   
$
4.56
 
                 
Average Price per BOE
   
76.41
     
74.47
 
Production Costs
   
15.19
     
6.33
 
Production Taxes
   
8.18
     
7.76
 
Depreciation and Amortization
   
42.25
     
36.98
 
Total Operating Costs
   
65.62
     
51.07
 
Gross Margin
   
10.79
     
23.40
 
Gross Margin %
   
14.12
%
   
31.42
%
 
Oil volumes declined 39%, gas volume increased by 675%, and prices for both oil and gas increased.  The gas volume increase can be attributed to the production of one gas well that produced during the entirety of 2011, but only for part of 2010.  The decline in oil volume is due almost entirely to natural production declines.

Other revenues in 2010 included an unrealized loss on commodity hedges of $399,000.  Unrealized losses on commodity hedges in 2011 were nominal.
 
  
Production taxes in 2011 decreased by 22% in 2011 as a result in the overall decrease in oil and gas sales.  Production costs increased by 77%.  This increase is due primarily to an increase in the number of workovers, property improvements and other onsite work that was performed on our producing properties during the year.

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

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

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

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

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

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

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

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

Average daily net production for the twelve month period ended December 31, 2010 was 373 BOEPD. 
 
Miscellaneous Income and Operating Fees

We earned net operating fees of $13,487 during the twelve months ended December 31, 2010. We realized a mark-to-market gain of $28,666 during the twelve months ended December 31, 2010 on a put agreement associated with 85,000 shares of stock placed in conjunction with our reverse merger in September 2009.
 
Price Risk Management Activities
 
We recorded a net loss on our derivative contracts that do not qualify for cash flow hedge accounting of $(398,840) for the year ended December 31, 2010.  This amount represents an unrealized non-cash loss which represents a change in the fair value of our mark-to-market derivative instruments at December 31, 2010 as detailed in “Note 5 – Financial Instruments and Derivatives” and “Note 6 – Fair Value of Financial Instruments”.  We realized a gain on our derivative contracts that do not qualify for cash flow hedge accounting $570,233 for the year ended December 31, 2010.  This amount represents a realized cash gain from the settlement of our forward sale contracts for the quarter ended December 31, 2010 as detailed in “Note 5 – Financial Instruments and Derivatives” and “Note 6 – Fair Value of Financial Instruments”.   
 
 
Oil and Gas Production Expenses, Depreciation, Depletion and Amortization
 
   
Years ended December 31,
 
   
2010
   
2009 (1)
 
Net production
           
Oil (Bbl)
   
133,709
     
-
 
Gas (Mcf)
   
14,914
     
-
 
MBOE
   
136,195
     
-
 
Average net daily production
               
Oil (Bbl)
   
366
     
-
 
Gas (Mcf)
   
41
     
-
 
BOE
   
373
     
-
 
Average realized sales price, excluding the effects of hedging
               
Oil (per Bbl)
 
$
71.08
   
$
-
 
Gas (per Mcf)
 
$
4.56
   
$
-
 
Per BOE
 
$
70.29
   
$
-
 
Average realized sales price, including the effects of hedging
               
Oil (per Bbl)
 
$
75.27
   
$
-
 
Gas (per Mcf)
 
$
4.56
   
$
-
 
Per BOE
 
$
74.47
   
$
-
 
Production costs per BOE
               
Lease operating expense (2)
 
$
6.33
   
$
-
 
DD&A
 
$
36.98
   
$
-
 
Production taxes
 
$
7.76
   
$
-
 
                 
Total operating costs
 
$
51.07
   
$
-
 
                 
Gross margin percentage
   
31
%
 
$
-
%
 
(1)  
Prior to January 2010, the Company did not own any oil and gas properties.  
(2)  
Approximately $2.35/BOE of lease operating expense relates to surface, subsurface, road repairs and work-over activities.
 
General and Administrative Expenses
 
General and administrative expenses were $15,530,248 for the year ended December 31, 2010.  Our general and administrative expenses twelve months ended December 31, 2010 included $1,464,990 in professional fees (financial advisors, attorneys, accountants, and reserve engineers) of which $372,393 were noncash, and $9,958,300 in non-cash compensation expense.  We also incurred a non-cash expense of $54,500 in rental expense for our office lease for the year ending December 31, 2010 and a non-cash warrant modification expense of $2,953,450 for the year ended December 31, 2010. Total non-cash general and administrative expenditures for the year ended December 31, 2010 was approximately $13,300,000.  This compares to approximately $1,057,306 in general and administrative expenditures from inception through December 31, 2009 which included non-cash expenditures of $690,000.

Depreciation Expense

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

Total interest expense was $6,640,209 for the year ended December 31, 2010.  The interest expense was comprised of $3,989,649 in non-cash amortization of expenses for the year ended December 31, 2010 related to warrants issued and overriding royalty interests assigned to our lender in conjunction with the closing of the three credit agreements and the extension of the credit agreements.  We incurred $2,655,131 in cash interest expense for the year ended December 31, 2010.  Neither we nor our predecessor business incurred interest expense from inception through December 31, 2009.
 
 
We incurred a net loss to common shareholders of $19,739,033 for the year ended December 31, 2010.

Financial Condition and Liquidity

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

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

A summary of cash flow results during the nine months ended September 30, 2012 follows:
 
   
Nine Months Ended
September 30,
 
   
2012
 
Cash provided by (used in):
     
Operating activities
 
$
(2,747,079
)
Investing activities
   
(3,274,068
)
Financing activities
   
4,011,701
 
         
Net change in cash
 
$
(2,009,446
)
 
During the nine months ended September 30, 2012, net cash used in operating activities was $2.75 million.  The primary changes in operating cash during the nine months ended September 30, 2012 were $12.78 million of net loss, adjusted for non-cash charges of $4.51 million of depreciation, depletion, amortization and accretion expenses,  $1.77 million of stock-based compensation, $3.27 million of impairment of evaluated properties, $2.23 million of amortization of deferred financing costs and issuance of stock for convertible debentures interest, and non-cash change in fair value of convertible debentures conversion option of $0.70 million, and offset by a non-cash charge for the change in commodity price derivatives of $0.45 million.
 
During the nine months ended September 30, 2012, net cash used in investing activities was $3.27 million. The primary changes in investing cash during the nine months ended September 30, 2012 were $0.44 million related to our acquisitions of unproved acreage and drilling capital expenditures of $4.28 million, offset by the proceeds from the sale of undeveloped properties of $1.44 million.
  
During the nine months ended September 30, 2012, net cash provided by financing activities was $4.01 million. The changes in financing cash during the nine months ended September 30, 2012 were from net proceeds from the issuance of new convertible debentures of $5.00 million, offset by the net repayments of debt of $0.98 million.

On March 19, 2012, we entered into agreements with our existing convertible debenture holders to issue up to an additional $5.0 million in convertible debentures. All terms of the new convertible debentures are substantively identical to the existing convertible debentures.  This financing was completed by September 30, 2012.
 
Information about our financial position is presented in the following table:
 
   
September 30,
2012
   
December 31,
2011
 
Financial Position Summary
           
Cash and cash equivalents
 
$
698,276
   
$
2,707,722
 
Working capital
 
$
(907,863
)
 
$
1,294,706
 
Balance outstanding on term loans and convertible debentures payable
 
$
 33,692,339
   
$
29,680,636
 
Shareholders’ equity
 
$
39,311,760
   
$
49,668,225
 
 
 
Cash used in operating activities during the year ended December 31, 2011 was $.6 million, and cash used in investing activities exceeded cash provided by financing activities by approximately $2.2 million. This net cash use contributed to a substantial decrease in our net working capital as of December 31, 2011.  Expenditures subsequent to December 31, 2011 have continued to exceed cash receipts, causing a further reduction of the Company’s working capital position.

During the year ended December 31, 2011, our working capital decreased to $1.3 million compared to $4.4 million at December 31, 2010. This lower level of working capital is primarily of the result of cash used in operations, and cash investing activities that exceeded cash provided by financing activities.
 
During the year ended December 31, 2011, net cash used in operating activities was $570,000. The primary changes in operating cash during the year ended December 31, 2010 were $18.8 million of net loss, adjusted for non-cash charges of $ 4.3 million of depreciation, depletion and amortization expenses and accretion expense, $6.5 million of stock-based compensation and stock paid for services, $4.4 million of amortization of deferred financing costs, $2.8 million of impairment expense, $2.8 million of debt inducement expense, and offset by $3.3 million in non-cash gains on derivatives.

During the year ended December 31, 2011, net cash used by investing activities was $13.3 million. The primary changes in investing cash during the year ended December 31, 2011 was $9.4 million in expenditures related to our acquisitions which consisted primarily of the undeveloped acreage, and $7.0 million in drilling capital expenditures, offset by $3.0 million in proceeds received from the sale of certain undeveloped acreage.
 
During the year ended December 31, 2011, net cash provided by financing activities was $11.0 million. The primary changes in financing cash during the year ended December 31, 2011 were $8.0 million related to the issuance of convertible debt, $2.1 million derived from the issuance of common stock, and $.9 million in other changes in debt.

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

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

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

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

Term Loans
 
The Company entered into three separate loan agreements with Hexagon during 2010.  All three loans bear annual interest of 15% and mature on December 31, 2013.

Effective January 29, 2010, the Company entered into a $4.5 million loan agreement, with an original maturity date of December 1, 2010.  Effective March 25, 2010, the Company entered into a $6.00 million loan agreement, with an original maturity date of December 1, 2010.  Effective April 14, 2010, the Company entered into a $15 million loan agreement, with an original maturity date of December 1, 2010.  All three loan agreements have similar terms, including customary representations and warranties and indemnification, and require the Company to repay the loans with the proceeds of the monthly net revenues from the production of the properties acquired using the loan proceeds.  The loans contain cross collateralization and cross default provisions and are collateralized by mortgages against a portion of the Company’s developed and undeveloped leasehold acreage as well as all related equipment purchased in the Wilke Field, Albin Field, and State Line Field acquisitions.

We entered into a loan modification agreement on May 28, 2010, which extended the maturity date of the loans to December 1, 2011.  In consideration for extending the maturity of the loans, Hexagon received 250,000 warrants with an exercise price of $6.00 per share.  The loan modification agreement also required the Company to issue 250,000 five year warrants to purchase common stock at $6.00 per share to Hexagon if the Company did not repay the loans in full by January 1, 2011. Since the loans were not paid in full by January 1, 2011, the Company issued 250,000 additional warrants with an exercise price of $6.00 per share to Hexagon which was valued at approximately $1.60 million.  This amount was recorded as a deferred financing cost and is being amortized over the remaining term of the loan.
  
In December 2010, Hexagon extended the maturity of the loans to September 1, 2011.  During the last six months of 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2.00 million as payment on the loans. In November 2011, Hexagon extended the maturity to January 1, 2013.  In November 2011, Hexagon also temporarily advanced the Company an additional amount of $0.31 million, which was repaid in full in February 2012.  In March 2012, Hexagon extended the maturity of the loans to June 30, 2013, and in connection therewith, the Company agreed to make minimum monthly loan payments of $0.33 million, effective immediately.  In July 2012, Hexagon extended the maturity date to September 30, 2013. In November 2012, Hexagon extended the maturity date to December 31, 2013.

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

The Company is subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements.  As of September 30, 2012, the Company was in compliance with all covenants under the facilities.  If any of the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default and accelerate all principal and interest outstanding.

Convertible Debentures Payable
 
In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of 8% Senior Secured Convertible Debentures due February 2, 2014 (the "Debentures") with a group of accredited investors.  Initially, the Debentures were convertible at any time at the holders' option into shares of our common stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. Interest on the Debentures is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or at the Company's option in shares of common stock, valued at 95% of the volume weighted average price of the common stock for the 10 trading days prior to an interest payment date.  The Company can redeem some or all of the Debentures at any time.  The redemption price is 115% of principal plus accrued interest.  If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price will include a make-whole premium equal to the remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable in common stock. T.R. Winston & Company LLC acted as placement agent for the private placement and received $0.40 million of Debentures equal to 5% of the gross proceeds from the sale.  The Company is amortizing the $0.40 million over the life of the loan as deferred financing costs.  The Company amortized $0.13 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.18 million of deferred financing costs to be amortized through February 2014. 
 
In December, 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share.
 
 
This amendment was an inducement consideration to the Debenture holders for their agreement to release a mortgage on certain properties so the properties could be sold. The sale of these properties was effective December 31, 2011, and a final closing occurred during the three months ended March 31, 2012.
 
On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to increase the amount of its Debentures by up to an additional $5.0 million (the “Supplemental Debentures”).  Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of Supplemental Debentures are to be used principally for the development of certain of the Company's proved undeveloped properties, and other undeveloped leases currently targeted by the Company for exploration, as well as for other general corporate purposes. Any new producing properties that are developed from the proceeds of Supplemental Debentures are to be pledged as collateral under a mortgage to secure future payment of the Debentures and Supplemental Debentures. All terms of the Supplemental Debentures are substantively identical to the Debentures.  The Agreements also provided for the payment of additional consideration to the purchasers of Supplemental Debentures in the form of a proportionately reduced, 5% carried working interest in any properties developed with the proceeds of the Supplemental Debenture offering.

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

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

The Company has estimated the total value of consideration paid to Supplemental Debenture holders in the form of the modified net profits interest and carried working interest to be approximately $1.16 million, and recorded this amount as a debt discount to be amortized over the remaining life of the Debentures.
 
We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect to September 30, 2012, the Supplemental Debentures.  This valuation resulted in an estimated derivative liability as of September 30, 2012 and December 31, 2011 of $1.3 million and $1.3 million, respectively.  The portion of the derivative liability that is associated with the Supplemental Debentures, in the approximate amount of $0.70 million, has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.

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

On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC for acting as a placement agent of the Supplemental Debentures.  The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs.  The Company amortized $0.01 million of deferred financing costs into interest expense during the nine months ended September 30, 2012, and has $0.22 million of deferred financing costs to be amortized through February 2014. 
 
As of September 30, 2012 and December 31, 2011, the convertible debt is recorded as follows:

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

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

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

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

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

Off-Balance Sheet Arrangements
 
We do not have any off-balance sheet arrangements.

2013 Capital Budget

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

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

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

Capital Resources

Our 2013 capital program is subject to securing sufficient capital, principally via the issuance of additional equity and debt both to fund our capital program and to refinance the Hexagon loans which are due on December 31, 2013.   We may also secure additional capital by pursuing sales of certain assets that are considered non-strategic.  We may also seek to finance certain projects via joint venture agreements or other arrangements with strategic or industry partners.
 
Currently, the majority of our cash flows from operations are applied to the payment of principal and interest of our loans and to capital expenditures.  Due to the continuing operating losses and the large amounts of capital expenditures during 2011 and continuing through 2012, our liquidity and working capital have deteriorated. While we believe that we have sufficient liquidity and capital resources to maintain our staff and continue our current production operations, we require additional capital to resolve our current working capital deficit and address our upcoming debt maturities, and will also require substantial additional capital in order to fully test, develop and evaluate our 125,000 net undeveloped acres.  We expect to obtain this capital through a variety of sources, including, but not limited to, future debt and equity financings and potentially from future joint venture partners.  Unless we are successful in competing a substantial debt and/or equity financing or other similar transaction in the near term, we may be required to sell certain assets in order to meet obligations as they arise.  We can provide no assurance that we will be able to secure a major financing, nor can we predict the terms of any future potential financing transactions.
 

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

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

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

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

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

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

We intend to use the services of independent consultants and contractors to perform various professional services, including land, legal, environmental, investor relations and tax services.  We believe that by limiting our management and employee costs, we may be able to better control total costs and retain flexibility in terms of project management.  
 
Marketing and Pricing
 
We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas.  We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts.  The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.
 
 
Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas.  Prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.  Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of oil and natural gas.  Historically, the prices received for oil and natural gas have fluctuated widely.  Among the factors that can cause these fluctuations are:
 
changes in global supply and demand for oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries, or OPEC;
the price and quantity of imports of foreign oil and natural gas;
acts of war or terrorism;
political conditions and events, including embargoes, affecting oil-producing activity;
the level of global oil and natural gas exploration and production activity;
the level of global oil and natural gas inventories;
weather conditions;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
 
From time to time, we will enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas.  Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:
 
our production and/or sales of natural gas are less than expected;
payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
the counter party to the hedging contract defaults on its contract obligations.
 
In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas.  We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas.  On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions. 

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

Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial condition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.
  
Use of Estimates
 
The financial statements included herein were prepared from the records of Recovery in accordance with GAAP, and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods.  The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  We evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances.  Although actual results may differ from these estimates under different assumptions or conditions, we believe that our estimates are reasonable.  Our most significant financial estimates are associated with our estimated proved oil and gas reserves as well as valuation of common stock used in various issuances of common stock, options and warrants and estimated fair value of the asset held for sale.
 
  
Oil and Natural Gas Reserves
 
We follow the full cost method of accounting.  All of our oil and gas properties are located within the United States, and therefore all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool.  Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves.  Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties.  Should capitalized costs exceed this ceiling, impairment would be recognized.  Under the SEC rules, we prepared our oil and gas reserve estimates as of September 30, 2012, using the average, first-day-of-the-month price during the 12-month period ending September 30, 2012.
 
Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process.  The process relies on interpretations of available geological, geophysical, engineering and production data.  The extent, quality and reliability of this technical data can vary.  The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate. 
 
We believe estimated reserve quantities and the related estimates of future net cash flows are the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties.  Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used.  For example, the standardized measure calculation requires us to apply a 10% discount rate.  Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change.  We evaluate and estimate our oil and natural gas reserves as of December 31 of each year and quarterly throughout the year.  For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions.  Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.
 
Oil and Natural Gas Properties—Full Cost Method of Accounting
 
We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.
 
Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations.  These undeveloped properties are assessed quarterly to ascertain whether impairment has occurred.  When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations.
 
 
Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%.  Royalties paid, net of any tax credits received, are netted against oil and natural gas sales. 
 
In applying the full cost method, we perform a ceiling test on properties that restricts the capitalized costs, less accumulated depletion, from exceeding an amount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleum engineers.  The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the end of the applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financing costs, future site restoration costs and income taxes.  Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.

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

Likewise, operations that are being conducted on this well are extending the primary terms of leases that comprise approximately 6,919 net acres and that are currently being carried at a cost of approximately $4.1 million.  Absent a successful completion of this well, the lease terms of some or all of these acres may expire, and the carrying costs of these leases would also be transferred to the full cost pool.
 
Revenue Recognition
 
The Company derives revenue primarily from the sale of produced natural gas and crude oil.  The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses and are included in oil and gas production expense in the accompanying consolidated statements of operations.  Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production.  No revenue is recognized unless it is determined that title to the product has transferred to the purchaser.  At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive.  The Company uses its knowledge of its properties, their historical performance, NYMEX and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates.
 
Share Based Compensation
 
The Company accounts for share-based compensation by estimating the fair value of share-based payment awards made to employees and directors, including restricted stock grants, on the date of grant.  The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods.  

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


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

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

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

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

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

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

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

Compensation of Directors

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

Name
 
Fees Earned or
Paid in Cash
Compensation
   
Stock Awards
   
All Other
Compensation
   
Total
 
Timothy N. Poster
 
$
40,000.00
   
$
40,000.00
   
$
0.00
   
$
80,000.00
 
W. Phillip Marcum (1)
 
$
42,500.00
   
$
150,000.00
   
$
0.00
   
$
192,500.00
 
D. Kirk Edwards
 
$
24,835.16
   
$
150,000.00
   
$
0.00
   
$
174,835.16
 
Bruce B. White
 
27,472.52
   
150,000.00
   
0.00
   
$
177,472.52
 
Conway J. Schatz (2)
 
5,000.00
   
0.00
   
0.00
   
$
5,000.00
 
 
(1)  Mr. Marcum ceased being a non-employee director when he was appointed chief executive officer on November 15, 2012.
(2)  Mr. Schatz resigned as a director to pursue other professional and career obligations on January 31, 2012.

We currently pay each of our non-employee directors annual cash compensation of $40,000 ($10,000 per quarter), and annual equity compensation in common shares equal to $40,000 (payable on each anniversary of their initial appointment) at the then current fair market value of our shares. We pay additional cash compensation of $10,000 per year (payable quarterly) to the chairman of our audit and compensation committees. Mr. Poster currently serves as chair of our compensation committee, and Mr. Marcum served as chair of our audit committee until he was appointed an executive officer of the Company on November 15, 2012.
 
In May 2010 we granted Mr. Poster 125,000 shares of our common stock, 50% of which vested on January 1, 2011 and the other 50% of which will vest on January 1, 2012. In April 2012 we granted Mr. Marcum and Mr. White 50,000 shares of our common stock for their service as directors.  The shares vest in equal amounts on the first, second and third anniversaries of the date of their initial appointment to the board (September 9, 2011 for Mr. Marcum and April 24, 2012 for Mr. White). We also made an additional grant of 13,115 to Mr. Poster in April 2012 in accordance with his independent director agreement. In May 2012, when Mr. Edwards joined the board, we granted him 50,000 shares subject to vesting on the first, second and third anniversaries of the date of his initial appointment to the board (May 18, 2012).
 
We have entered into independent director agreements with our non-employee directors. These agreements provide that the shares granted to a director fully vest upon a change of control or termination of the director's services as a director by Recovery Energy other than for cause. The agreements permit a director to engage in other business activities in the energy industry, some of which may be in conflict with the best interests of Recovery Energy, and also states that if a director becomes aware of a business opportunity, he has no affirmative duty to present or make such opportunity available to us.
 
 

Executive Compensation for Fiscal Year 2012

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

The table below sets forth compensation paid to our executive officers for the 2012 and 2011 fiscal years.
 
Name and
Principal Position
 
Year
 
Salary
   
Bonus
   
Stock Awards
   
Other Compensation
   
Total
 
Roger A. Parker
 
2012
 
$
217,700
   
$
-
   
$
-
   
$
141,903
(1)
 
$
359,603
 
(chief executive officer May 1, 2010 – November 15, 2012)(3)
 
2011
 
$
240,000
   
$
-
   
$
-
   
$
110,000
(2)
 
$
350,000
 
                                             
A. Bradley Gabbard
 
2012
 
$
182,146
   
$
-
   
$
97,689
(4)
 
$
5,275
(5)
 
$
285,110
 
(chief financial officer since July 12, 2011; president since November 15, 2012)
 
2011
 
$
84,000
   
$
-
   
$
166,000
(6)
 
$
-
   
$
250,000
 
                                             
Jeffrey A. Beunier
 
2012