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** **

 

** **

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON, D.C.  20549**

 

**FORM 10-K**

 

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

 

**For the fiscal Year Ended December 31, 2010**

** **

**or**

 

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

 

**For the transition period from                     to                     **

 

**Commission file number: 001-32369**

 

**GASCO ENERGY, INC.**

(Exact name of registrant as specified in its charter)

** **

| **NEVADA**                      | ** ** | **98-0204105**         |
|---------------------------------|------------|------------------------|
| (State or other jurisdiction of |       | (I.R.S.  Employer |
| incorporation or organization)  |       | Identification No.)    |

 

| **8 Inverness Drive East, Suite 100, Englewood, CO** | ** ** | **80112**  |
|------------------------------------------------------|------------|------------|
| (Address of principal executive offices)             |       | (Zip Code) |

 

Registrant’s telephone number, including area code: **(303) 483-0044**

 

Securities registered pursuant to Section 12(b) of the Exchange Act:

 

| **Title of each class** | ** ** | **Name of each exchange on which registered** |
|----------------------------------------|------------|-----------------------------------------------------------------------------|
| **COMMON STOCK, $0.0001 PAR VALUE**    | ** ** | **NYSE AMEX LLC**                                                           |

 

Securities registered pursuant to Section 12(g) of the Exchange Act: **None.**

 

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

 

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

 

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes o  No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

| Large accelerated filer o                       |   | Accelerated filer o         |
|-------------------------------------------------|--------|-----------------------------|
|                                            |   |                        |
| Non-accelerated filer x                         |   | Smaller reporting company o |
| (Do not check if a smaller reporting   company) |   |                        |

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o  No x

 

As of June 30, 2010, pursuant to Regulation 14A the aggregate market value of the outstanding shares of Common Stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the shares of Common Stock outstanding, for this purpose as if they may be affiliates of the registrant) was approximately $29,735,697 based on a price of $0.28 per share, which was the closing price per share as reported on the NYSE Amex on such date. As of March 2, 2011, 126,948,715 shares of Common Stock, par value $0.0001 per share were outstanding.

 

Documents incorporated by reference:

 

Certain information required by Part III of this Annual Report on Form 10-K is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2011 annual meeting of stockholders to be filed pursuant to Regulation 14A within 120 days of December 31, 2010.

 

 

 

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**Table of Contents**

 
| ** ** | **Part I**                                                                                                            |   |
|------------|-----------------------------------------------------------------------------------------------------------------------|--------|
|       |                                                                                                                  |   |
| Item 1.    | Business                                                                                                              | 4      |
|       |                                                                                                                  |   |
| Item 1 A.  | Risk Factors                                                                                                          | 18     |
|       |                                                                                                                  |   |
| Item 1 B.  | Unresolved   Staff Comments                                                                                           | 41     |
|       |                                                                                                                  |   |
| Item 2.    | Properties                                                                                                            | 41     |
|       |                                                                                                                  |   |
| Item 3.    | Legal Proceedings                                                                                                     | 50     |
|       |                                                                                                                  |   |
| Item 4.    | (Removed and Reserved)                                                                                                | 52     |
|       |                                                                                                                  |   |
| ** ** | **Part II**                                                                                                           |   |
|       |                                                                                                                  |   |
| Item 5.    | Market for   Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases   of Equity Securities | 52     |
|       |                                                                                                                  |   |
| Item 6.    | Selected Financial   Data                                                                                             | 54     |
|       |                                                                                                                  |   |
| Item 7.    | Management’s   Discussion and Analysis of Financial Condition and Results of Operations                          | 54     |
|       |                                                                                                                  |   |
| Item 7A.   | Quantitative   and Qualitative Disclosures about Market Risk                                                          | 77     |
|       |                                                                                                                  |   |
| Item 8.    | Financial   Statements and Supplementary Data                                                                         | 79     |
|       |                                                                                                                  |   |
| Item 9.    | Changes in   and Disagreements with Accountants on Accounting and Financial Disclosure                                | 120    |
|       |                                                                                                                  |   |
| Item 9A.   | Controls and   Procedures                                                                                             | 120    |
|       |                                                                                                                  |   |
| Item 9B.   | Other Information                                                                                                     | 124    |

 

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| ** ** | **Part   III**                                                                                     |   |
|------------|----------------------------------------------------------------------------------------------------|--------|
|       |                                                                                               |   |
| Item 10.   | Directors, Executive   Officers and Corporate Governance                                           | 124    |
|       |                                                                                               |   |
| Item 11.   | Executive Compensation                                                                             | 124    |
|       |                                                                                               |   |
| Item 12.   | Security   Ownership of Certain Beneficial Owners and Management and Related Stockholder   Matters | 124    |
|       |                                                                                               |   |
| Item 13.   | Certain Relationships and   Related Transactions and Director Independence                         | 124    |
|       |                                                                                               |   |
| Item 14.   | Principal Accounting   Fees and Services                                                           | 124    |
|       |                                                                                               |   |
| Item 15.   | Exhibits,   Financial Statement Schedules                                                          | 124    |

 

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**PART I**

 

**ITEM 1 - BUSINESS**

 

**Overview**

 

We are a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. Our principal business strategy is to enhance stockholder value by generating and developing high-potential exploitation resources in these areas. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. We are currently focusing our operational efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations. As of December 31, 2010, we held interests in 280,986 gross (225,482 net) acres located in Utah, California and Nevada. As of December 31, 2010, we held an interest in 133 gross (79.4 net to our interest) producing wells and three gross (three net) shut-in wells located on these properties.

 

We began an up-hole recompletion program in early February 2010. Since then, we have successfully completed the initial stages on one Upper Mancos well and recompleted 22 gross (8.5 net) wells with six (2.0 net) wells occurring during the fourth quarter of 2010. As of December 31, 2010, we operated 133 gross producing wells. We currently have an inventory of 19 operated wells with up-hole completion potential and one Upper Mancos well awaiting initial completion activities. We do not have a drilling rig under contract at this time, as was the case for all of 2010.

 

We were incorporated on April 21, 1997 under the laws of the State of Nevada.  We operated as a shell company until December 31, 1999.

 

**2010 Highlights**

 

***Acquisition of Petro-Canada Assets***

 

On****February 25, 2010, we completed the acquisition of two wells and certain related oil and gas leases (the “Petro-Canada Assets”) from Petro-Canada Resources (USA) Inc., a Colorado corporation (“Petro-Canada”), for a purchase price of approximately $482,000, subject to customary post-closing terms and conditions for transactions of this size and nature. The sale was made pursuant to a definitive agreement dated February 4, 2010 by and between us and Petro-Canada. The Petro-Canada Assets included one producing well, one shut-in well with recompletion potential and 5,582 gross and net acres located in Utah, west of our Gate Canyons operating area. We funded this acquisition with cash flow from operating activities.

 

***Sale of Gathering Assets***

 

On February 26, 2010, we completed the sale of substantially all of the assets comprising our gathering system and our evaporative facilities, located in Uintah County, Utah (“Gathering Assets”), to Monarch Natural Gas, LLC (“Monarch”) pursuant to an Asset Purchase Agreement dated January 29, 2010 (the “Purchase Agreement”). At the closing, we received total cash consideration of approximately $23 million from Monarch, the entirety of which was used to repay amounts outstanding under our revolving credit facility.

 

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Pursuant to the Purchase Agreement, simultaneous with the closing, we entered into the following agreements with Monarch: (i) a transition services agreement pursuant to which we provided certain services relating to the operation of the Gathering Assets to Monarch for a six-month term commencing at closing (this agreement was terminated in August 2010); (ii) a gas gathering agreement pursuant to which we dedicated the natural gas production from all of our Utah acreage and Monarch will provide gathering, compression and processing services utilizing the Gathering Assets to us; and (iii) a salt water disposal services agreement pursuant to which we may deliver salt water produced by our operations to the evaporative facilities that Monarch acquired for a minimum 15-year period. The Purchase Agreement was subject to customary post-closing terms and conditions for transactions of this size and nature.

 

***Sale of Partial Working Interest in Producing Wells***

 

On March 19, 2010, we completed the sale of a partial working interest in 32 wells for $1.25 million. The 32 wells were part of a joint venture project that was started in 2002 under which each of the participants received a net profits interest in these wells for a period of twelve years from initial production date. We agreed to sell our interest in these wells related to the period subsequent to the initial twelve year period to one of the joint venture participants and to convert the purchaser’s net profits interest into a working interest.

 

***Prospect Fee***

 

During September 2010, we entered into an arrangement with an exploration and production company which operates in California, pursuant to which we received a $1.5 million prospect fee related to certain of our California acreage. The fee reimburses costs that we have invested in the area and provides us with a potential carried interest of 20% in two wells to be drilled on the acreage.  Additionally, the farmee is obligated to obtain and provide us a license to 3-D Seismic data over the contract area.

 

***Resignation of Former Chief Executive Officer; Appointment of Replacement***

 

Effective January 1, 2011, our plan of succession for changes in management, which was initially announced in September 2010, was completed.  Charles B. Crowell resigned as our interim Chief Executive Officer and was replaced by W. King Grant, our then President and Chief Financial Officer.  At that time, Mr. Grant resigned as Chief Financial Officer and Peggy Herald, our Vice President and Chief Accounting Officer is now our principal financial officer. Mr. Crowell maintains his position as Chairman of the Board of Directors of the Company; Mr. Grant also serves as a member of the Board of Directors.

 

***The Exchange Transaction***

 

During the second quarter of 2010, we completed the exchange of $64,532,000 aggregate principal amount of our 5.5% Convertible Senior Notes due 2011 (the “2011 Notes”) for $64,532,000 aggregate principal amount of our unsecured 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”),  which are convertible, at the option of the holder, into shares of our common stock and/or shares of a newly designated Series C Convertible Preferred Stock, par value $0.001 per share (the “Preferred Stock”), which are convertible into shares of common stock (the “Exchange Transaction”). We also paid to the holders of the 2011 Notes that participated in the Exchange Transaction an aggregate cash amount of $788,724.44, equal to all accrued but unpaid interest with respect to the 2011 Notes as of but not including the date of closing. The 2015 Notes were issued pursuant to the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), provided by Section 4(2) and Regulation D thereunder. The 2015 Notes have a final maturity date of October 5, 2015 and are governed by an indenture (the “Indenture”), dated as of June 25, 2010, by and between us and Wells Fargo Bank, National Association, as trustee (the “Trustee”). The Indenture contains usual and customary

 

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covenants limiting the Company’s ability to incur additional indebtedness, with certain exceptions, or liens on its property or assets, restricting its ability to make dividends or other distributions, requiring its domestic subsidiaries to guaranty the 2015 Notes, and requiring it to list the shares of common stock that may be issued upon conversion of the 2015 Notes and the Preferred Stock on the NYSE Amex or any other U.S. national or regional securities exchange on which the common stock is then listed.

 

The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock, other than pursuant to an automatic conversion (described below), is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the Indenture, we could not issue shares of common stock to holders of the 2015 Notes (including shares of common stock issuable upon a conversion of the 2015 Notes or upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes or in payment of any change of control purchase price, make whole premium or conversion make whole payment (each as described in the Indenture)) in excess of 19.9% of the number of shares of common stock outstanding immediately prior to the closing of the Exchange Transaction (the “Exchange Cap”), until stockholder approval of the issuance of common stock in excess of the Exchange Cap was obtained.

 

On September 15, 2010, at our 2010 Annual Meeting of Stockholders, we received stockholder approval for the issuance of all of the shares of common stock issuable upon conversion of our 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes in accordance with applicable law and the rules of the NYSE Amex. Accordingly, pursuant to the terms of the Indenture, on September 20, 2010, we effected the automatic conversion of thirty percent of the 2015 Notes, which equaled $19,364,000 aggregate principal amount, into 305,754 shares of Preferred Stock. We also paid an aggregate cash amount of $254,599, equal to all accrued but unpaid interest on the 2015 Notes subject to automatic conversion through September 20, 2010. See Note 4 “Convertible Senior Notes” to the accompanying consolidated financial statements for further discussion.

 

**Markets and Customers**

 

We focus our exploitation activities on locating natural gas and crude petroleum.  The success of our operations is dependent primarily upon prevailing and future prices for natural gas and, to a lesser extent, oil.  The higher market prices are, the more likely it is that we will be financially successful.  On the other hand, declines in natural gas or oil prices may have a material adverse affect on our financial condition, profitability and liquidity.  Lower prices also may reduce the amount of natural gas or oil that we can produce economically.  Natural gas and oil commodity prices are set by broad market forces, which have historically been and will likely continue to be volatile in the future.  Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control. Natural gas currently is selling at significantly lower prices than oil on an energy equivalent basis due to excess natural gas in storage and excess production concerns. Significant or extended price declines may adversely affect the amount of oil and natural gas that we can produce economically.

 

The principal markets for these commodities are natural gas transmission pipeline and marketing companies, utilities, refining companies and private industry end-users. We do not own or operate any natural gas lines or distribution facilities and rely on third parties to construct additional interstate pipelines to increase our ability to bring our production to market.  Any significant change affecting these facilities or our failure to obtain timely access to existing or future facilities on acceptable terms could restrict our ability to conduct normal operations.  Delays in the commencement of operations of new

 

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pipelines, the unavailability of new pipelines or other facilities due to market conditions, mechanical reasons or otherwise could have an adverse impact on our results of operations and financial condition.

 

Effective March 1, 2010, concurrent with the sale of our Gathering Assets (see “—2010 Highlights—Sale of Gathering Assets”), we entered into a gas gathering agreement with Monarch, pursuant to which Monarch provides gathering, compression and processing services utilizing the Gathering Assets to us. The gas gathering agreement covers the gathering, processing, compressing and delivery of our gross production of natural gas from all of our Utah acreage from wellheads to points of sale. Pursuant to the gas gathering agreement, Monarch is required to connect to the gathering system future wells that we drill within an area of mutual interest established thereunder. The gas gathering agreement provides for an initial gathering rate of $0.435 per MMBtu, plus 5% of the proceeds from the sale of natural gas and natural gas liquids. Any failure by Monarch or any successor thereto to timely perform its obligations under the gas gathering agreement may limit our ability to deliver production into the interstate pipeline where it is sold.  A delay or reduction in the amount of natural gas that we sell as a result of a failure by Monarch to timely perform such obligations or a delay or failure to connect future wells to the gathering system could have a material adverse effect on our business, financial condition or results of operations.

 

Historically, nearly all of our sales have been to a few customers. The majority of our production was sold to one customer, Anadarko Petroleum Corporation (“Anadarko”), during each of the years ended December 31, 2010, 2009 and 2008. For the years ended December 31, 2010, 2009 and 2008, purchases by the following companies exceeded 10% of our total oil and gas revenues.

 
| ** **                                                                     | ** ** | **For the Years Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                     | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                                                           |       |                                                          |       |   |   |   |   |
| Revenues associated with EnWest Marketing LLC   (“EnWest”) purchases |       | $                                                             | 2,604,206  |   | $ | 1,916,757 |   | $ | — |   |
| Revenues associated with Anadarko purchases                                    |       | $                                                             | 16,294,083 |   | $ | 13,173,402 |   | $ | 24,406,071 |   |
| Revenues associated with ConocoPhillips purchases                              |       | $                                                             | —     |   | $ | 13,429 |   | $ | 7,537,841 |   |
|                                                                           |       |                                                          |       |   |   |   |   |
| Percentage of oil and gas revenues attributable   to:                          |       |                                                          |       |   |   |   |   |
| EnWest                                                                         |       | 13                                                            | %          | 12 | % | — |   |
| Anadarko                                                                       |       | 83                                                            | %          | 84 | % | 68 | % |
| ConocoPhillips                                                                 |       | —                                                        |       | — |   | 21 | % |

 

We do not believe that the loss of a single purchaser, including Anadarko, would materially affect our business because there are other potential purchasers in the areas in which we sell our production.

 

**Competitive Business Conditions, Competitive Position in the Industry and Methods of Competition**

 

Our natural gas and petroleum exploration, exploitation and production activities take place in a highly competitive and speculative business atmosphere.  In seeking suitable natural gas and petroleum properties for acquisition, we compete with a number of other companies operating in our areas of interest, including large oil and gas companies and other independent operators.  Many of our competitors have greater financial resources, have been engaged in the exploration and production business for a much longer time than we have or not only explore for and produce, but also market natural gas and oil and other products on a regional, national or worldwide basis. Many of our competitors also have a substantially larger operating staff than we do.  These competitors may be able to pay more for productive natural gas and oil properties and exploratory prospects and define, evaluate, bid for and purchase a greater number of properties and prospects than us.  In addition, these competitors may have a greater

 

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ability to continue exploration activities during periods of low market prices.  Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

 

As discussed under “Item 1A—Risk Factors,” we are required to obtain drilling and right of way permits for our wells, and there is no assurance that such permits will be available timely or at all.

 

The prices of our products are controlled by regional, domestic and world markets.  However, competition in the petroleum and natural gas exploration, exploitation and production industry also exists in the form of competition to acquire the most promising acreage blocks and obtaining the most favorable prices for transporting the product.  We, and projects in which we participate, are relatively small compared to other petroleum and natural gas exploration, exploitation and production companies. As a result, we may have difficulty acquiring additional acreage and/or projects, and may have difficulty arranging for the transportation of the oil or natural gas we produce. We also face competition in obtaining natural gas and oil drilling rigs and in providing the manpower to operate them, as well as providing related services.

 

**Seasonal Nature of Business**

 

Generally, demand for natural gas decreases during the summer months, and increases during the winter months.  Seasonal anomalies such as mild winters or abnormally hot summers sometimes lessen this fluctuation.  In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer.  This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other natural gas and oil operations in certain areas. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

 

**Industry and Geographic Information**

 

We operate in one industry segment, which is the exploitation, development and production of natural gas and petroleum.  Our current operational activities are conducted in and our consolidated revenues are generated from markets within the United States and we have no long-lived assets located outside the United States.

 

**Governmental Regulations and Environmental Laws**

 

We are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.  These laws and regulations may require the acquisition of permits before drilling commences, limit or prohibit operations on environmentally sensitive lands such as wetlands or wilderness areas, require capital expenditures to limit or prevent emissions or discharges, and place restrictions on the management of wastes.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.  Any changes in environmental laws and regulations that result in more stringent and costly waste handling, disposal or cleanup requirements could have an adverse effect on our operations.  While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements would not materially affect us, there is no assurance that this trend will continue in the future.

 

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The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.  Under CERCLA, these “responsible persons” may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, 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 release of hazardous substances into the environment.  We also may incur liability under the Resource Conservation and Recovery Act (“RCRA”), which imposes requirements relating to the management and disposal of solid and hazardous wastes.  While there exists an exclusion from the definition of hazardous wastes for “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy,” in the course of our operations, we may generate ordinary industrial wastes, including paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous waste.

 

We currently own or lease, and have in the past owned or leased, properties that for a number of years have been used for the exploration and production of oil and gas.  Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal.  In addition, some of these properties may have been operated by third parties whose disposal or release of hydrocarbons or other wastes was not under our control.  These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws.  Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination or to perform remedial operations to prevent future contamination.

 

The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and gas wastes, into state or federal waters.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by United States Environmental Protection Agency (the “EPA”) or the state.  The Clean Water Act provides civil and criminal penalties for any discharge of oil in harmful quantities and imposes liabilities for the costs of removing an oil spill.

 

The Clean Air Act, as amended (the “CAA”), restricts the emission of air pollutants from many sources, including oil and gas operations.  New facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance.  In addition, the EPA has promulgated more stringent regulations governing emissions of toxic air pollutants from sources in the oil and gas industry, and these regulations may increase the costs of compliance for some facilities.

 

**EPA Enforcement Action**

 

In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), our wholly-owned subsidiary, who was preparing air emission calculations for possible future capacity expansions, preliminarily determined that Riverbend may have not accurately calculated the amount of air pollutants that could be emitted from certain existing equipment at its Riverbend Compressor Station in Uintah County, Utah.  Riverbend thereafter undertook a more detailed assessment, which confirmed that Riverbend had not obtained certain air permits nor complied with certain air pollution regulatory programs that were applicable to its operations at the Riverbend Compressor Station.  On June 22, 2007, Riverbend sent a letter to the United States Environmental Protection Agency (“EPA”) Region 8 office in

 

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Denver, Colorado, which—because the Riverbend Compressor Station is located in Indian Country—is the agency that has jurisdiction over federal air permitting and air pollution regulatory programs.  Riverbend’s June 22 letter voluntarily disclosed the potential violations to EPA and informed the agency of the steps that Riverbend had taken and planned to take to achieve compliance.  In November 2007, Riverbend met with EPA Region 8 personnel and discussed the disclosed violations, its plans to bring the Riverbend Compressor Station into compliance, and possible resolution of the disclosed violations.  These discussions culminated in the negotiation of a consent decree that was signed by the parties and lodged in the United States District Court of the District of Utah on December 30, 2010. The consent resolves the apparent violations, requires Gasco to pay a civil penalty of $350,000, specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that will authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented. The consent decree is awaiting entry by the court.

 

Under the Purchase Agreement dated January 29, 2010 by which we sold our Gathering Assets located in Uintah County, Utah to Monarch, we retained the obligation to pay any civil penalty assessed and the capital cost of the equipment required to be installed pursuant to the consent decree, and we also agreed to reimburse Monarch for certain miscellaneous expenses incurred to finalize the consent decree and obtain certain changes to the Riverbend Compressor Station’s air permits that are required by the consent decree.  Monarch is also a party to the consent decree and will be responsible for implementing most of the consent decree requirements at the Riverbend Compressor Station other than the payment of a civil penalty and the installation of capital equipment.  We believe that all necessary pollution control and other equipment required by the consent decree is already installed at the site or accounted for in our capital budget, and that the civil penalty and the other expenses required by the consent decree will not materially affect our financial position or liquidity.

 

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, 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’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules.

 

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

 

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legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced.  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.

 

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods.  If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance.  Another possible consequence of climate change is increased volatility in seasonal temperatures.  The ultimate market for some of our natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market the fuels that we produce.  Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience substantially colder temperatures than their historical averages.  As a result, it is difficult to predict how the market for our fuels would be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it **c**ould have an adverse effect on our business.

 

Under the National Environmental Policy Act (the “NEPA”), a federal agency, in conjunction with a permit holder, may be required to prepare an environmental assessment or a detailed environmental impact statement (“EIS”) before issuing a permit that may significantly affect the quality of the environment. We are currently working with the U.S. Bureau of Land Management (“BLM”) regarding the preparation of an EIS in connection with certain proposed exploration and production operations in the Uinta Basin of Utah.  We expect that the EIS will be approved no earlier than the second half of 2010 and will potentially allow us to drill approximately 1,500 wells in the development phase.  Until the EIS is completed and issued by the BLM, we will be limited in the number of oil and gas wells that we can drill in the areas undergoing EIS review. While we do not expect that the EIS process will result in a significant curtailment in future oil and gas production from this particular area, we can provide no assurance regarding the outcome of the EIS process.

 

**Corporate Office**

 

Our corporate office is located at 8 Inverness Drive East, Suite 100, Englewood, Colorado, where we lease 11,840 square feet.

 

**Insurance Matters**

 

As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is unavailable or because premium costs are considered prohibitive.  A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations or cash flows.  We maintain insurance at customary industry levels to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of certain prohibited substances into the environment.  Such insurance might not cover the complete amount of such a claim and would not cover fines or penalties for a violation of an environmental law.  In analyzing our operations and insurance needs, we compare premium costs to the likelihood of material loss of production. Based on this analysis,  policies we carry are: property insurance, Commercial General Liability,  Umbrella Liability, Fiduciary Liability, and Control of Well.

 

**Employees**

 

As of March 2, 2011, we had 25 full-time employees.

 

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**Available Information**

 

We file annual, quarterly and current reports, proxy statements and other information electronically with the Securities and Exchange Commission (“SEC”).  You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F. Street, NE, Washington, DC 20549.  You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including our filings.

 

Our internet address is www.gascoenergy.com.  We make available free of charge on or through our internet site our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. None of the information on our website should be considered incorporated into or a part of this Form 10-K.

 

**CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS**

 

Some of the information in this Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, Section 21E of the Private Securities Litigation Reform Act of 1995.  All statements other than statements of historical facts included in this report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.  These statements express, or are based on, our expectations about future events. Forward-looking statements give our current expectations or forecasts of future events. Forward-looking statements generally can be identified by the use of forward looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe” or “continue” or the negative thereof or similar terminology.

 

Although any forward-looking statements contained in this Form 10-K or otherwise expressed by or on behalf of the Company are, to the knowledge and in the judgment of the officers and directors of the Company, believed to be reasonable, there can be no assurances that any of these expectations will prove correct or that any of the actions that are planned will be taken. Forward-looking statements involve and can be affected by inaccurate assumptions or by known and unknown risks and uncertainties which may cause the Company’s actual performance and financial results in future periods to differ materially from any projection, estimate or forecasted result. Important factors that could cause actual results to differ materially from expected results include, but are not limited to, those discussed in (1) Part I, “Item 1A— Risk Factors,” “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Item 7A—Quantitative and Qualitative Disclosure About Market Risk” and elsewhere in this report, and (2) our reports and registration statements filed from time to time with the SEC.

 

The following are among the important factors that could cause future results to differ materially from any projected, forecasted, estimated or budgeted amounts that we have discussed in this report:

 

·                  fluctuations in natural gas and oil prices;

 

·                  pipeline constraints;

 

·                  overall demand for natural gas and oil in the United States;

 

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·                  changes in general economic conditions in the United States;

 

·                  our ability to manage interest rate and commodity price exposure;

 

·                  changes in our borrowing arrangements;

 

·                  our ability to generate sufficient cash flow to operate;

 

·                  the condition of credit and capital markets in the United States;

 

·                  the amount, nature and timing of capital expenditures;

 

·                  drilling of wells;

 

·                  acquisition and development of oil and gas properties;

 

·                  operating hazards inherent to the natural gas and oil business;

 

·                  timing and amount of future production of natural gas and oil;

 

·                  operating costs and other expenses;

 

·                  cash flow and anticipated liquidity;

 

·                  future operating results;

 

·                  marketing of oil and natural gas;

 

·                  competition and regulation; and

 

·                  plans, objectives and expectations.

 

Any of these factors could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. We cannot assure you that our future results will meet our expectations. When you consider these forward-looking statements, you should keep in mind these factors.  All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by these factors.  Our forward-looking statements speak only as of the date made. The Company assumes no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.

 

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**GLOSSARY OF NATURAL GAS AND OIL TERMS**

 

The following is a description of the meanings of some of the natural gas and oil industry terms used in this Annual Report on Form 10-K.

 

*Bbl*.  One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.

 

*Bbl/d*.  One Bbl per day.

 

*Bcf*.  Billion cubic feet of natural gas.

 

*Bcfe*.  Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

*Btu or British Thermal Unit*.  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

 

*Completion*.  The installation of permanent equipment for the production of natural gas or oil, or in the case of a dry well, the reporting of abandonment to the appropriate agency.

 

*Condensate*. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

 

*Developed acreage*.  The number of acres that are allocated or assignable to productive wells or wells capable of production.

 

*Development well*.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

*Dry well*.  An exploratory or development well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

 

*Exploratory well*.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil and gas in another reservoir.

 

*Farm-in or farm-out*.  An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage.  Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage.  The assignor usually retains a royalty or reversionary interest in the lease.  The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

 

*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.

 

*Gross acres or gross wells*.  The total acres or wells, as the case may be, in which a working interest is owned.

 

*Lead*.  A specific geographic area which, based on supporting geological, geophysical or other data, is deemed to have potential for the discovery of commercial hydrocarbons.

 

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*MBbls*.  Thousand barrels of crude oil or other liquid hydrocarbons.

 

*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.

 

*MMBls*.  Million barrels of crude oil or other liquid hydrocarbons.

 

*MMBtu*.  Million British Thermal Units.

 

*MMcf*.  Million cubic feet of natural gas.

 

*MMcf/d*.  One MMcf per day.

 

*MMcfe*.  Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

 

*Net acres or net wells*.  The sum of the fractional working interest owned in gross acres or wells, as the case may be.

 

*Net feet of pay*.  The true vertical thickness of reservoir rock estimated to both contain hydrocarbons and be capable of contributing to producing rates.

 

*Present value of future net revenues or present value of discounted future net cash flows or present value or PV-10*.  The pre-tax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

 

*Productive well*.  A producing well and a well that is found to be mechanically capable of production.

 

*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.

 

*Proved area*.  The part of a property to which proved reserves have been specifically attributed.

 

*Proved developed oil and gas reserves*.  Proved developed oil and gas reserves are reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

*Proved oil and gas reserves*. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be

 

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economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

(i)                                     The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

(ii)                                  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii)                               Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

(iv)                              Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development  by all necessary parties and entities, including governmental entities.

 

(v)                                 Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

*Proved properties*.  Properties with proved reserves.

 

*Proved undeveloped reserves*.  Undeveloped oil and gas reserves are reserves of any category 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.

 

(i)                                                      Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

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(ii)                                                   Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

(iii)                                                Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

 

*Reservoir*. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

*Service well.*  A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

 

*Standardized Measure of Discounted Future Net Cash Flows.*    The discounted future net cash flows relating to proved reserves based on average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period and period-end costs and statutory tax rates (adjusted for permanent differences) and a 10-percent annual discount rate.

 

*Stratigraphic test well*. A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily arc drilled without the intent of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (a) “exploratory type,” if not drilled in a proved area, or (b) “development type,” if drilled in a proved area.

 

*Undeveloped acreage*.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

 

*Unproved properties*.  Properties with no proved reserves.

 

*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.

 

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**ITEM 1A. Risk Factors**

 

Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following material risks and all other information set forth in this Annual Report on Form 10-K.

 

If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected.

 

***We have incurred losses and may continue to incur losses in the future.***

 

Historically, other than for the years ended December 31, 2010 and 2008, we have generated losses which have not provided sufficient cash flows to provide working capital for our ongoing overhead, the funding of our lease acquisitions and the exploration and development of our properties.  As such, and in light of the volatile nature of commodity price levels and other uncertainties described in this “Item 1A— Risk Factors” and elsewhere in this Annual Report on Form 10-K, we may not be able to successfully develop any prospects that we have or acquire any additional properties without adequate financing and we may not achieve profitability from operations in the near future or at all.

 

During the year ended December 31, 2009, we incurred a net loss of $50,188,171.  As of December 31, 2010, we had an accumulated deficit of $215,327,315.  Our failure to achieve profitability in the future could adversely affect the trading price of our common stock or our ability to raise additional capital. Any of these circumstances could have a material adverse effect on our business, financial condition and results of operations.

 

***We may not be able to maintain adequate cash flow from operations or obtain adequate financing to fund our capital expenditures, meet working capital needs or grow our operations.***

 

We will require significant additional capital to fund our future drilling activities and to meet our future debt maturities. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to service our indebtedness, meet our working capital needs or achieve our planned growth and operating results. We have relied in the past primarily on the sale of equity capital, the issuance of equity, borrowings under our revolving credit facility and farm-out and other similar types of transactions to fund working capital and the acquisition of our prospects and related leases. Failure to generate operating cash flow or to obtain additional financing for the development of our properties could result in substantial dilution of our property interests or delay or cause indefinite postponement of further exploration and development of our prospects with the possible loss of our properties. This could cause us to alter our business plans, including further reducing our exploration and development plans.

 

In particular, we face uncertainties relating to our ability to generate sufficient cash flows from operations to fund the level of capital expenditures required for oil and gas exploration and production activities beyond our planned recompletion activities, including those reflected in our 2011 budget. We intend to fund our capital budget for 2011 of $6 million through cash on hand, cash flows from operations and borrowings under our revolving credit facility. Effective February 26, 2010, our borrowing base under our revolving credit facility was reduced to $16 million from $35 million and as of March 2, 2011, we had $6.5 million of outstanding borrowings thereunder. Our borrowing base could be further reduced in the future by our lenders.  An inability to access additional borrowings in excess of our existing $9.4 million of capacity under our revolving credit agreement will limit our ability to increase our operating budget and execute on our growth plans.

 

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If we need additional liquidity for future activities, including paying amounts owed in connection with a borrowing base reduction, if any, we may be required to consider several options for raising additional funds, such as selling securities, selling assets or farm-outs or similar arrangements, but we may be unable to complete any of these transactions on terms acceptable to us or at all. Any financing obtained through the sale of our equity will likely result in substantial dilution to our stockholders.

 

Our failure to find the financial resources necessary to fund our planned activities and service our debt and other obligations could materially and adversely affect our business, financial condition and results of operations.

 

***Lower oil and natural gas prices could negatively impact our borrowing base under our revolving credit facility.***

 

The amount available for borrowing under our revolving credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to scheduled periodic redeterminations, as well as unscheduled discretionary redeterminations, based on pricing models and other economic assumptions determined by the lenders at such time. Effective February 26, 2010, our borrowing base under our revolving credit agreement was reduced to $16 million from $35 million. The decline in oil and natural gas prices has adversely affected the value of our estimated proved reserves and, in turn, the pricing assumptions used by our lenders to determine our borrowing base. If commodity prices remain at current levels or decline in 2011, it will have similar material adverse effects on our reserves and global borrowing base.

 

***Lower oil and gas prices and other factors, including downward revisions of the present value of our proved reserves and increased drilling expenditures without current additions to proved reserves, have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values. We are subject to the full cost ceiling limitation which has resulted in past write-downs of estimated net reserves and may result in a write-down in the future if commodity prices continue to decline.***

 

We may be required to write down the carrying value of our gas and oil properties when gas and oil prices are low or if there are substantial downward adjustments to our estimated proved reserves, increases in the estimates of development costs or deterioration in the exploration results. Because we have elected to use the full-cost accounting method, we are subject to quarterly calculations of a “ceiling” or limitation on the amount of our oil and gas properties that can be capitalized on our balance sheet.  As explained below, the discounted present value of our proved reserves is a major component of the ceiling calculation and the risk that we will be required to write down the carrying value of oil and natural gas properties increases when natural gas and crude oil prices are depressed or volatile.  Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges against current earnings.

 

Under the full cost method of accounting, capitalized gas and oil 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 gas and oil 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 and the costs of any property not being amortized.

 

If the net capitalized costs of our oil and gas properties exceed the cost ceiling, we are subject to a ceiling test write-down of our estimated net reserves to the extent of such excess. The present value of estimated future net revenues is computed by applying the twelve month trailing average first-of-month prices of

 

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gas and oil to estimated future production of proved gas and oil reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. Expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling applicable in the subsequent period.

 

As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf by $41,000,000. Therefore, impairment expense of $41,000,000 was recorded during the year ended December 31, 2009.

 

Our evaluation of impairment of unproved properties incorporates our expectations of developing unproved properties given current and forward-looking economic conditions and commodity prices. Investments in unproved properties with a carrying value of approximately $35,941,100 as of December 31, 2010, including capitalized interest costs, are assessed periodically to ascertain whether impairment has occurred. Impairments in such properties may result from lower commodity prices, expiration of leases, inability to find partners, inadequate financing or unsuccessful drilling results. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized, or is reported as a period expense, as appropriate. If an impairment of unproved properties results in a reclassification to proved oil and gas properties, the ceiling test cushion would be reduced.

 

We believe that the majority of our remaining unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before we can explore or develop it further, or by making decisions that further exploration and development activity will not occur.

 

During 2010, we reclassified approximately $3,000,000 of acreage costs primarily in Utah, into proved property. This acreage represents the leases that will expire during 2011 before we are able to develop them further and a decrease in the carrying value of our acreage based upon an independent appraisal as of December 31, 2010.

 

***Lower oil and natural gas prices could negatively impact our ability to produce economically.***

 

Lower natural gas and oil prices may not only decrease our revenue, but also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. This reduction may also result in our having to make substantial downward adjustments to our estimated proved reserves. For example, during 2009, the previous oil and gas reserves quantities decreased by approximately 6% primarily due to the decrease in gas prices used to estimate reserve quantities, from $4.63 per mcf at December 31, 2008 to $2.85 per mcf at December 31, 2009. This decrease in reserve quantities was partially offset by an increase in the oil price from $15.34 per bbl at December 31, 2008 to $44.46 per bbl at December 31, 2009. The price per barrel of oil reflects our blend of oil and condensate. If the prices for oil and gas decrease materially from year end 2010 prices we will be unable to economically develop most of our acreage. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

 

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***Availability under our revolving credit facility is based on a borrowing base which is subject to redetermination by our lenders.  If our borrowing base is reduced, we may be required to repay amounts outstanding under our revolving credit facility.***

 

Our revolving credit facility limits our borrowings to the borrowing base less our total outstanding letters of credit issued thereunder. In February 2010, our borrowing base was reduced to $16 million and as of March 2, 2011, we had $6.5 million of outstanding borrowings thereunder (see Note 8 “Credit Facility” to the accompanying consolidated financial statements for further discussion). Our borrowing base could be further reduced in the future by our lenders. Under the terms of our revolving credit facility, our borrowing base is subject to semi-annual redetermination by our lenders based on their valuation of our proved reserves and their internal criteria. In addition to such semi-annual determinations, our lenders may request one additional borrowing base redetermination between each semi-annual calculation. Our next borrowing base redetermination is scheduled for May 2011.

 

If our borrowing base is further reduced as a result of a redetermination to a level below our then current outstanding borrowings, we will be required to repay the amount by which such outstanding borrowings exceed the borrowing base within 30 days of notification by the lenders and we will have less or no access to borrowed capital going forward. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our revolving credit facility or sell assets or additional shares of common stock. We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all.  Failure to make the required repayment would result in a default under our revolving credit facility, which would, absent a waiver or amendment,  entitle the lenders to terminate their aggregate commitment under the revolving credit facility and declare our outstanding borrowings immediately due and payable in whole. Additionally, should our obligation to repay indebtedness under our revolving credit facility be accelerated, we would be in default under the indenture governing our 2011 Notes and our 2015 Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on the notes.  As such, should we anticipate that we will not be able to repay all amounts owed under the Credit Facility as a result of the anticipated borrowing base redetermination, we will consider, along with previously discussed refinancing and sales, a sale of our company or our assets as well as a voluntary reorganization in bankruptcy. Additionally, if we are unable to repay amounts owed under the Credit Facility, the 2015 Notes and the 2011 Notes, we may be forced into an involuntary reorganization in bankruptcy. Please read “Item 7. Management’s Discussion and Analysis of Financial Position and Results of Operations — Liquidity and Capital Resources — Credit Facility.”

 

***Oil and natural gas prices are volatile. The extended decline in commodity prices has adversely affected, and in the future will continue to adversely affect, our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.***

 

Our financial condition, operating results, and future rate of growth depend primarily upon the prices that we receive for our oil and natural gas. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our revolving credit facility and through the capital markets. Natural gas and oil commodity prices are set by broad market forces, which historically have been and are likely to remain volatile in the future. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

·                  changes in global supply and demand for natural gas and oil;

 

·                  commodity processing, gathering and transportation availability;

 

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·                  domestic and global political and economic conditions; 

 

·                  the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; 

 

·                  weather conditions, including hurricanes;

 

·                  technological advances affecting energy consumption;

 

·                  an increase in alternative fuel sources;

 

·                  higher fuel taxes and other regulatory actions;

 

·                  an increase in fuel economy;

 

·                  additional domestic and foreign governmental regulations; and

 

·                  the price and availability of alternative fuels.

 

***Our success is influenced by natural gas prices in the specific area where we operate, and these prices may be lower than prices at major markets.***

 

Regional natural gas prices may move independent of broad industry price trends.  Because some of our operations are located outside major markets, we are directly impacted by regional natural gas prices regardless of major market pricing. All of our natural gas production is currently located in, and all of our future natural gas production is anticipated to be located in, the Rocky Mountain Region of the United States.  The gas prices that we and other operators in the Rocky Mountain region have received and are receiving are at a discount to gas prices in other parts of the country.

 

Additional factors that can cause price volatility for crude oil and natural gas within this region are:

 

·                  the availability of gathering systems with sufficient capacity to handle local production;

 

·                  seasonal fluctuations in local demand for production;

 

·                  local and national gas storage capacity;

 

·                  interstate pipeline capacity; and

 

·                  the availability and cost of gas transportation facilities from the Rocky Mountain region.

 

It is impossible to predict natural gas and oil price movements with certainty. A substantial or extended decline in natural gas and oil prices would materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.

 

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***Our revolving credit facility imposes restrictions on us that may affect our ability to successfully operate our business.***

 

Our revolving credit facility and indentures impose certain operational and financial restrictions on us that limit our ability to:

 

·                  incur additional indebtedness;

 

·                  create liens;

 

·                  sell our assets to, or consolidate or merge with or into, other companies;

 

·                  make investments and other restricted payments, including dividends; and

 

·                  engage in transactions with affiliates.

 

Our revolving credit facility contains covenants that require us to maintain (1) a current ratio (defined as current assets plus unused availability under the revolving credit facility divided by current liabilities excluding the current portion of the revolving credit facility), determined at the end of each quarter, of not less than 1:1; and (2) a ratio of senior debt to EBITDAX (as such term is defined in the revolving credit facility) for the most recent four quarters not to be greater than 3.5:1 for each fiscal quarter.  In addition, the revolving credit facility contains covenants that restrict our ability to incur other indebtedness, create liens or sell our assets, pay dividends on our common stock and make certain investments. As of December 31, 2010, our current and senior debt to EBITDAX ratios were 2.2:1 and 0.9:1, respectively, and we were in compliance with each of the covenants as of December 31, 2010.  Sustained or lower oil and natural gas prices and the impact of the sale of our gathering system could reduce our consolidated EBITDAX and thus could reduce our ability to maintain existing levels of senior debt or incur additional indebtedness.

 

The Indenture contains usual and customary covenants limiting the Company’s ability to incur additional indebtedness, with certain exceptions, or liens on its property or assets and restricting its ability to make dividends or other distributions.  Any failure to be in compliance with any material provision or covenant of our revolving credit facility or indentures could result in a default which would, absent a waiver or amendment, require immediate repayment of the related outstanding indebtedness.  Additionally, should our obligation to repay indebtedness under our revolving credit facility be accelerated, we would be in default under the indenture governing our 2011 Notes and our 2015 Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes.  Sustained or lower oil and natural gas prices could reduce our consolidated EBITDAX and thus could reduce our ability to maintain existing levels of senior debt or incur additional indebtedness.  Sustained or lower oil and natural gas prices may make it more difficult for us to satisfy this ratio in future quarters.  To the extent it becomes necessary to address any anticipated covenant compliance issues, we may be required to sell a portion of our assets or issue additional securities, which would be dilutive to our shareholders.  Given the condition of current credit and capital markets, any sale of assets or issuance of additional securities may not be on terms acceptable to us.

 

The restrictions under our revolving credit facility and indentures could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. Any failure to remedy any event of default could have a material adverse effect on our business, financial condition or results of operations.

 

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***The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.***

 

To mitigate the impact of lower commodity prices on our cash flows, we entered into commodity derivative instruments through 2012 (see Note 5 “Derivatives” of the accompanying consolidated financial statements for further discussion).

 

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.  The new legislation, know as the Dodd-Frank Wall Street Reform and Consumer Protection Act, (the “Act”) was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment.  In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to us is uncertain at this time.  The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

 

The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.  Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.  Any of these consequences could have an adverse effect on us, our financial condition, and our results of operations.

*** ***

***A failure by the gatherer of our natural gas to perform its obligations under our gas gathering agreement may negatively affect our ability to deliver our natural gas production for sale.***

 

Pursuant to a gas gathering agreement executed in February 2010 concurrent with the sale of substantially all of our Gathering Assets, we rely on Monarch to gather, process, compress and deliver our natural gas production from wellheads to points of sale.  Additionally, pursuant to the gas gathering agreement, Monarch is required to connect to the gathering system future wells that we drill within an area of mutual interest established thereunder. Any failure by Monarch or any successor thereto to timely perform its obligations under the gas gathering agreement may limit our ability to deliver production into the interstate pipeline where it is sold.  A delay or reduction in the amount of natural gas that we sell as a result of a failure by Monarch to timely perform such obligations or a delay or failure to connect future wells to the gathering system could have a material adverse effect on our business, financial condition or results of operations.

 

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***Our ability to market the oil and gas that we produce is essential to our business. Pipeline constraints may limit our ability to sell production and may negatively affect the price at which we sell our production, which could have an adverse impact on our results of operations and financial condition.***

 

Several factors beyond our control may adversely affect our ability to market the oil and gas that we discover.  These factors include the proximity, capacity and availability of oil and gas pipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection.  The extent of these factors cannot be accurately predicted, but any one or a combination of these factors may result in our inability to sell our oil and gas at prices that would result in an adequate return on our invested capital.

 

We currently distribute the gas that we produce through a single interstate pipeline. Any constraints on the capacity of this pipeline could adversely affect our ability to sell production and, in certain circumstances, may limit our ability to sell any or all of our production in a given period. If this pipeline were to become unavailable, we would incur additional costs to secure a substitute facility in order to deliver the gas that we produce. In addition, although we currently have access to firm transportation for the majority of our current gas production, there is no assurance that we will be able to procure additional transportation on terms satisfactory to us, or at all, if we increase our production through our drilling program or acquisitions.

 

Delays in the commencement of operations of new pipelines, the unavailability of the new pipelines or other facilities due to market conditions, mechanical reasons or otherwise could have an adverse impact on our results of operations and financial condition. Pipeline capacity constraint could also lead to heightened price competition on such pipeline, which would reduce the price at which we are able to sell the production that does flow. A reduction in the amount of natural gas that we can sell or the price at which such natural gas can be sold could have a material adverse effect on our business, financial condition or results of operations.

 

Further, interstate transportation and distribution of natural gas is regulated by the federal government through the FERC. FERC sets rules and carries out administratively the oversight of interstate markets for natural gas and other energy policy.   Additionally, state regulators have powers over sale, supply and delivery of natural gas and oil within their state borders.  While we do employ certain companies to represent our interests before state regulatory agencies, our interests may not receive favorable rulings from any state agency, or some future occurrence may drastically alter our ability to enter into contracts or deliver natural gas to the market.

 

***Approximately 14% of our proved reserves are classified as proved developed non-producing and may ultimately prove to be less than estimated.***

 

At December 31, 2010, approximately 14% of our total proved reserves were classified as proved developed non-producing.  It will take substantial capital to recomplete or drill our non-producing.  Our estimate of proved reserves at December 31, 2010 assumes that we will spend significant development capital expenditures to develop these reserves, including an estimated $3.4 million in 2011.  Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

 

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***Our estimates of proved reserves have been prepared under the SEC rules that went into effect for fiscal years ending on or after December 31, 2009, which may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.***

 

This Annual Report on Form 10-K presents estimates of our proved reserves as of December 31, 2010 and 2009, which have been prepared and presented under current SEC rules that went into effect for fiscal years ending on or after December 31, 2009. These rules require SEC reporting companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on twelve-month unweighted first-day-of-the-month average pricing. The previous rules required that reserve estimates be calculated using last-day-of-the-year pricing. Under the current rules, the pricing that was used for estimates of our reserves as of December 31, 2010 and 2009 was based on an unweighted average 12-month average price, as compared to the end of the year price that was used as of December 31, 2008. As a result of these changes, direct comparisons to our previously-reported reserves amounts may be more difficult.

 

Additionally, under the current SEC rules there is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This rule has limited and may continue to limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill on those reserves within the required five-year timeframe.

 

***Our proved reserves are estimates and depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates, that may turn out to be inaccurate. Any material inaccuracies in these in these reserve estimates or underlying assumptions could cause the quantity and value of our oil and gas reserves, and our revenue, profitability, and cash flow, to be materially different from our estimates.***

 

Estimating accumulations of gas and oil is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering, production and other technical data the extent, quality and reliability of which can vary.  The process also requires certain economic assumptions, some of which are mandated by the SEC. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves.

 

There are many uncertainties inherent in estimating natural gas and oil reserves and their values, many of which are beyond our control.  Estimates of economically recoverable natural gas or oil reserves and of future net cash flows necessarily depend on many variables and assumptions, such as:

 

·                                          Historical natural gas or oil production from that area, compared with production from other producing areas;

 

·                                          Assumptions concerning the effects of regulations by governmental agencies;

 

·                                          Assumptions concerning future prices;

 

·                                          Assumptions concerning future operating costs;

 

·                                          Assumptions concerning severance and excise taxes; and

 

·                                          Assumptions concerning development costs and workover and remedial costs.

 

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Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from our estimates.  Any significant variance could materially affect the quantities and present value of our reserves.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development and prevailing gas and oil prices.  Our reserves may also be susceptible to drainage by operators on adjacent properties.

 

For these reasons, estimates of the economically recoverable quantities of natural gas or oil attributable to any particular group of properties, classifications of those reserves based on risk recovery and estimates of the future net cash flows expected from them prepared by different engineers, or by the same engineer at different times may vary substantially.  Because of this, our reserve estimates may materially change at any time.

 

The most accurate method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data.  The accuracy of the decline analysis method generally increases with the length of the production history.  Since most of our wells had been producing less than ten years as of December 31, 2010, their production history was relatively short, so other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir were used in conjunction with the decline analysis method to determine our estimates of proved reserves as of December 31, 2010.  As our wells are produced over time and more data is available, the estimated proved reserves will be redetermined on an annual basis and may be adjusted based on that data. These adjustments could result in downward revisions of our reserve estimates.

 

Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from our estimates.  Any significant variance could materially affect the quantities and present value of our reserves.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development and prevailing gas and oil prices.  Our reserves may also be susceptible to drainage by operators on adjacent properties.

 

It should not be assumed that the present value of future net cash flows included herein is the current market value of our estimated proved gas and oil reserves.  In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on the unweighted arithmetic average of the first-day-of-the-month commodity prices for the trailing twelve months and development and production costs on the date of estimate.  Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. This price and rate are not necessarily the most appropriate price or discount factor based on prices and interest rates in effect from time to time and risks associated with our reserves or the natural gas and oil industry in general. Current or actual future prices and costs may be materially higher or lower.  Actual future net cash flows also will be affected by factors such as:

 

·                  The amount and timing of actual production;

 

·                  Supply and demand for natural gas or oil;

 

·                  Actual prices received for natural gas in the future being different than those used in the estimate;

 

·                  Curtailments or increases in consumption of natural gas or oil;

 

·                  Changes in governmental regulations or taxation; and

 

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·                  The timing of both production and expenses in connection with the development and production of natural gas or oil properties.

 

***The exploration and development of oil and gas properties involves substantial risks that may materially and adversely affect us.***

 

Our future success will largely depend on the success of our exploration drilling program. The business of exploring for and producing oil and gas involves a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome.  Drilling oil and gas wells involves the risk that the wells will be unproductive or that, although productive, the wells do not produce oil and/or gas in economic quantities.  The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including, but not limited to:

 

·                  Unexpected drilling conditions;

 

·                  Blowouts, fires or explosions with resultant injury, death or environmental damage;

 

·                  Pressure or irregularities in formations;

 

·                  Equipment failures or accidents;

 

·                  Adverse weather conditions;

 

·                  Compliance with governmental requirements and laws, present and future; and

 

·                  Shortages or delays in the availability of drilling rigs and the delivery of equipment.

 

A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well.  In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

 

If we experience any one or more of these risks, our business, financial condition and results of operations could be materially and adversely affected.

*** ***

***Natural gas and oil reserves are depleting assets, and the failure to replace our reserves would adversely affect our production and cash flows.***

 

Our future natural gas and oil production depends on our success in finding or acquiring new reserves.  If we fail to replace reserves, our level of production and cash flows would be adversely impacted.  Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics.  Our total proved reserves will decline as reserves are produced unless we conduct successful exploration and development activities and/or acquire properties containing proved reserves.  Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable.  Further, we may not be successful in exploring for, developing or acquiring additional reserves, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

 

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*** ***

***Delays in obtaining drilling permits could have a material adverse effect on our ability to develop our properties in a timely manner.***

 

The average processing time at the Bureau of Land Management in Vernal, Utah for an application to drill on federal leases has been increasing and currently is approximately 23 to 24 months. Approximately 82% of our gross acreage in Utah is located on federal leases. If we are delayed in procuring sufficient drilling permits for our federal properties, we may shift more of our drilling in Utah to our state leases, the permits for which require an average processing time of approximately 60 days. While such a shift in resources would not necessarily affect the rate of growth of our cash flow, it would result in a slower growth rate of our total proved reserves, because a higher percentage of the wells drilled on the state leases would be drilled on leases to which proved undeveloped reserves may already have been attributed.

*** ***

***Our drilling operations may be delayed or revised unless we receive approval of our Environmental Impact Statement.***

 

As we continue to develop our Utah acreage, we are required to file an Environmental Impact Statement under the National Environmental Policy Act. Any delay of approval or mandated change to our plan of development may materially delay our ability to drill on our acreage in Utah or may require us to make additional capital investments or make certain areas of our acreage inaccessible to drilling. Any delay of or restriction on our ability to drill on our acreage in Utah could materially and adversely affect our future business, financial condition and results of operations.

*** ***

***We may have difficulty managing any growth in our business****.*

 

Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources.  If we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources.  The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

*** ***

***Competition in the natural gas and oil industry is intense.********Our competitors may have greater resources which could enable them to pay a higher price for properties and to better withstand periods of low market prices for hydrocarbons.***

 

The petroleum and natural gas industry is intensely competitive, and we compete with other companies with greater resources.  Many of these companies not only explore for and produce crude petroleum and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis.  Many of our competitors are large, well-established companies that have a substantially larger operating staff and greater capital resources than we do and, in many instances, have been engaged in the natural gas and oil business for a much longer time than we have.  These companies may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase more properties and prospects than our financial and human resources permit. These companies may also be able to spend more on the existing and changing technologies that we believe are and will be increasingly important to the current and future success of natural gas and oil companies. In addition, such companies may have a greater ability to continue exploration activities during periods of low hydrocarbon market prices.  Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Increased 

 

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competitive pressure could have a material adverse effect on our financial condition, future cash flows and the results of operations.

 

***Acquisition prospects are difficult to assess and may pose additional risks to our operations.***

 

Where appropriate, we may evaluate and pursue acquisition opportunities on terms our management considers favorable.  The successful acquisition of natural gas and oil properties requires an assessment of:

 

·                  Recoverable reserves;

 

·                  Exploration potential;

 

·                  Future natural gas and oil prices;

 

·                  Operating costs;

 

·                  Potential environmental and other liabilities; and

 

·                  Permitting and other environmental authorizations required for our operations.

 

In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices.  Nonetheless, the resulting conclusions are inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies.  Inspections may not always be performed on every facility or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.  Future acquisitions could pose additional risks to our operations and financial results, including:

 

·                  Problems integrating the purchased operations, personnel or technologies;

 

·                  Unanticipated costs;

 

·                  Diversion of resources and management attention from our exploration business;

 

·                  Entry into regions or markets in which we have limited or no prior experience; and

 

·                  Potential loss of key employees, particularly those of the acquired organization.

*** ***

***We may suffer losses or incur liability for events that we have, or that the operator of a property has, chosen not to insure against.***

 

The natural gas and oil business involves many operating hazards, such as:

 

·                  Well blowouts, fires and explosions;

 

·                  Surface craterings and casing collapses;

 

·                  Uncontrollable flows of natural gas, oil or well fluids;

 

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·                  Pipe and cement failures;

 

·                  Formations with abnormal pressures;

 

·                  Stuck drilling and service tools;

 

·                  Pipeline ruptures or spills;

 

·                  Natural disasters; and

 

·                  Releases of toxic natural gas.

 

Any of these events could cause substantial losses to us as a result of:

 

·                  Injury or death;

 

·                  Damage to and destruction of property, natural resources and equipment;

 

·                  Pollution and other environmental damage;

 

·                  Regulatory investigations and penalties;

 

·                  Suspension of operations; and

 

·                  Repair and remediation costs.

 

Insurance against every operational risk is not available at economic rates. We may suffer losses from hazards that we cannot insure against or that we have, or the operator thereof has, chosen not to insure against because of high premium costs or other reasons.  We could also be responsible for environmental damage caused by previous owners of property from whom we purchased leases.  As a result, we may incur substantial liabilities to third parties or governmental entities. If these liabilities are not covered by our insurance, paying them could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties. The payment of any such liabilities may have a material adverse effect on our business, financial condition and results of operations.

*** ***

***We may incur losses as a result of title deficiencies in the properties in which we invest*****.**

 

If an examination of the title history of a property that we have purchased reveals a petroleum and natural gas lease that has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless.  In such an instance, the amount paid for such petroleum and natural gas lease or leases would be lost.

 

It is our practice, in acquiring petroleum and natural gas leases, or undivided interests in petroleum and natural gas leases, not to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease.  Rather, we will rely upon the judgment of petroleum and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

 

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If there are any title defects in the properties in which we hold an interest, we may not be able to proceed with our exploration and development of the lease site or may suffer a monetary loss, including as a result of performing any necessary curative work prior to the drilling of a petroleum and natural gas well.

*** ***

***Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities and******could materially affect our cash flow.***

 

Our operations are subject to stringent federal, state and local laws and regulations relating to environmental protection.  There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to our operations, and historical industry operations and waste disposal practices.  Failure to comply with these laws may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may delay or prevent our operations.  Under certain environmental laws and regulations, we could be subject to strict, joint and several liabilities for the removal or remediation of previously released materials or property contamination.  Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. Please read “Item 1 —Business—Governmental Regulations and Environmental Laws” above.

*** ***

***We are subject to complex governmental laws and regulations which may expose us to significant costs and liabilities******and******adversely affect the cost,******manner or feasibility of conducting******our business.***

 

Our petroleum and natural gas exploration and production interest and operations are subject to stringent and complex federal, state, provincial and local laws and regulations relating to the operation and maintenance of our facilities, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment and otherwise relating to environmental protection.  Oil and natural gas operations are also subject to federal, state, provincial and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. We may be required to make large expenditures to comply with these regulatory requirements.  Legislation affecting the petroleum and natural gas industry is under constant review for amendment and expansion.  Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the petroleum and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply.  Any increases in the regulatory burden on the petroleum and natural gas industry created by new legislation would increase our cost of doing business and adversely affect our profitability.

 

Failure to comply with these laws and regulations applicable to our interests and operations could result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders enjoining or limiting some or all of our operations, any of which could have a material adverse affect on our financial condition.  Legal requirements are sometimes unclear or subject to reinterpretation and may be frequently changed in response to economic or political conditions.  As a result, it is hard to predict the ultimate cost of compliance with these requirements or their affect on our interests and operations.  In addition, existing laws or regulations, as currently

 

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interpreted or reinterpreted in the future, or future laws or regulations may have a material adverse effect on our financial condition, future cash flows and the results of operations.

 

***Because our reserves and production are concentrated in a small number of properties, production problems or significant changes in reserve estimates related to any property could have a material impact on our business.***

 

Our current reserves and production primarily come from a small number of producing properties in Utah.  If mechanical problems with the wells or production facilities (including salt water disposal, pipelines, compressors and processing plants), depletion, weather or other events adversely affect any particular property, we could experience a significant decline in our production, which could have a material adverse effect on our cash flows, financial condition and results of operations. In addition, if the actual reserves associated with any one of our properties are less than estimated, our overall reserve estimates could be materially and adversely affected.

*** ***

***Our operations may be interrupted by severe weather or drilling restrictions.***

 

Our operations are conducted in the Rocky Mountain region of the United States. The weather in this area can be extreme and can cause interruption in our exploration and production operations. Severe weather can result in damage to our facilities entailing longer operational interruptions and significant capital investment. Additionally, our operations are subject to disruption from winter storms and severe cold, which can limit operations involving fluids and impair access to our facilities.

*** ***

***Shortages of supplies, equipment and personnel may adversely affect our operations.***

 

The natural gas and oil 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 be substantially increased 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. 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 business, financial condition and results of operations could be materially and adversely affected.

 

***Hedging our production may result in losses or prevent us from benefiting to the fullest extent possible from increases in prices for natural gas and oil.***

 

In order to manage our exposure to price volatility in marketing our oil and natural gas, we enter into oil and natural gas price risk management arrangements for a portion of our expected production. Economically hedging the commodity price may limit the prices we actually realize and therefore reduce oil and natural gas revenues in the future. The fair value of our oil and natural gas derivative instruments outstanding as of December 31, 2010 was a current asset of $193,959. See “Item 7A—Quantitative and Qualitative Disclosures about Market Risk” for further discussion. In addition, our commodity price risk management transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

·                  production is less than expected;

 

·                  the counterparty to the contract defaults on its obligations; or

 

·                  there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

 

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In addition, economic hedging may limit the benefit we would otherwise receive from increases in the prices of oil and gas.

*** ***

***If a counterparty to the derivative instruments we use to hedge our business risks defaults or fails to perform, we may be exposed to risks we had sought to mitigate, which could materially adversely effect our financial condition and results of operations.***

 

We use hedges to mitigate our natural gas price risk with counterparties.  If our counterparty fails or refuses to honor its obligations under these derivative instruments, our hedges of the related risk will be ineffective.  This is a more pronounced risk to us in view of the recent stresses suffered by financial institutions. We cannot provide assurance that our counterparty will honor its obligations now or in the future.  A counterparty’s insolvency or inability or unwillingness to make payments required under terms of derivative instruments with us could have a material adverse effect on our financial condition and results of operations.  At the date of filing of this Form 10-K, we had one counterparty to our derivative instruments.

*** ***

***Our natural gas and oil sales and our related hedging activities expose us to potential regulatory risks.***

 

The Federal Trade Commission, the FERC, and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets.  These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets.  With regard to our physical sales of natural gas and oil and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority.** **Our sales may also be subject to certain reporting and other requirements.  Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

 

To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to use of such capacity.  Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.

*** ***

***Our success depends on our key management personnel, the loss of any of whom could disrupt our business.***

 

The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management.  The loss of services of any of our key managers — including Mr. Grant, our President and Chief Executive Officer and Mr. Decker, our Executive Vice President and Chief Operating Officer—could have a material adverse effect on our business, financial condition and results of operations.  We have not obtained “key man” insurance for any of our management.

 

***Our directors are engaged in other businesses which may result in conflicts of interest.***

 

Certain of our directors also serve as directors of other companies or have significant shareholdings in other companies operating in the oil and gas industry. Our Chairman, Charles Crowell, served as our interim Chief Executive Officer through December 31, 2010 and also serves on the Board of Directors of Derek Oil & Gas Corporation. Richard S. Langdon, another one of our directors, is President and Chief Executive Officer of Matris Exploration Company, L.P., a private exploration and production company active in onshore California. Mr. Langdon is also the President and Chief Executive Officer of Sigma Energy Ventures with E&P activities in the Texas Gulf Coast. Mr. Langdon is also a member of the Board of Directors of Constellation Energy Partners LLC (“CEP”), a public limited liability company

 

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focused on the acquisition, development and exploitation of oil and natural gas properties and related midstream assets. CEP’s activities are currently focused in the Black Warrior Basin of Alabama and in the Cherokee Basin in Oklahoma and Kansas. Another of our directors, C. Tony Lotito, currently serves as the Executive Vice President Business Development of Falcon Oil and Gas, Ltd, and serves as a member of the Board of Directors of Petrohunter Energy Corporation. Richard Burgess, another director, serves on the Board of Michigan Oil and Gas Association. We estimate that all of our outside directors spend up to 10% of their time on our business.

 

To the extent that such other companies participate in ventures in which we may participate, or compete for prospects or financial resources with it, these officers and directors will have a conflict of interest in negotiating and concluding terms relating to the extent of such participation. In the event that such a conflict of interest arises at a meeting of the board of directors, a director who has such a conflict must disclose the nature and extent of his interest to the board of directors and abstain from voting for or against the approval of such participation or such terms.

 

In accordance with the laws of the State of Nevada, our directors are required to act honestly and in good faith with a view to our best interests. In determining whether or not we will participate in a particular program and the interest therein to be acquired by it, the directors will primarily consider the degree of risk to which we may be exposed and our financial position at that time.

*** ***

***It may be difficult to enforce judgments predicated on the federal securities laws on some of our board members who are not U.S. residents.***

 

One of our directors resides outside the United States and maintains a substantial portion of his assets outside the United States.  As a result it may be difficult or impossible to effect service of process within the United States upon such persons, to bring suit in the United States against such persons or to enforce, in the U.S. courts, any judgment obtained there against such persons predicated upon any civil liability provisions of the U.S. federal securities laws.

 

Foreign courts may not entertain original actions against our directors or officers predicated solely upon U.S. federal securities laws.  Furthermore, judgments predicated upon any civil liability provisions of the U.S. federal securities laws may not be directly enforceable in foreign countries.

*** ***

***Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.***

 

President Obama’s Proposed Fiscal Year 2011 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective.  The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

 

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***The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.***

 

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHG”) 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 federal Clean Air Act (“CAA”).

 

In response to findings that emissions of GHGs present an endangerment to public heath and the environment, the EPA has adopted regulations under existing provisions of the CAA that would require a reduction in emissions of GHGs from motor vehicles and also may trigger PSD and Title V permit requirements for GHG emissions from certain stationary sources when the motor vehicle standards took effect on January 2, 2011.  The EPA rules have tailored the PSD and Title V permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting.  These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.  The EPA also published a final rule on November 30, 2010 expanding its existing GHG emissions reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage, and distribution activities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011.  In addition, Congress has actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce.

 

Additionally, more than one-third of the states, either individually or as part of regional initiatives, have begun taking actions to control and/or reduce emissions of greenhouse gases, as have a number of local governments. Although most of the regional and state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as coal-fired electric power plants, smaller sources of emissions could become subject to greenhouse gas emission limitations, allowance purchase requirements or other restrictions or costs. 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 and natural gas we produced.  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 assets and operations.

 

***Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.***

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water,

 

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sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions but is not subject to regulation at the federal level. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation was introduced in the recently completed session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, and such legislation could be introduced in the current session of Congress. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has imposed a de facto moratorium on the issuance of permits for high-volume, horizontal hydraulic fracturing until state-administered environmental studies are finalized, a draft of which must be published by June 1, 2011 followed by a 30-day comment period.  Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed and Wyoming has adopted legislation requiring drilling operators conducting hydraulic fracturing activities in that state to publicly disclose the chemicals used in the fracturing process.

 

If new laws or regulations at the federal, state and/or provincial levels that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform hydraulic fracturing. In addition, if hydraulic fracturing is regulated at the federal level, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements and attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay the development of unconventional oil and natural gas resources from shale formations that are not commercial without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition and results of operations.

*** ***

***Current and future economic conditions in the United States and key international markets may materially adversely impact our operating results.***

 

Our operations are affected by local, national and international economic conditions and the condition of the natural gas and oil industry.  The United States and other world economies are slowly recovering from a recession, which began in 2008 and has extended into 2010.  Although growth has resumed, it is modest and certain economic data indicates the United States and worldwide economies may require some time to recover.  There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years.  In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved.   Global economic growth drives demand for energy from all sources, including fossil fuels.  A lower future economic growth rate will result in decreased demand growth for our natural gas production and crude oil, as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

 

Continued market deterioration could also jeopardize the performance of certain counterparty obligations, including those of our insurers, customers and financial institutions.  Although we assess the creditworthiness of our counterparties, prolonged business decline or disruptions as a result of economic slow down or lower commodity prices could lead to changes in a counterparty’s liquidity and increase our exposure to credit risk and bad debts.  In the event any such party fails to perform, our financial results could be adversely affected and we could incur losses and our liquidity could be negatively impacted.

 

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***Lack of access to the credit market could negatively impact our ability to operate our business and to execute our business strategy.***

 

Due to the changes in the global credit market during 2009 and 2010, there has been deterioration in the credit and capital markets and access to financing is limited and uncertain.  If the capital and credit markets continue to experience weakness and the availability of funds remains limited, we may incur increased costs associated with any additional financing we may require for future operations.  Our suppliers may be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations, each of which could adversely affect our operations. Continued lower levels of economic activity and weakness in the credit markets could also adversely affect our ability to implement our strategic objectives.

 

In addition, some financial institutions and insurance companies have reported significant deterioration in their financial condition. Our forward-looking statements assume that our lenders, insurers and other financial institutions will be able to fulfill their obligations under our various credit agreements, insurance policies and contracts.  If any of our significant financial institutions were unable to perform under such agreements, and if we were unable to find suitable replacements at a reasonable cost, our results of operations, liquidity and cash flows could be adversely impacted.

 

**Risks Related to Our Capital Stock**

*** ***

***A substantial number of shares of our common stock will be eligible for future sale upon conversion of the 2015 Notes (or shares of Preferred Stock issuable upon conversion of the 2015 Notes), and the sale of those shares could adversely affect our stock price.***

 

Pursuant to the terms of those certain Exchange Agreements entered into in connection with the issuance of the 2015 Notes (or shares of Preferred Stock issuable upon conversion of the 2015 Notes), we listed an additional 21,433,135 shares of common stock on the NYSE Amex. A substantial number of shares of our common stock are now eligible for public sale upon conversion of the 2015 Notes. If a significant portion of these shares were to be offered for sale at any given time, the public market for our common stock and the value of our common stock owned by our stockholders could be adversely affected.

*** ***

***Our stockholders will experience substantial dilution if the 2015 Notes are converted.***

 

The 2015 Notes are convertible, at the option of the holder, at any time prior to maturity, into shares of common stock or, at the election of such holder, into shares of Preferred Stock, which are convertible into common stock. The initial conversion price for converting the 2015 Notes into Common Stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock (with certain exceptions), is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes.

 

Specifically, the 2015 Notes and Preferred Stock entitle the holders thereof to voluntarily convert such securities at any time into an aggregate principal amount of approximately 75.8 million shares of common stock (assuming 70% of the approximately $65.0 million maximum amount of the 2015 Notes are voluntarily converted), which would represent an aggregate of approximately 30.7% of the total shares of common stock outstanding on June 25, 2010 and immediately prior to the closing of the Exchange Transaction. Additionally, in September 2010, upon receipt of stockholder approval to issue shares in excess of the Exchange Cap, 30% of the 2015 Notes were automatically converted into an aggregate amount of 305,754 shares of Preferred Stock, which were convertible into an aggregate of approximately

 

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51.3 million shares of common stock, which would represent an aggregate of approximately 20.8% of the total shares of common stock outstanding on such date and immediately prior to the closing of the Exchange Transaction. As of December 31, 2010, we have 225,600 shares of Preferred Stock outstanding which are convertible into approximately 37.6 million shares of common stock.

 

Additionally, all of the shares of common stock issued upon conversion of the 2015 Notes and Preferred Stock are immediately eligible for resale in the public markets under Rule 144 of the Securities Act. Any such sales, or the anticipation of the possibility of such sales, could depress the market price of our common stock.

 

Additionally, any issuance shares of common stock upon conversion of the 2015 Notes or Preferred Stock, if any, our existing stockholders will incur significant dilution of their interests.

*** ***

***If we cannot meet the NYSE Amex’s continued listing requirements, the NYSE Amex may delist our common stock, which would have an adverse impact on the liquidity and market price of our common stock.***

 

Our common stock is currently listed on the NYSE Amex, LLC (the “NYSE Amex”). On June 25, 2009, we received a notice from the NYSE Amex LLC (“NYSE Amex”), dated June 25, 2009, informing us that we did not meet certain of the continued listing standards of the NYSE Amex. Specifically, the notice stated that we were not in compliance with Section 1003(a)(i) of the NYSE Amex Company Guide, with stockholders’ equity of less than $2,000,000 and net losses in two of its three most recent fiscal years; and Section 1003(a)(ii) of the NYSE Amex Company Guide, with stockholders’ equity of less than $4,000,000 and net losses in three of its four most recent fiscal years. The notice also stated that in order to maintain its listing, we must submit a plan of compliance to the NYSE Amex by July 27, 2009 that addresses how we intend to regain compliance with Sections 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide by December 27, 2010.

 

We submitted our plan to the NYSE Amex on July 27, 2009, and provided supplemental information on August 25, 2009, advising the NYSE Amex of the actions we have taken, and plan to take, to attempt to bring the Company into compliance with the applicable listing standards by December 27, 2010.

 

By letter dated September 15, 2009, the NYSE Amex notified us that it had accepted our plan and determined that, in accordance with Section 1009 of the NYSE Amex Company Guide, we had made a reasonable demonstration of our ability to regain compliance with Section 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide by December 27, 2010. The NYSE Amex granted us an extension until December 27, 2010 (the “extension period”) to regain compliance with the continued listing standards of the NYSE Amex Company Guide.

 

On November 19, 2010 the NYSE Amex notified us that, on the basis of a review of publically available information, we had resolved our continuing listing deficiencies. The notice also stated that, as is the case for all listed issuers, our continued listing eligibility will be assessed on an ongoing basis.

 

We will be subject to future review by the NYSE Amex and there can be no assurance that we will be able to achieve compliance the continued listing standards. If we are not able to maintain compliance with the continued listing standards in the future, we will be subject to delisting procedures as set forth in the NYSE Amex Company Guide. A delisting of our common stock could negatively impact us by reducing the liquidity and market price of our common stock and the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing.

 

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***Our common stock has experienced, and may continue to experience, price volatility and low trading volume.***

 

The trading price of our common stock has been and may continue to be subject to large fluctuations, which may result in losses to investors.  Our stock price may increase or decrease in response to a number of events and factors, including:

 

·                  the results of our exploratory drilling;

 

·                  trends in our industry and the markets in which we operate;

 

·                  changes in the market price of the commodities we sell;

 

·                  changes in financial estimates and recommendations by securities analysts;

 

·                  acquisitions and financings;

 

·                  quarterly variations in operating results;

 

·                  the operating and stock price performance of other companies that investors may deem comparable to us;

 

·                  an inability to regain compliance with the listing requirements of the NYSE AMEX; and

 

·                  issuances, purchases or sales of blocks of our common stock.

 

This volatility may adversely affect the price of our common stock regardless of our operating performance. See “Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for further discussion.

*** ***

***Shares eligible for future sale may cause the market price for our common stock to drop significantly, even if our business is doing well.***

 

If our existing shareholders sell our common stock in the market, or if there is a perception that significant sales may occur, the market price of our common stock could drop significantly.  In such case, our ability to raise additional capital in the financial markets at a time and price favorable to us might be impaired.  In addition, our board of directors has the authority to issue additional shares of our authorized but unissued common stock without the approval of our shareholders, subject to certain limitations under the rules of the exchange on which our common stock is listed.  Additional issuances of our common stock would dilute the ownership percentage of existing shareholders and may dilute the earnings per share of our common stock.  As of December 31, 2010, we had 121,182,048 shares of common stock issued and outstanding and outstanding options to purchase an additional 12,689,733 shares of common stock.  An additional 197,450 shares of common stock are issuable under our restricted stock plan.

 

Assuming all of our outstanding Preferred Stock, 2011 Notes and 2015 Notes are converted at the applicable conversion prices, the number of shares of our common stock outstanding would increase by approximately 77,681,841 shares to approximately 198,863,889 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).

 

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***We have not previously paid dividends on our common stock and we do not anticipate doing so in the foreseeable future.***

 

We have not in the past paid, and do not anticipate paying in the foreseeable future, cash dividends on our common stock. Our credit agreement and Indenture contain covenants that restrict our ability to pay dividends on our common stock. Additionally, any future decision to pay a dividend and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.

*** ***

***We have anti-takeover provisions in our certificate of incorporation and by-laws that may discourage a change of control.***

 

Our articles of incorporation and bylaws contain several provisions that could delay or make more difficult the acquisition of us through a hostile tender offer, open market purchases, proxy contest, merger or other takeover attempt that a stockholder might consider in his or her best interest, including those attempts that might result in a premium over the market price of our common stock.

 

Under the terms of our articles of incorporation and as permitted under Nevada law, we have elected not to be subject to Nevada’s anti-takeover law.  This law provides that specified persons who, together with affiliates and associates, own, or within three years did own, 15% or more of the outstanding voting stock of a corporation cannot engage in specified business combinations with the corporation for a period of three years after the date on which the person became an interested stockholder.  With the approval of our stockholders, we may amend our articles of incorporation in the future to become subject to the anti-takeover law.  This provision would then have an anti-takeover effect for transactions not approved in advance by our board of directors, including discouraging takeover attempts that a stockholder might consider in his or her best interest or that might result in a premium over the market price for the shares of our common stock.

** **

**ITEM 1 B. UNRESOLVED STAFF COMMENTS**

 

None.

 

**ITEM 2 - PROPERTIES**

 

**Petroleum and Natural Gas Properties**

 

***Riverbend Project***

 

The Riverbend Project comprises approximately 119,932 gross acres in the Uinta Basin of northeastern Utah, of which we hold interests in approximately 84,401 net acres as of December 31, 2010.  Historically, our engineering and geologic focus has been concentrated on four natural gas and condensate charged formations in the Uinta basin: the Wasatch, Mesaverde, Mancos and Blackhawk formations.  A typical well drilled into these formations may encounter multiple distinct natural gas sands, silts and shales located between approximately 6,000 and 15,000 feet in depth that are completed using up to ten staged fracs.

 

We began an up-hole recompletion program early in February 2010. Since then, we have successfully completed the initial stages on one Upper Mancos well and recompleted 22 gross (8.5 net) wells with six gross (2.0 net) wells occurring during the fourth quarter of 2010. As of December 31, 2010, we operated 133 gross producing wells. We currently have an inventory of 19 operated wells with up-hole completion potential and one Upper Mancos well awaiting initial completion activities. We do not have a drilling rig under contract at this time, as was the case for all of 2010.

 

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On****February 25, 2010, we completed the acquisition of two wells and certain oil and gas leases (the “Petro-Canada Assets”) from Petro-Canada Resources (USA) Inc., a Colorado corporation (“Petro-Canada”), for a purchase price of approximately $482,000, subject to customary post-closing terms and conditions for transactions of this size and nature. The sale was made pursuant to a definitive agreement dated February 4, 2010 by and between us and Petro-Canada. The Petro-Canada Assets included one producing well, one shut in well with recompletion potential and 5,582 gross and net acres located in Utah west of our Gate Canyons operating area. We funded this acquisition with cash flow from operating activities.

 

On February 26, 2010, we completed the sale of substantially all of the assets comprising our gathering system and our evaporative facilities, located in Uintah County, Utah the (“Gathering Assets”), to Monarch Natural Gas, LLC (“Monarch”). At the closing, we received total cash consideration of approximately $23 million from Monarch, the entirety of which was used to repay amounts outstanding under our revolving credit facility.

 

In connection with the sale of Gathering Assets, we entered into (i) a transition services agreement with Monarch pursuant to which we provided certain services relating to the operation of the Gathering Assets to Monarch for a six-month term commencing at closing (this agreement was terminated in August 2010); (ii) a gas gathering agreement with Monarch pursuant to which we dedicated the natural gas production from all of our Utah acreage and Monarch will provide gathering, compression and processing services utilizing the Gathering Assets to us; and (iii) a salt water disposal services agreement with Monarch pursuant to which we may deliver salt water produced by our operations to the evaporative facilities that Monarch acquired as part of the Gathering Assets for a minimum 15-year period.

 

On March 19, 2010, we closed the sale of a partial working interest in 32 wells for $1.25 million. The 32 wells were part of a joint venture project that was started in 2002 under which each of the participants received a net profits interest in these wells for a period of twelve years from initial production date. We agreed to sell our interest in these wells related to the period subsequent to the initial twelve year period to one of the joint venture participants and to convert the purchaser’s net profits interest into a working interest.

 

In late March, we turned on one of the wells (Gasco operated — 100% working interest) that we acquired as part of the Petro-Canada acquisition discussed above, after installing production equipment and connecting it to sales. The other well acquired in this acquisition was producing when it was purchased; however, our field personnel have optimized the production and have increased the flows rates on this well.

 

During 2010 we reclassified approximately $3,000,000 of unproved acreage costs primarily in Utah into proved property. This reclassification represents the value of the leases that will expire during 2011 before we are able to develop it further and a reduction in the carrying value of our acreage based on an independent acreage appraisal as of December 31, 2010.

*** ***

***Southern California Project***

 

As of December 31, 2010, we had a leasehold interest in approximately 30,823 gross (11,040 net) acres in Kern and San Luis Obispo Counties of Southern California. Below is a description of the various projects in this area:

 

The project in our Northwest McKittrick Prospect is in its final permitting stage and we currently expect a 2011 spud date.  The Northwest McKittrick Prospect****lies below the McKittrick slide block and covers approximately 600 gross acres targeting oil within the Tulare, Olig, McKittrick and Stevens sands.  These

 

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sands are draped over a faulted anticlinal nose as interpreted from well data and surface geology. Our partner must carry us for a 20% working interest in three wells that will test through the Stevens sands to fully earn its 80% working interest.  If no wells are drilled, we retain 100% of the prospect.

 

Our Southwest Cymric Prospect is an oil prospect with two traps; a shallow (approximately 2,000’) hanging wall anticline above the McKittrick fault and a footwall block (approximately 4,000’) below the fault.  The traps are defined by reprocessed 2D seismic reflection lines integrated with well data and subsurface and surface geologic mapping that define the trap closures.  The oil targets are the Tulare Sand, the Etchegoin Formation sand and the Antelope Shale member of the Monterey Formation.  Gasco is currently seeking a partner for this prospect.

 

Our Willow Springs Prospect has three anticlinally-folded fault block traps located below the west dipping McKittrick thrust fault as interpreted from reprocessed 2D seismic reflection lines integrated with well data.  The prospect is targeting oil within the Phacoides sandstone and the First, Second and Third sandstone members of the Point of Rocks Formation.   Our partner is processing recently acquired 3D seismic data over the prospect to better define the drilling locations.  Our partner must carry us for a 20% working interest in up to two wells drilled through the Third Point of Rocks sandstone (approximately 8,500’) to fully earn its 80% working interest.  If no wells are drilled, we retain 100% of the prospect.  The first well is anticipated to be spud before year end 2011.

 

Our partner in our Willow Springs Prospect also recently bought into our Antelope Valley Trend group of nine oil and gas prospects that include both shallow horizons and deeper subthrust objectives.  The objectives within the Antelope Valley Trend consist of four to five sand members within the Temblor interval, including the Carneros. Our partner is currently in the process of planning and obtaining the necessary permits for a 3-D seismic shoot over this trend.  The first well in this area must be spud on or before July 1, 2012 and be drilled through the Mabury Sand reservoir or to a depth of 12,000’, whichever is less. When the first well is drilled, our partner will earn approximately one half of the prospect area and an additional four to five prospects as well, depending on the results of the 3-D seismic.

 

Our partner will then have the option to drill a second well on or before December 31, 2012.  The drilling of the second well will allow our partner to earn the remaining acreage and prospects.  Our partner must carry us for a 20% working interest in each well through the tanks to fully earn its 80% working interest.  Additionally we will receive a full license to the 3-D seismic data for this area.  If no wells are drilled, we retain 100% of the prospect and a license to the 3D seismic data.

 

We continue to pursue opportunities in the western area of the San Joaquin Basin.  We have identified additional leads and prospects within the overall trend of prospects defined by the Antelope Valley, Willow Springs, Northwest McKittrick and Southwest Cymric prospects.  We have purchased existing seismic data and are having this data reprocessed to better define these new leads and prospects.  We are also purchasing additional acreage as these prospects become defined.

 

***Nevada Project***

 

As of December 31, 2010 we had a leasehold interest in approximately 130,231 gross (130,041 net) acres containing ten prospects within White Pine and Elko Counties Nevada.  All of the prospects are anticlinal structures identified by mapping the surface geology.  The prospects are targeting oil and gas within the Guilmette and Joanna limestones and the Scotty Wash member of the Chainman Shale.    We are currently seeking a drilling partner for these prospects.

 

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*** ***

***Greater Green River Basin Project***

 

During the second quarter 2010 we sold our remaining acreage in Wyoming along with our interest in two producing wells at an auction for $9,000. The low natural gas prices we were receiving in this area had made it difficult for us to find partners to participate in the drilling of wells in this area, and as a result, we reclassified all unproved leasehold costs associated with this area into proved property during 2007.

 

***Capital Expenditure Budget***

 

The Board of Directors approved an initial capital expenditure budget of $6 million for our 2011 oil and gas activities. We have allocated approximately $2.4 million for our continued up-hole recompletion program targeting natural gas and an additional $1.6 million for the drilling and completion of two Green River Formation oil wells. A significant portion of the remaining $2 million budget may be allocated to additional investment in existing and new California oil and gas prospects in the San Joaquin Basin. Our 2011 capital expenditure program will be funded primarily from cash on hand, cash flow from operations and borrowings under our revolving credit facility. The initial 2011 budget will be subject to market conditions, drilling results, oilfield service availability and commodity process.

 

**Oil and Natural Gas Reserves**

 

Our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure at December 31, 2010 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2010 through December 2010, without giving effect to derivative transactions, and were held constant throughout the life of the properties.  These prices, weighted by production over the lives of the proved reserves were $64.97 for oil and oil equivalents and $3.62 for gas.

 

For more information on our reserves, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation — Production and Reserve Information.”

 

***Company Reserve Estimates***

 

Our proved reserve information as of December 31, 2010 included in this Annual Report on Form 10-K was estimated by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. A copy of NSAI’s summary reserve report is included as Exhibit 99.1 to this Annual Report on Form 10-K. See Note 19 “Supplemental Oil and Gas Reserve Information (Unaudited)” to the accompanying consolidated financial statements for further discussion. In accordance with SEC guidelines, NSAI’s estimates of future net revenues from our properties, and the pre-tax present value of discounted future net cash flows (“PV-10”) and standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period January 2010 through December 2010, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.

 

The tables below set forth information as of December 31, 2010 with respect to our estimated proved reserves, the associated present value of discounted future net cash flows and the standardized measure of discounted future net cash flows. Neither the PV-10 nor the after-tax standardized measure is intended to represent the current market value of the estimated oil and natural gas reserves we own. The average prices weighted by production over the lives of the proved reserves used in the reserve report were $3.62

 

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per Mcf of gas and $64.97 per bbl of oil. All of our proved undeveloped reserves became uneconomic at these prices and as a result were not included in the December 31, 2010 reserve estimates.

 

All of our proved reserves are located within the state of Utah.

 
| ** **                      | ** ** | **Mcf of Gas** | ** ** | **Bbls of Oil** | ** ** | **Total Mcfe** | ** ** |
|---------------------------------|------------|--------------------------|------------|---------------------------|------------|---------------------|------------|
|                            |       |                     |       |                      |       |                |       |
| Total Proved Reserve Quantities |       | 39,726,060               |       | 464,659                   |       | 42,514,014          |       |

 
| ** **                                              | ** ** | **Proved   Undeveloped** | ** ** | **Proved   Developed** | ** ** | **Total**  | ** ** |
|---------------------------------------------------------|------------|--------------------------|------------|------------------------|------------|------------|------------|
|                                                    |       |                     |       |                   |       |       |       |
| Present Value of Discounted Future Net Cash Flows   (a) |       | $                        | 0          |                   | $          | 46,927,000 |       | $ | 46,927,000 |   |
|                                                         |            |                          |            |                        |            |            |            |  |  |  |

 

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(a)          Present value of discounted future net cash flows represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2010 through December 2010, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The average prices weighted by production over the lives of the proved reserves used in the reserve report were of $3.62 per Mcf of gas and $64.97 per bbl of oil. All of our proved undeveloped reserves became uneconomic at these prices and as a result were not included in the December 31, 2010 reserve estimates. These prices should not be interpreted as a prediction of future prices.

 

Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Therefore, the PV-10 amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to our properties.

 

***Non-GAAP Present Value Reconciliation***

 

Management uses discounted future net cash flows, which is calculated without deducting estimated future income tax expenses, and the present value thereof as one measure of the value of the Company’s current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While future net revenue and present value are based on prices, costs and discount factors which are consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. The PV-10 reserve measurement is considered to be a non-GAAP financial measure; however as of December 31, 2010, the PV-10 and the standardized measure of discounted future net cash flows are equal because the effects of estimated future income tax expenses are zero.

 

***Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process***

 

Our proved reserve information as of December 31, 2010 included in this Annual Report was estimated by our independent petroleum engineers, NSAI, in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers and definitions and guidelines established by the SEC.  NSAI was founded in 1961 and

 

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performs consulting petroleum engineering services under the Texas Board of Professional Engineers Registration No. F-002699.

 

Our Executive Vice President and Chief Operating Officer, Operations, Michael K. Decker, is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for the coordination of the third-party reserve reports provided by NSAI. Mr. Decker has over 30 years of experience in the oil and gas industry ranging from exploration, development, operations to mergers and acquisitions.  He holds a BS degree in Geological Engineering from the Colorado School of Mines. Prior to joining us in 2001, Mr. Decker served as the Vice President of Exploitation of Prima Energy Corporation, a NASDAQ traded oil and gas company.

 

Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI report are Mr. Craig Adams and Mr. William Knights.  Mr. Adams is a Registered Professional Engineer in the State of Texas (License No. 68137) and has over 25 years of practical experience in petroleum engineering with over 20 years experience in the estimation and evaluation of oil and gas reserves.  He graduated from Texas Tech University in Texas in 1985 with a Bachelor of Science Degree in Petroleum Engineering and is a member of the International Society of Petroleum Engineers.  Mr. Knights is a Certified Petroleum Geologist and Geophysicist in the State of Texas (License No. 1532) and has over 29 years of practical experience in petroleum geosciences in the estimation and evaluation of reserves.  He graduated from Texas Christian University in 1981 with a Bachelor of Science Degree in Geology and in 1984 with a Master of Science in Geology.  Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

 

The other technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

 

We also maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. In the fourth quarter, our technical team meets regularly with representatives of NSAI to review properties and discuss methods and assumptions used in NSAI’s preparation of the year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the NSAI reserve report is reviewed by our audit committee with representatives of NSAI and internal technical staff. Additionally, our senior management reviews and approves any internally estimated significant changes to our proved reserves on a quarterly basis.

 

***Reserve Technologies***

 

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved

 

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reserves include, but are not limited to, well logs, geologic maps and available down well and production data, seismic data, well test data.

 

***Reserve Sensitivities***

 

The following table discloses information regarding the sensitivity of our estimated total proved oil and gas reserves to price fluctuations.

 
| **Price Case** | ** ** | **Oil   (MBbls)** | ** ** | **Gas   (MMcf)** | ** ** | **Oil and Gas   Equivalent   (Mmcfe)** | ** ** | **PV 10** | ** ** |
|---------------------|------------|-------------------|------------|------------------|------------|--------------------------------------------------|------------|----------------|------------|
| ** **          | ** ** | ** **        | ** ** | ** **       | ** ** | ** **                                       | ** ** | ** **     | ** ** |
| SEC pricing (a)     |       | 464.7             |       | 39,726           |       | 42,514                                           |       | $              | 46,927,000 |   |
| Scenario 1 (b)      |       | 502.1             |       | 41,656           |       | 44,669                                           |       | $              | 57,220,000 |   |
| Scenario 2 (c)      |       | 425.3             |       | 37,488           |       | 40,039                                           |       | $              | 36,893,100 |   |

 

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(a)                                  This case represents pricing under SEC rules under which the prices used are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period January 2010 through December 2010. The oil and gas prices used in this scenario, weighted by production over the lives of the proved reserves are $64.97 per bbl of oil and $3.62 per Mcf of gas.

 

(b)                                 Scenario 1 estimates total proved reserves assuming a 10% price increase in both the oil and the gas price used in the SEC pricing scenario.

 

(c)                                  Scenario 2 estimates total proved reserves assuming a 10% price decrease in both the oil and the gas price used in the SEC pricing scenario.

** **

**Volumes, Prices and Operating Expenses**

 

The following table presents information regarding the production volumes, average sales prices received and average production costs for the periods presented associated with the Company’s sales of natural gas and oil for the periods indicated.

 
| ** **                                  | ** ** | **For the Years Ended December 31,** | ** ** |
|---------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                  | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                        |       |                                                          |       |   |   |   |   |
| Natural gas production (Mcf)                |       | 4,105,139                                                     |       | 4,274,849 |   | 4,583,028 |   |
| Average sales price per Mcf                 |       | $                                                             | 4.15       |   | $ | 3.23 |   | $ | 7.05 |   |
| Oil production (Bbl)                        |       | 40,532                                                        |       | 42,151 |   | 42,545 |   |
| Average sales price per Bbl                 |       | $                                                             | 64.45      |   | $ | 45.47 |   | $ | 77.71 |   |
| Equivalent production of oil and gas (Mcfe) |       | 4,348,331                                                     |       | 4,527,755 |   | 4,838,298 |   |
| Selected Operating Expenses per Mcfe:       |       |                                                          |       |   |   |   |   |
| Lease operating                             |       | $                                                             | 1.18       |   | $ | 0.79 |   | $ | 1.07 |   |
| Production and property taxes               |       | $                                                             | 0.20       |   | $ | 0.17 |   | $ | 0.31 |   |
| General and administrative                  |       | $                                                             | 1.55       |   | $ | 1.80 |   | $ | 1.90 |   |
| Depreciation, depletion and amortization    |       | $                                                             | 0.82       |   | $ | 1.23 |   | $ | 1.96 |   |
| Impairment                                  |       | $                                                             | —     |   | $ | 9.06 |   | $ | 0.72 |   |

 

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**Development, Exploration and Acquisition Capital Expenditures**

 

The following table presents information regarding the Company’s net costs incurred in the purchase of proved and unproved properties and in exploration and development activities:

 
| ** **                  | ** ** | **For the Years Ended December 31,** | ** ** |
|-----------------------------|------------|---------------------------------------------------------------|------------|
| ** **                  | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
|                        |       |                                                          |       |   |   |   |   |
| Property acquisition costs: |       |                                                          |       |   |   |   |   |
| Unproved                    |       | $                                                             | 313,238    |   | $ | 647,721 |   | $ | 624,815 |   |
| Proved                      |       | 481,947                                                       |       | — |   | — |   |
| Exploration costs           |       | 968,683                                                       |       | 1,895,981 |   | 24,607,162 |   |
| Development costs           |       | 5,151,909                                                     |       | 2,486,858 |   | 11,758,219 |   |
| Total                       |       | $                                                             | 6,915,777  |   | $ | 5,030,560 |   | $ | 36,990,196 |   |

 

**Productive Oil and Gas Wells**

 

The following summarizes the Company’s productive and shut-in oil and gas wells as of December 31, 2010.

 
| ** **          | ** ** | **Productive Oil and Gas   Wells** | ** ** |
|---------------------|------------|---------------------------------------------------|------------|
| ** **          | ** ** | **Gross**                                         | ** ** | **Net** | ** ** |
|                |       |                                              |       |   |   |
| Producing oil wells |       | 13                                                |       | 12.8 |   |
| Shut-in oil wells   |       | 2                                                 |       | 2.0 |   |
| Producing gas wells |       | 117                                               |       | 66.5 |   |
| Shut-in gas wells   |       | 1                                                 |       | 1.0 |   |
|                |       | 133                                               |       | 82.3 |   |

 

As of December 31, 2010, we operated 133 gross (79.4 net to our interest) producing wells and 3 gross (3 net) shut-in wells located on these properties.

 

**Oil and Gas Acreage**

 

***Exploration and Productive Acreage***

 

The following table sets forth our ownership interest in undeveloped and developed leasehold acreage, in the areas indicated as of December 31, 2010. The table does not include acreage that we have a contractual right to acquire or to earn through drilling projects, or any other acreage for which we have not yet received leasehold assignments. In certain leases, our ownership is not the same for all depths; therefore, the net acres in these leases are calculated using the greatest ownership interest at any depth. Generally this greater interest represents our ownership in the primary objective formation.

 

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| ** **  | ** ** | **Undeveloped Acres** | ** ** | **Developed Acres** | ** ** |
|-------------|------------|----------------------------|------------|--------------------------|------------|
| ** **  | ** ** | **Gross**                  | ** ** | **Net**                  | ** ** | **Gross** | ** ** | **Net** | ** ** |
|        |       |                       |       |                     |       |   |   |   |   |
| Utah        |       | 114,652                    |       | 80,301                   |       | 5,280 |   | 4,100 |   |
| Nevada      |       | 130,231                    |       | 130,041                  |       | — |   | — |   |
| California  |       | 30,823                     |       | 11,040                   |       | — |   | — |   |
|        |       |                       |       |                     |       |   |   |   |   |
| Total acres |       | 275,706                    |       | 221,382                  |       | 5,280 |   | 4,100 |   |

 

***Undeveloped Acreage***

 

The following table summarizes our ownership interest in the gross and net undeveloped acreage in the areas indicated that will expire in each of the next three years.

 
| ** ** | ** ** | **Expiring in 2011** | ** ** | **Expiring in 2012** | ** ** | **Expiring in 2013** | ** ** |
|------------|------------|--------------------------------|------------|--------------------------------|------------|--------------------------------|------------|
| ** ** | ** ** | **Gross**                      | ** ** | **Net**                        | ** ** | **Gross**                      | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|       |       |                           |       |                           |       |                           |       |   |   |   |   |   |   |
| Utah       |       | 3,179                          |       | 3,131                          |       | 1,117                          |       | 1,117 |   | 800 |   | 800 |   |
| California |       | 642                            |       | 168                            |       | 4,736                          |       | 1,400 |   | 2,647 |   | 533 |   |
| Nevada     |       | —                         |       | —                         |       | —                         |       | — |   | — |   | — |   |
|       |       |                           |       |                           |       |                           |       |   |   |   |   |   |   |
| Total      |       | 3,821                          |       | 3,299                          |       | 5,853                          |       | 2,517 |   | 3,447 |   | 1,333 |   |

 

The Company’s acreage positions are maintained by the payment of delay rentals or by the existence of a producing well on the acreage. As of December 31, 2010, approximately 82% of the gross acreage that we hold is located on federal lands and approximately 17% of the acreage is located on state lands.  It has been our experience that the permitting process related to the development of acreage on federal lands is more time consuming and expensive than the permitting process related to acreage on state lands.  We have generally been able to obtain state permits within 60 days, while obtaining federal permits has taken approximately 24 months or longer.  If we are delayed in procuring sufficient drilling permits for our federal properties, we will shift more of our drilling in Utah to our state leases. While such a shift in resources would not necessarily affect the rate of growth of our cash flow, it would result in a slower growth rate of our total proved reserves, because a higher percentage of the wells drilled on the state leases will be drilled on leases to which proved undeveloped reserves may already have been attributed. Additionally, if the development of our acreage located on federal lands is delayed significantly by the permitting process, we may have to operate at a loss for an extended period of time. Such delays could result in impairments of the carrying value of our unproved properties and could impact the ceiling test calculation. During 2010 we reclassified approximately $3,000,000 of unproved acreage costs primarily in Utah into proved property. This reclassification represents the value of the leases that will expire during 2011 before we are able to develop them further and a reduction in the carrying value of our acreage based on an independent acreage appraisal as of December 31, 2010. After this impairment, the aggregate carrying value of our unproved acreage is approximately $35,941,100 as of December 31, 2010.

 

**Drilling Activity**

 

The following table sets forth our drilling activity during the years ended December 31, 2010, 2009 and 2008. As of December 31, 2010, we had no wells in progress.

 

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| ** **         | ** ** | **For the Years Ended December 31,** | ** ** |
|--------------------|------------|---------------------------------------------------------------|------------|
| ** **         | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
| ** **         | ** ** | **Gross**                                                     | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Exploratory Wells: |       |                                                          |       |   |   |   |   |   |   |   |   |   |   |
| Productive         |       | —                                                        |       | — |   | 2 |   | 0.8 |   | 6 |   | 2.5 |   |
| Dry                |       | —                                                        |       | — |   | — |   | — |   | — |   | — |   |
| Total wells        |       | —                                                        |       | — |   | 2 |   | 0.8 |   | 6 |   | 2.5 |   |
|               |       |                                                          |       |   |   |   |   |   |   |   |   |   |   |
| Development Wells: |       |                                                          |       |   |   |   |   |   |   |   |   |   |   |
| Productive         |       | —                                                        |       | — |   | — |   | — |   | 8 |   | 2.8 |   |
| Dry                |       | —                                                        |       | — |   | — |   | — |   | — |   | — |   |
| Total wells        |       | —                                                        |       | — |   | — |   | — |   | 8 |   | 2.8 |   |

 

**Office Space**

 

We lease approximately 11,843 square feet of office space in Englewood, Colorado, under a lease, which terminates on May 31, 2011. The average rent for this space during the year ended December 31, 2010 was approximately $204,900.  During December 2010, we extended our current lease through May 31, 2012 at an annual rate of approximately $161,700.

 

**ITEM 3 - LEGAL PROCEEDINGS**

 

**EPA Enforcement Action**

 

In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), a wholly-owned subsidiary of the Company, who was preparing air emission calculations for possible future capacity expansions, preliminarily determined that Riverbend may have not accurately calculated the amount of air pollutants that could be emitted from certain existing equipment at its Riverbend Compressor Station in Uintah County, Utah.  Riverbend thereafter undertook a more detailed assessment, which confirmed that Riverbend had not obtained certain air permits nor complied with certain air pollution regulatory programs that were applicable to its operations at the Riverbend Compressor Station.  On June 22, 2007, Riverbend sent a letter to the United States Environmental Protection Agency (“EPA”) Region 8 office in Denver, Colorado, which—because the Riverbend Compressor Station is located in Indian Country—is the agency that has jurisdiction over federal air permitting and air pollution regulatory programs.  Riverbend’s June 22 letter voluntarily disclosed the potential violations to EPA and informed the agency of the steps that Riverbend had taken and planned to take to achieve compliance.  In November 2007, Riverbend met with EPA Region 8 personnel and discussed the disclosed violations, its plans to bring the Riverbend Compressor Station into compliance, and possible resolution of the disclosed violations.   These discussions culminated in the negotiation of a consent decree that was signed by the parties and lodged in the United States District Court of the District of Utah on December 30, 2010.  The consent  resolves the apparent violations, requires Gasco to pay a civil penalty of $350,000, specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that will authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented.  The consent decree is awaiting entry by the court.

 

Under the Purchase Agreement dated January 29, 2010 by which we sold our gathering system and its evaporative facilities located in Uintah County, Utah to Monarch, we retained the obligation to pay any civil penalty assessed and the capital cost of the equipment required to be installed pursuant to the consent decree, and we also agreed to reimburse Monarch for certain miscellaneous expenses incurred to finalize the consent decree and obtain certain changes to the Riverbend Compressor Station’s air permits that are

 

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required by the consent decree.  Monarch is also a party to the consent decree and will be responsible for implementing most of the consent decree requirements at the Riverbend Compressor Station other than the payment of a civil penalty and the installation of capital equipment.  We believe that all necessary pollution control and other equipment required by the consent decree is already installed at the site or accounted for in our capital budget, and that the civil penalty and the other expenses required by the consent decree will not materially affect our financial position or liquidity.

 

**Sweeney Litigation**

 

On December 5, 2008, a lawsuit was filed in state court in Cook County, Illinois (“Sweeney litigation”) by eleven individual plaintiffs and Griffin Asset Management, LLC.  The lawsuit alleges that defendants Richard N. Jeffs (“Jeffs), Marc Bruner (“Bruner”) and the Company through its agency with Bruner, made misrepresentations, committed fraud, aided and abetted a scheme to defraud, and conspired to defraud in connection with the plaintiffs’ investment in Brek Energy Corporation (“Brek”).  The complaint alleged that plaintiffs’ relied on various misrepresentations and omissions by the individual defendants when making the decision to invest in Brek, which merged into the Company in December of 2007.  Plaintiffs sought unspecified damages in an amount in excess of $50,000, punitive damages, attorneys’ fees, and costs.  The Company removed the case to the United States District Court for the Northern District of Illinois, Eastern Division, on January 7, 2009 and answered the complaint, denying all liability, on February 13, 2009. A scheduling conference was held on April 1, 2009.  The judge ordered fact discovery in the case to be completed by December 15, 2009 and set the trial for June 7, 2010.  Following the scheduling conference, Jeffs was served with the complaint and filed a motion to dismiss all counts against him on the grounds that certain claims are barred by limitations, that plaintiffs lack standing to bring other claims, and that plaintiffs have failed to join an indispensable party (Brek).

 

During the fall of 2009, the parties began to engage in the early stages of discovery and numerous depositions were scheduled for late November and the first half of December 2009.  Prior to the start of depositions, however, on November 25, 2009, the parties reached an agreement in principle to settle the claims made against the Company and Bruner in the Sweeney litigation.

 

On December 4, 2009, while counsel for the Company was documenting the partial settlement, counsel for Jeffs sent a letter to the Company demanding that the Company (1) reimburse Jeffs for his defense costs to date in the Sweeney litigation; and (2) indemnify Jeffs for any judgment entered (or settlement made) in the Sweeney litigation.  Jeffs’ counsel claimed that Jeffs was entitled to such reimbursement and indemnification under the bylaws of Brek Energy Corporation that were in effect at the time of Brek’s merger into a wholly-owned subsidiary of the Company.

 

On December 9, 2009, Jeffs also filed an action in Colorado federal district court to obtain a declaration that the 550,000 shares of the Company’s stock being held in escrow under an agreement between the Company and Jeffs belong to, and should be released to, Jeffs pursuant to the terms of the escrow agreement (“Jeffs litigation”).

 

On or around December 18, counsel for the Company, Bruner, Jeffs, and plaintiffs reached an agreement in principle to settle all claims in both the Sweeney litigation and the Jeffs litigation.  This global settlement was documented and finalized in February 2010.

 

On February 5, 2010, counsel for the Company, Bruner, Jeffs, and plaintiffs filed an Agreed Motion for Dismissal with Prejudice of the Sweeney litigation.  On February 9, 2010, the United States District Court for the Northern District of Illinois, Eastern Division entered a docket entry granting the parties’ Agreed Motion and dismissing the Sweeney litigation with prejudice.  On February 10, 2010, a settlement payment was made to the Sweeney plaintiffs in connection with this dismissal with prejudice. On

 

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February 16, 2010, counsel for Gasco and Jeffs filed an Agreed Motion for Dismissal with Prejudice of the**Jeffs litigation.  On February 17, 2010, the United States District Court for the District of Colorado entered an Order of Dismissal with Prejudice.  A settlement payment, which was accrued in the accompanying financial statements as of December 31, 2009, was made on February 17, 2010, following this dismissal with prejudice. The Company received a partial reimbursement from its insurance provider related to this matter during the second quarter of 2010.

 

**ITEM 4 - (REMOVED AND RESERVED)**

 

None.

 

**PART II**

 

**ITEM 5 - MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES**

 

**Market Information**

 

The Company’s common stock is traded on the NYSE Amex under the symbol “GSX.”  As of March 2, 2011, the Company had 167 record shareholders of its common stock. During the last two fiscal years, no cash dividends were declared on Gasco’s common stock. The Company’s management does not anticipate that dividends will be paid on its common stock in the foreseeable future. Furthermore, Gasco’s revolving credit facility contains covenants that restrict the payment of dividends. See further discussion in Note 8, “Credit Facility” of the accompanying financial statements.

 

The following table sets forth, for the periods indicated, the high and low sales prices per share of the Company’s common stock as reported on the NYSE Amex for the periods reflected.

 
| ** **     | ** ** | **High** | ** ** | **Low** | ** ** |
|----------------|------------|----------|------------|---------|------------|
| **2010**       |       |     |       |    |       |
| First Quarter  |       | $        | 0.56       |    | $          | 0.30 |   |
| Second Quarter |       | 0.52     |       | 0.30    |       |
| Third Quarter  |       | 0.42     |       | 0.25    |       |
| Fourth Quarter |       | 0.40     |       | 0.30    |       |
|           |       |     |       |    |       |
| **2009**       |       |     |       |    |       |
| First Quarter  |       | $        | 0.69       |    | $          | 0.18 |   |
| Second Quarter |       | 0.60     |       | 0.21    |       |
| Third Quarter  |       | 0.62     |       | 0.21    |       |
| Fourth Quarter |       | 0.83     |       | 0.40    |       |

 

**Dividends**

 

We have never declared or paid cash dividends on our common stock. Our management anticipates that we will retain future earnings, if any, to satisfy our operational and other cash needs and does not anticipate that dividends will be paid on its common stock in the foreseeable future. Furthermore, our revolving credit facility contains covenants that restrict the payment of dividends. See further discussion in Note 8, “Credit Facility” of the accompanying financial statements.

 

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** **

**Securities Authorized for Issuance under Equity Compensation Plans**

 

See “Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” regarding information about the Company’s equity compensation plans.

 

**Recent Sales of Unregistered Securities; Use of Proceeds from Unregistered Securities**

 

As discussed elsewhere in this Annual Report, during the second quarter of 2010 we completed the exchange of $64,532,000 aggregate principal amount of our 5.5% Convertible Senior Notes due 2011 for $64,532,000 aggregate principal amount of our unsecured 5.5% Convertible Senior Notes due 2015, which are convertible, at the option of the holder, into shares of our common stock or, at the election of the holder,  shares of our newly designated Series C Convertible Preferred Stock, par value $0.001 per share, which are convertible into shares of common stock. The exchange of the 2011 Notes for the 2015 Notes was not registered in reliance on an exemption from registration under Section 4(2) of the Securities Act and Regulation D promulgated thereunder, as such transaction did not involve a public offering of securities.

 

The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock, other than pursuant to an automatic conversion (described below), is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes.  The 2015 Notes (or the Preferred Stock which may be received in certain circumstances upon conversion of, or as may otherwise be issued upon the 2015 Notes) entitle the holders thereof to voluntarily convert such notes (or Preferred Stock, as applicable) into an aggregate principal amount of approximately 75.8 million shares of common stock (assuming 70% of the approximately $65.0 million maximum amount of the 2015 Notes are voluntarily converted).

 

Pursuant to the Indenture, we could not issue shares of common stock to holders of the 2015 Notes (including shares of common stock issuable upon a conversion of the 2015 Notes or upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes or in payment of any change of control purchase price, make whole premium or conversion make whole payment (each as described in the Indenture)) in excess of 19.9% of the number of shares of common stock outstanding immediately prior to the closing of the Exchange Transaction (the “Exchange Cap”), until stockholder approval of the issuance of common stock in excess of the Exchange Cap was obtained. Accordingly, we agreed with those holders that participated in the Exchange Transaction, that, among other things, we would seek to obtain, by September 15, 2010, the approval of our stockholders for the issuance and/or potential issuance of all shares of Common Stock which may be issued pursuant to the conversion of the 2015 Notes (and Series C Preferred Stock issuable thereon) in excess of the Exchange Cap.

 

On September 15, 2010, at our 2010 Annual Meeting of Stockholders, we received stockholder approval for the issuance of all of the shares of common stock issuable upon conversion of our 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes in accordance with applicable law and the rules of the NYSE Amex. Accordingly, on September 20, 2010, we effected the automatic conversion of thirty percent of the then outstanding 2015 Notes, which equaled $19,364,000 aggregate principal amount, into 305,754 shares of Preferred Stock. We also paid an aggregate cash amount of $254,599, equal to all accrued but unpaid interest on the 2015 Notes subject to automatic conversion through September 20, 2010. See Note 4 “Convertible Senior Notes” to the accompanying consolidated financial statements for further discussion.

 

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**ITEM 6 - SELECTED FINANCIAL DATA**

 

The following table sets forth selected financial data, derived from our historical consolidated financial statements and related notes, regarding our financial position and results of operations as the dates indicated. Certain reclassifications have been made to prior financial data to conform to the current presentation. The financial information is an integral part of, and should be read in conjunction with, the consolidated financial statements and notes thereto included in Item 8 hereof. Information concerning significant trends in financial condition and results of operations is contained in “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

 
| ** **                                | ** ** | **For the Years Ended December 31,** | ** ** |
|-------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
| Summary of Operations                     |       |                                                          |       |   |   |   |   |   |   |   |   |
| Gas revenue                               |       | $                                                             | 17,053,924 |   | $ | 13,801,679 |   | $ | 32,328,579 |   | $ | 16,818,623 |   | $ | 19,851,663 |   |
| Oil revenue                               |       | 2,612,233                                                     |       | 1,916,757 |   | 3,306,253 |   | 2,337,129 |   | 1,187,509 |   |
| General & administrative expense |       | 6,743,539                                                     |       | 8,130,151 |   | 9,211,806 |   | 9,021,977 |   | 9,415,787 |   |
| Impairment                                |       | —                                                        |       | 41,000,000 |   | 3,500,000 |   | 97,090,000 |   | 51,000,000 |   |
| Net income (loss)                         |       | 10,127,020                                                    |       | (50,188,171 | ) | 14,513,945 |   | (104,373,921 | ) | (55,817,767 | ) |
| Net income (loss) per share               |       |                                                          |       |   |   |   |   |   |   |   |   |
| Basic                                     |       | 0.08                                                          |       | (0.47 | ) | 0.14 |   | (1.12 | ) | (0.65 | ) |
| Diluted                                   |       | 0.08                                                          |       | (0.47 | ) | 0.13 |   | (1.12 | ) | (0.65 | ) |
|                                           |            |                                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                          | ** ** | **As of December 31,** | ** ** |
|-------------------------------------|------------|---------------------------------------|------------|
| ** **                          | ** ** | **2010**                              | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
| Balance Sheet                       |       |                                  |       |   |   |   |   |   |   |   |   |
| Working capital (deficit)           |       | $                                     | (254,000   | ) | $ | 8,440,548 |   | $ | 10,894,674 |   | $ | (9,330,209 | ) | $ | 11,129,942 |   |
| Cash and cash equivalents           |       | 1,994,542                             |       | 10,577,340 |   | 1,053,216 |   | 1,843,425 |   | 12,876,879 |   |
| Property, plant and equipment, net  |       | 69,704,454                            |       | 67,335,582 |   | 128,712,579 |   | 107,676,102 |   | 115,846,114 |   |
| Total assets                        |       | 80,010,429                            |       | 104,741,713 |   | 153,885,508 |   | 122,511,789 |   | 165,454,418 |   |
| Noncurrent liabilities              |       | 30,018,127                            |       | 101,587,581 |   | 97,196,768 |   | 75,090,876 |   | 65,981,536 |   |
| Stockholders’ equity (deficit) |       | 41,935,252                            |       | (4,193,399 | ) | 44,042,888 |   | 25,247,791 |   | 77,171,921 |   |
|                                     |            |                                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**ITEM 7 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION**

 

The following discussion should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data included elsewhere in this report.

 

**Forward Looking Statements**

 

Please refer to the section entitled “Cautionary Statement Regarding Forward Looking Statements” under Item 1 for a discussion of factors which could affect the outcome of forward looking statements used in this report.

 

**Overview**

 

We are a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon prospects, primarily in the Rocky Mountain region. Our business strategy is to enhance shareholder value by generating and developing high-potential exploitation resources in this area. Our principal business is the acquisition of leasehold interests in petroleum and

 

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natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to those leases. We are currently focusing our drilling efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.

 

**2010 Highlights**

 

***Acquisition of Petro-Canada Assets***

 

On****February 25, 2010, we completed the acquisition of two wells and certain related oil and gas leases (the “Petro-Canada Assets”) from Petro-Canada Resources (USA) Inc., a Colorado corporation (“Petro-Canada”), for a purchase price of approximately $482,000, subject to customary post-closing terms and conditions for transactions of this size and nature. The sale was made pursuant to a definitive agreement dated February 4, 2010 by and between us and Petro-Canada. The Petro-Canada Assets included one producing well, one shut-in well with recompletion potential and 5,582 gross and net acres located in Utah, west of our Gate Canyons operating area. We funded this acquisition with cash flow from operating activities.

 

***Sale of Gathering Assets***

 

On February 26, 2010, we completed the sale of substantially all of the assets comprising our gathering system and our evaporative facilities, located in Uintah County, Utah (“Gathering Assets”), to Monarch Natural Gas, LLC (“Monarch”) pursuant to an Asset Purchase Agreement dated January 29, 2010 (the “Purchase Agreement”). At the closing, we received total cash consideration of approximately $23 million from Monarch, the entirety of which was used to repay amounts outstanding under our revolving credit facility.

 

Pursuant to the Purchase Agreement, simultaneous with the closing, we entered into the following agreements with Monarch: (i) a transition services agreement pursuant to which we provided certain services relating to the operation of the Gathering Assets to Monarch for a six-month term commencing at closing (this agreement was terminated in August 2010); (ii) a gas gathering agreement pursuant to which we dedicated the natural gas production from all of our Utah acreage and Monarch will provide gathering, compression and processing services utilizing the Gathering Assets to us; and (iii) a salt water disposal services agreement pursuant to which we may deliver salt water produced by our operations to the evaporative facilities that Monarch acquired for a minimum 15-year period. The Purchase Agreement was subject to customary post-closing terms and conditions for transactions of this size and nature.

 

***Sale of Partial Working Interest in Producing Wells***

 

On March 19, 2010, we completed the sale of a partial working interest in 32 wells for $1.25 million. The 32 wells were part of a joint venture project that was started in 2002 under which each of the participants received a net profits interest in these wells for a period of twelve years from initial production date. We agreed to sell our interest in these wells related to the period subsequent to the initial twelve year period to one of the joint venture participants and to convert the purchaser’s net profits interest into a working interest.

 

***Prospect Fee***

 

During September 2010, we entered into an arrangement with an exploration and production company which operates in California, pursuant to which we received a $1.5 million prospect fee related to certain of our California acreage. The fee reimburses costs that we have invested in the area and provides us with

 

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a potential carried interest of 20% in two wells to be drilled on the acreage.  Additionally, the farmee is obligated to obtain and provide us a license to 3-D Seismic data over the contract area.

 

***Resignation of Former Chief Executive Officer; Appointment of Replacement***

 

Effective January 1, 2011, our plan of succession for changes in management, which was initially announced in September 2010, was completed.  Charles B. Crowell resigned as our interim Chief Executive Officer and was replaced by W. King Grant, our then President and Chief Financial Officer.  At that time, Mr. Grant resigned as Chief Financial Officer and Peggy Herald, our Vice President and Chief Accounting Officer is now our principal financial officer. Mr. Crowell maintains his position as Chairman of the Board of Directors of the Company; Mr. Grant also serves as a member of the Board of Directors.

 

***The Exchange Transaction***

 

During the second quarter of 2010, we completed the exchange of $64,532,000 aggregate principal amount of our 5.5% Convertible Senior Notes due 2011 (the “2011 Notes”) for $64,532,000 aggregate principal amount of our unsecured 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”),  which are convertible, at the option of the holder, into shares of our common stock or, at the election of the holder,  shares of our newly designated Series C Convertible Preferred Stock, par value $0.001 per share (the “Preferred Stock”), which are convertible into shares of common stock (the “Exchange Transaction”). We also paid to the holders of the 2011 Notes that participated in the Exchange Transaction an aggregate cash amount of $788,724.44, equal to all accrued but unpaid interest with respect to the 2011 Notes as of but not including the date of closing. The 2015 Notes are governed by an indenture (the “Indenture”), dated as of June 25, 2010, by and between us and Wells Fargo Bank, National Association, as trustee.

 

The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock, other than pursuant to an automatic conversion (described below), is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the Indenture, we could not issue shares of common stock to holders of the 2015 Notes (including shares of common stock issuable upon a conversion of the 2015 Notes or upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes or in payment of any change of control purchase price, make whole premium or conversion make whole payment (each as described in the Indenture)) in excess of 19.9% of the number of shares of common stock outstanding immediately prior to the closing of the Exchange Transaction (the “Exchange Cap”), until stockholder approval of the issuance of common stock in excess of the Exchange Cap was obtained.

 

On September 15, 2010, at our 2010 Annual Meeting of Stockholders, we received stockholder approval for the issuance of all of the shares of common stock issuable upon conversion of our 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes in accordance with applicable law and the rules of the NYSE Amex. Accordingly, pursuant to the terms of the Indenture, on September 20, 2010, we effected the automatic conversion of thirty percent of the 2015 Notes, which equaled $19,364,000 aggregate principal amount, into 305,754 shares of Preferred Stock. We also paid an aggregate cash amount of $254,599, equal to all accrued but unpaid interest on the 2015 Notes subject to automatic conversion through September 20, 2010. See Note 4 “Convertible Senior Notes” to the accompanying consolidated financial statements for further discussion.

 

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*** ***

***NYSE Amex Notifications***

 

Our common stock is currently listed on the NYSE Amex, LLC (the “NYSE Amex”). On June 25, 2009, we received a notice from the NYSE Amex LLC (“NYSE Amex”), dated June 25, 2009, informing us that we did not meet certain of the continued listing standards of the NYSE Amex. Specifically, the notice stated that we were not in compliance with Section 1003(a)(i) of the NYSE Amex Company Guide, with stockholders’ equity of less than $2,000,000 and net losses in two of its three most recent fiscal years; and Section 1003(a)(ii) of the NYSE Amex Company Guide, with stockholders’ equity of less than $4,000,000 and net losses in three of its four most recent fiscal years. The notice also stated that in order to maintain its listing, we must submit a plan of compliance to the NYSE Amex by July 27, 2009 that addresses how we intend to regain compliance with Sections 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide by December 27, 2010.

 

We submitted our plan to the NYSE Amex on July 27, 2009, and provided supplemental information on August 25, 2009, advising the NYSE Amex of the actions we have taken, and plan to take, to attempt to bring the Company into compliance with the applicable listing standards by December 27, 2010.

 

By letter dated September 15, 2009, the NYSE Amex notified us that it had accepted our plan and determined that, in accordance with Section 1009 of the NYSE Amex Company Guide, we had made a reasonable demonstration of our ability to regain compliance with Section 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide by December 27, 2010. The NYSE Amex granted us an extension until December 27, 2010 (the “extension period”) to regain compliance with the continued listing standards of the NYSE Amex Company Guide.

 

On November 19, 2010 the NYSE Amex notified us that, on the basis of a review of publically available information, we had resolved our continuing listing deficiencies. The notice also stated that, as is the case for all listed issuers, our continued listing eligibility will be assessed on an ongoing basis.

 

***Amendments to Credit Facility***

 

On February 1, 2010, our $250 million revolving credit facility (the “Credit Facility”) was amended to, among other things, incrementally reduce our borrowing base by a fixed amount in connection with certain contemplated asset sales, including the sale of the Gathering Assets described above, and, effective as of April 1, 2010, to automatically reduce to $16 million, regardless of whether any of the contemplated asset sales were consummated. Effective February 26, 2010, in connection with the consummation of the Asset Sale and the application of the proceeds therefrom to pay down outstanding borrowings under our revolving credit facility, we elected to reduce the borrowing base to $16 million effective immediately.

 

On June 22, 2010, in connection with the Exchange Transaction, our Credit Facility was amended to, among other things, permit (i) our incurrence of indebtedness under the 2015 Notes, (ii) our subsidiaries’ guarantee of the 2015 Notes; (iii) our incurrence of indebtedness and related liens relating to certain insurance policies; (iv) the interest payments and equity payments (of common stock and Preferred Stock) required under the 2015 Notes; and (v) and the exchange of the 2011 Notes for the 2015 Notes and other transactions and requirements contemplated by the Exchange Transaction further described in Note 4 “Convertible Senior Notes” to the accompanying consolidated financial statements.

 

On November 3, 2010, in connection with the November 2010 borrowing base redetermination of our Credit Facility, our Credit Facility was amended, among other things, to acknowledge and reaffirm that our borrowing base is $16,000,000, which will remain in effect until the earlier of (i) the next redetermination of the borrowing base, which is currently scheduled for May 2011 and (ii) the date such

 

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borrowing base is otherwise reduced pursuant to the terms of the Credit Agreement and to extend the termination of the credit facility by one year to March 26, 2012.

 

**Completion Operations**

 

We began our up-hole recompletion program in early February 2010. Since then, we have successfully completed the initial stages on one Upper Mancos well and recompleted 22 gross  wells (8.5 net) with six gross wells (2.0 net) occurring in the fourth quarter 2010.

 

In late March, we turned on one of the wells (Gasco operated — 100% working interest) that we acquired as part of the Petro-Canada acquisition discussed above, after installing production equipment and connecting it to sales. The other well acquired in this acquisition was producing when it was purchased; however, our field personnel have optimized the production and have increased the flows rates on this well.

 

Oilfield services and pressure pumping remain widely available to us and at competitive prices.  Current per-stage fracture stimulation costs are now averaging $30,000, as compared to $95,000 two years ago, a 67% decrease.  The average recompletion includes six stages. Current recompletions are consistently yielding higher production rates for the Upper Blackhawk and Mesaverde pay horizons.  The first eight Upper Blackhawk/Mesaverde recompletions in 2010 are realizing a greater than 25% increase in their production over eight similar recompletions in 2008 when compared to each well’s first eight-week production period.  Consequently, the decreased stimulation costs when combined with the increased production are contributing to much better per-well economics.

 

As of December 31, 2010, we operated 133 gross wells, and we currently have an inventory of 19 operated wells with up-hole recompletions and one Upper Mancos well awaiting initial completion activities. We do not have a drilling rig under contract at this time, as was the case for all of 2010.

 

**California Projects**

 

The operator of the project in the Northwest McKittrick Prospect continues to work with the California State Agencies to acquire the appropriate permits. The Northwest McKittrick Prospect****lies below the McKittrick slide block and covers approximately 600 gross acres targeting oil within the Tulare, Olig, McKittrick and Stevens sands.  These sands are draped over a faulted anticlinal nose as interpreted from well data and surface geology. Our partner must carry us for a 20% working interest in three wells that will test through the Stevens sands to fully earn its 80% working interest.  If no wells are drilled, we retain 100% of the prospect. The operator anticipates commencing drilling operations in the first half of 2011.

 

Our Southwest Cymric Prospect is an oil prospect with two traps; a shallow (approximately 2,000’) hanging wall anticline above the McKittrick fault and a footwall block (approximately 4,000’) below the fault.  The traps are defined by reprocessed 2D seismic reflection lines integrated with well data and subsurface and surface geologic mapping that define the trap closures.  The oil targets are the Tulare Sand, the Etchegoin Formation sand and the Antelope Shale member of the Monterey Formation.  Gasco is currently seeking a partner for this prospect.

 

The operator of the oil prospect in our Willow Springs Prospect recently finished shooting and acquiring the 3-D seismic data for this area.  The operator is processing the 3-D seismic data to better identify the drill locations in the Willow Springs area.  Our Willow Springs Prospect has three anticlinally-folded fault block traps located below the west dipping McKittrick thrust fault.  The prospect is targeting oil within the Phacoides sandstone and the First, Second and Third sandstone members of the Point of Rocks

 

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Formation.   Our partner must carry us for a 20% working interest in up to two wells drilled through the Third Point of Rocks sandstone (approximately 8,500’) to fully earn its 80% working interest.  If no wells are drilled, we retain 100% of the prospect.  The first well is anticipated to be spud before year end 2011.

 

Our partner in our Willow Springs Prospect also recently bought into our Antelope Valley Trend group of nine oil and gas prospects that include both shallow horizons and deeper subthrust objectives.  The objectives within the Antelope Valley Trend consist of four to five sand members within the Temblor interval, including the Carneros. Our partner is currently in the process of shooting 3-D seismic over this series of prospects.  Drilling on this trend is anticipated to occur in 2012 and the first well must be drilled through the Mabury Sand reservoir or to a depth of 12,000’, whichever is less.  When the first well is drilled, our partner will earn approximately one half of the prospect area and four to five prospects as well, depending on the results of the 3-D seismic.  Our partner will then have the option to drill a second well on or before December 31, 2012.  The drilling of the second well will allow our partner to earn the remaining acreage and prospects.  Our partner must carry us for a 20% working interest in each well through the tanks to fully earns its 80% working interest.  Additionally we will receive a full license to the 3-D seismic data for this area.  If no wells are drilled, we retain 100% of the prospect and a license to the 3D seismic data.

 

We continue to pursue opportunities in the western area of the San Joaquin Basin.  We have identified additional leads and prospects within the overall trend of prospects defined by the Antelope Valley, Willow Springs, Northwest McKittrick and Southwest Cymric prospects.  We have purchased existing seismic data are having this data reprocessed to better define these new leads and prospects.  We are also purchasing additional acreage as these prospects become defined.

 

**Wyoming**

 

During the second quarter 2010, we sold our remaining acreage in Wyoming along with our interest in two producing wells at an auction for $9,000. The low natural gas prices we were receiving in this area had made it difficult for us to find partners to participate in the drilling of wells in this area, and as a result, we reclassified all unproved leasehold costs associated with this area into proved property during 2007.

 

**Summary of Capital Expenditures**

 

The following table summarizes our capital expenditures during 2010 by reconciling the cash paid for acquisitions, development and exploration included within the Consolidated Statement of Cash Flows in Item 8.

 

 
| Cash paid for acquisitions, development and exploration |   | $         | 6,981,247 | ** ** |
|---------------------------------------------------------------------------------------|--------|-----------|-----------|------------|
| Cash spent for 2009 property costs that were   accrued at 12/31/09                    |   | (514,000  | )         |
| Capital expenditures for 2010 projects                                                |   | $         | 6,467,247 |       |
|                                                                                  |   |      |      |
| Lease acquisitions and related costs                                                  |   | $         | 313,238   |       |
| Facilities and equipment costs                                                        |   | 249,484   |      |
| Drilling, completion and recompletion activity                                        |   | 5,904,525 |      |
| Capital expenditures for 2010 projects                                                |   | $         | 6,467,247 |       |

 

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**Production and Reserve Information**

 

In December 2008, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and natural gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. The new rules expanded the definition of oil and gas producing activities to include the extraction of saleable hydrocarbons from oil sands, shale, coal beds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. The use of new technologies is now permitted in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Other definitions and terms were revised, including the definition of proved reserves, which was revised to indicate that entities must use the average of beginning-of-the-month commodity prices over the preceding 12-month period, rather than the end-of-period price, when estimating whether reserve quantities are economical to produce. Likewise, the 12-month average price is now used to calculate cost center ceilings for impairment and to compute depreciation, depletion and amortization. Another significant provision of the new rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking.

 

In January 2010, the FASB aligned the current oil and gas reserve estimation and disclosure requirements with those of the SEC.  As of December 31, 2009, we changed our method of determining the quantities of oil and gas reserves which impacted the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties. Under the new rules, we prepared our oil and gas reserve estimates as of December 31, 2010 and 2009 using the average, first-day-of—the- month price during the 12-month periods ending December 31, 2010 and 2009, respectively. In prior years, we used the year-end price; therefore, reserve estimates for the years ended December 31, 2010 and 2009 may not be directly comparable to those presented for prior periods. The following table presents certain of our production information for each of the three years ended December 31, 2010 and our estimated proved reserves as of December 31 of each year presented. The Mcfe calculations assume a conversion of 6 Mcf for each Bbl of oil.

 
| ** **                                   | ** ** | **For the Years Ended December 31,** | ** ** |
|----------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                   | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                         |       |                                                          |       |   |   |   |   |
| Natural gas production (Mcf)                 |       | 4,105,139                                                     |       | 4,274,849 |   | 4,583,028 |   |
| Average sales price per Mcf                  |       | $                                                             | 4.15       |   | $ | 3.23 |   | $ | 7.05 |   |
| Year-end estimated proved gas reserves (Mcf) |       | 39,726,060                                                    |       | 44,229,950 |   | 50,909,308 |   |
|                                         |       |                                                          |       |   |   |   |   |
| Oil production (Bbl)                         |       | 40,532                                                        |       | 42,151 |   | 42,545 |   |
| Average sales price per Bbl                  |       | $                                                             | 64.45      |   | $ | 45.47 |   | $ | 77.71 |   |
| Year-end estimated proved oil reserves (Bbl) |       | 464,659                                                       |       | 450,858 |   | 361,185 |   |
|                                         |       |                                                          |       |   |   |   |   |
| Production (Mcfe)                            |       | 4,348,331                                                     |       | 4,527,755 |   | 4,838,298 |   |
| Year-end estimated proved reserves (Mcfe)    |       | 42,514,014                                                    |       | 46,935,098 |   | 53,076,418 |   |

 

Our oil and gas production decreased by approximately 4% during 2010 as compared with 2009 and 6% during 2009 as compared with 2008 primarily due to normal production declines, partially offset by the completion of new and existing wells during 2009. Our proved reserve quantities decreased by approximately 9% and 13% during the years ended December 31, 2010 and 2009, respectively, primarily due to the production during both years.

 

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The revisions of previous estimates during 2010 were primarily due to better than anticipated well performance related to behind pipe reserves that began producing during 2010.

 

The revisions of previous estimates during 2009 were due primarily to a decrease in the gas price from $4.63 per mcf at December 31, 2008 to $2.85 per mcf at December 31, 2009 which caused some of our wells to become uneconomic. This decrease was partially offset by an increase in the oil prices from $15.34 per barrel at December 31, 2008 to $44.46 per barrel at December 31, 2009.

 

The majority of the revisions of previous estimates during 2008 were primarily the result of a decrease in proved undeveloped reserves as the prices of $15.34 per barrel and $4.63 per Mcf that were used to estimate our 2008 reserves caused all of our proved undeveloped reserves to become uneconomic.

 

**Reserve Quantities**

 
| ** **                            | ** ** | **Gas**     | ** ** | **Oil**    | ** ** |
|---------------------------------------|------------|-------------|------------|------------|------------|
| ** **                            | ** ** | **Mcf**     | ** ** | **Bbls**   | ** ** |
| **Proved Reserves:**                  | ** ** | ** **  | ** ** | ** ** | ** ** |
|                                  |       |        |       |       |       |
| Balance,   December 31, 2007     |       | 104,338,338 |       | 1,070,802  |       |
| Extensions   and discoveries          |       | 2,400,000   |       | 17,000     |       |
| Revisions   of previous estimates (a) |       | (42,740,002 | )          | (646,072   | )          |
| Sales   of reserves in place          |       | (8,506,000  | )          | (38,000    | )          |
| Purchases   of reserves in place      |       | —      |       | —     |       |
| Production                            |       | (4,583,028  | )          | (42,545    | )          |
|                                  |       |        |       |       |       |
| Balance,   December 31, 2008     |       | 50,909,308  |       | 361,185    |       |
| Extensions   and discoveries          |       | 1,384,000   |       | 8,000      |       |
| Revisions   of previous estimates (b) |       | (3,788,509  | )          | 123,824    |       |
| Sales   of reserves in place          |       | —      |       | —     |       |
| Purchases   of reserves in place      |       | —      |       | —     |       |
| Production                            |       | (4,274,849  | )          | (42,151    | )          |
|                                  |       |        |       |       |       |
| Balance,   December 31, 2009     |       | 44,229,950  |       | 450,858    |       |
| Extensions   and discoveries          |       | —      |       | —     |       |
| Revisions   of previous estimates (c) |       | 632,807     |       | 68,912     |       |
| Sales   of reserves in place          |       | (2,213,000  | )          | (19,000    | )          |
| Purchases   of reserves in place      |       | 1,181,442   |       | 4,421      |       |
| Production                            |       | (4,105,139  | )          | (40,532    | )          |
|                                  |       |        |       |       |       |
| Balance,   December 31, 2010     |       | 39,726,060  |       | 464,659    |       |

 
| ** **                        | ** ** | **Gas**    | ** ** | **Oil**    | ** ** |
|-----------------------------------|------------|------------|------------|------------|------------|
| ** **                        | ** ** | **Mcf**    | ** ** | **Bbls**   | ** ** |
| ** **                        | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Proved Developed Reserves**     | ** ** | ** ** | ** ** | ** ** | ** ** |
| Balance,   December 31, 2010 |       | 39,726,060 |       | 464,659    |       |
| Balance,   December 31, 2009 |       | 44,229,950 |       | 450,858    |       |
| Balance,   December 31, 2008 |       | 50,909,308 |       | 361,185    |       |

 

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(a)          The majority of the revisions of previous estimates during 2008 were primarily due to the decrease in oil and gas prices from $73.95 per barrel and $6.53 per Mcf at December 31, 2007 to $15.34 per barrel and $4.63 per Mcf at December 31, 2008.

 

(b)         The majority of the revisions of previous estimates during 2009 were primarily due to a decrease in the gas price used in the reserve report estimates from $4.63 per Mcf at December 31, 2008 to $2.85 per Mcf at December 31, 2009 and an increase in oil prices from $15.34 per barrel at December 31, 2008 to $44.46 per barrel at December 31, 2009.

 

(c)          Better than anticipated existing well performances yielded positive reserve revisions during the year ended December 31, 2010.

 

**Liquidity and Capital Resources**

 

Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities or asset sales, availability under our Credit Facility, and access to capital markets, to the extent available. The capital markets, as they relate to us, have been adversely impacted by the recent financial crisis, the potential lack of liquidity in the banking system and the potential unavailability and cost of credit.  Though recently there has been some improvement in the capital markets, there is no guarantee that such will continue.  In connection with certain asset sales (see Note 3 “Asset Sales and Acquisitions” of the accompanying consolidated financial statements), the borrowing base under our Credit Facility was reduced to $16 million effective February 26, 2010. Additionally, our Credit Facility provides for periodic and special borrowing base redeterminations which could further affect our available borrowing base. Effective November 3, 2011, our borrowing base of $16 million under our Credit Facility was reaffirmed and as of March 2, 2011, we have $6.5 million of outstanding borrowings thereunder. Our borrowing base could be further reduced in the future by our lenders. An inability to access additional borrowings in excess of our $9.4 million of existing capacity under our Credit Facility will limit our ability to increase our operating budget and execute on our growth plans. We continually evaluate our capital needs and compare them to our capital resources and ability to raise funds in the financial markets. We adjust capital expenditures in response to changes in natural gas and oil prices, drilling results and cash flow. If we need additional liquidity for future activities, including paying amounts owed in connection with a borrowing base reduction, if any, we may be required to consider several options for raising additional funds, such as selling securities, selling assets or farm-outs or similar arrangements, but we may be unable to complete any of these transactions on terms acceptable to us or at all.  Any financing obtained through the sale of our equity will likely result in substantial dilution to our stockholders.

 

As of December 31, 2010 we had negative working capital of $254,000, which includes $400,000 related to the 2011 Notes that will be settled in October 2011.

 

With the completion of the Exchange Transaction in the second quarter of 2010, which allowed us to extend the maturity date of most of our 2011 Notes by four years, and the sale of our Gathering Assets, which allowed us to repay $23 million in borrowings under our Credit Facility, we believe we are in a better position to execute our 2011 business plan.

 

***Sources and Uses of Funds***

 

The following table summarizes our sources and uses of cash for each of the three years ended December 31, 2010, 2009 and 2008.

 

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| ** **                                            | ** ** | **For the Years Ended December 31,** | ** ** |
|-------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                            | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                                  |       |                                                          |       |   |   |   |   |
| Net cash provided by operating activities             |       | $                                                             | 3,643,851  |   | $ | 16,247,177 |   | $ | 18,152,640 |   |
| Net cash provided by (used in) investing   activities |       | 18,474,645                                                    |       | (10,268,022 | ) | (41,943,076 | ) |
| Net cash (used in) provided by financing   activities |       | (30,701,294                                                   | )          | 3,544,969 |   | 23,000,227 |   |
| Net cash flow                                         |       | (8,582,798                                                    | )          | 9,524,124 |   | (790,209 | ) |
|                                                       |            |                                                               |            |  |  |  |  |  |  |  |

 

Cash provided by operations decreased by $12,603,326 from December 31, 2009 to December 31, 2010.  The decrease in cash provided by operations was primarily due to the changes in operating assets and liabilities during 2010.  The decrease in cash provided by operations was partially offset by increased oil and gas revenue primarily due to a 28% increase in gas prices and a 42% increase in oil prices, partially offset by the 4% decrease in equivalent oil and gas production during 2010.

 

The decrease in cash provided by operating activities during 2009 as compared with 2008 is primarily due to a 56% decrease in oil and gas revenue resulting from a decrease in oil and gas prices of $3.82 per Mcf and $32.24 per bbl combined with a 6% decrease in production.

 

Our investing activities during three years ended December 31, 2010 related primarily to our development and exploration activities, fixed asset additions and the change in our advances from joint interest owners. The activity during 2010 included the sales proceeds of $24,309,000 associated primarily with the sale of our gathering and evaporative facilities and the sale of a partial working interest in 32 producing wells (see Note 3 “Asset Sales and Acquisitions” of the accompanying consolidated financial statements). In 2009 we had sales proceeds of $539,450 related to the sale of our drilling rig and certain other field equipment and in 2008 we had sales proceeds of $7,500,000 which represented the sale of a non-operated interest in four producing wells.

 

During the three years ended December 31, 2010, 2009 and 2008, our financing activity consisted primarily of borrowings and repayments under our Credit Facility. The 2010 activity included the repurchase of 2011 Notes and the payment of a deposit. The activity in 2008 included $1,161,057 in proceeds from the exercise of options to purchase common stock.

 

***Schedule of Contractual Obligations***

 

The following table summarizes the Company’s obligations and commitments to make future payments under its notes payable, operating leases, employment contracts, consulting agreements and service contracts for the periods specified as of December 31, 2010.

 

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| ** **                                     | ** ** | **Payments due by Period** | ** ** |
|------------------------------------------------|------------|-------------------------------------------|------------|
| **Contractual Obligations**               | ** ** | **Total**                                 | ** ** | **Less than 1   year** | ** ** | **1—3 years** | ** ** | **3—5 years** | ** ** | **More than********5 years** | ** ** |
|                                           |       |                                      |       |   |   |   |   |   |   |   |   |
| Convertible 2015 Notes                         |       |                                      |       |   |   |   |   |   |   |   |   |
| Principal                                      |       | $                                         | 45,168,000 |   | $ | — |   | $ | — |   | $ | 45,168,000 |   | $ | — |   |
| Interest                                       |       | 11,834,643                                |       | 2,484,240 |   | 4,968,480 |   | 4,381,923 |   | — |   |
| Convertible 2011 Notes                         |       |                                      |       |   |   |   |   |   |   |   |   |
| Principal                                      |       | 400,000                                   |       | 400,000 |   | — |   | — |   | — |   |
| Interest                                       |       | 16,806                                    |       | 16,806 |   | — |   | — |   | — |   |
| Credit Facility Principal                      |       | 6,544,969                                 |       | — |   | 6,544,969 |   | — |   | — |   |
| Operating leases                               |       | 172,746                                   |       | 129,287 |   | 43,459 |   | — |   | — |   |
| Employment & consulting contracts (a) |       | 1,385,167                                 |       | 996,000 |   | 389,167 |   | — |   | — |   |
| Asset retirement obligations(b)                |       | 1,119,561                                 |       | — |   | — |   | — |   | 1,119,561 |   |
| Total Contractual Cash Obligations             |       | $                                         | 66,641,892 |   | $ | 4,026,333 |   | $ | 11,946,075 |   | $ | 49,549,923 |   | $ | 1,119,561 |   |

 

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(a)          Effective February 8, 2011, we entered into new employment agreements (“New Agreements”) with our two key officers, which replace in their entirety the employment agreements previously in effect. Total minimum compensation under the New Agreements is $590,000 per annum and the initial terms of the New Agreements will expire on the second anniversary of the effective date and will automatically renew for additional one-year terms unless either party elects not to renew or the New Agreements is otherwise terminated in accordance with its terms. The New Agreements contain clauses regarding termination of the officer that would require payment of an amount ranging from 1.5 to two times annual compensation.

 

(b)         The accuracy and timing of the asset retirement obligations cannot be precisely determined in advance. See further discussion in Note 2 “Significant Accounting Policies — Asset Retirement Obligation” of the accompanying consolidated financial statements.

 

***Forward Sales Contracts***

 

During March 2010, pursuant to that certain Base Contract for Sale and Purchase of Natural Gas that we have with Anadarko Energy Services Company, dated December 1, 2007, we entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of our gross production through 2013 from the Uinta Basin.  The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price. We account for our agreement to physically settle our production as an executory contract.

 

***Capital Budget***

 

Our Board of Directors approved an initial capital expenditure budget of $6 million for our 2011 oil and gas activities. In the Uinta Basin, we allocated approximately $2.4 million for our continued up-hole recompletion program targeting natural gas and an additional $1.6 million for the drilling and completion of two Green River Formation oil wells. A significant portion of the remaining $2 million budget may be allocated to additional investments in existing and new California oil and gas prospects in the San Joaquin Basin. Our budget will be funded primarily from cash on hand, cash flow from operations and borrowings

 

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under our Credit Facility and will be subject to market conditions, drilling results, oilfield service availability and commodity prices.

 

***The Exchange Transaction***

 

During the second quarter of 2010, we completed the exchange of $64,532,000 aggregate principal amount of our 5.5% Convertible Senior Notes due 2011 (the “2011 Notes”) for $64,532,000 aggregate principal amount of our unsecured 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”),  which are convertible, at the option of the holder, into shares of our common stock and/or shares of a newly designated Series C Convertible Preferred Stock, par value $0.001 per share (the “Preferred Stock”), which are convertible into shares of common stock (the “Exchange Transaction”). We also paid to the holders of the 2011 Notes that participated in the Exchange Transaction an aggregate cash amount of $788,724.44, equal to all accrued but unpaid interest with respect to the 2011 Notes as of but not including the date of closing. The 2015 Notes were issued pursuant to the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), provided by Section 4(2) and Regulation D thereunder. The 2015 Notes have a final maturity date of October 5, 2015 and are governed by an indenture (the “Indenture”), dated as of June 25, 2010, by and between us and Wells Fargo Bank, National Association, as trustee (the “Trustee”). The Indenture contains usual and customary covenants limiting the Company’s ability to incur additional indebtedness, with certain exceptions, or liens on its property or assets, restricting its ability to make dividends or other distributions, requiring its domestic subsidiaries to guaranty the 2015 Notes, and requiring it to list the shares of common stock that may be issued upon conversion of the 2015 Notes and the Preferred Stock on the NYSE Amex or any other U.S. national or regional securities exchange on which the common stock is then listed.

 

The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock, other than pursuant to an automatic conversion (described below), is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the Indenture, we could not issue shares of common stock to holders of the 2015 Notes (including shares of common stock issuable upon a conversion of the 2015 Notes or upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes or in payment of any change of control purchase price, make whole premium or conversion make whole payment (each as described in the Indenture)) in excess of 19.9% of the number of shares of common stock outstanding immediately prior to the closing of the Exchange Transaction (the “Exchange Cap”), until stockholder approval of the issuance of common stock in excess of the Exchange Cap was obtained.

 

On September 15, 2010, at our 2010 Annual Meeting of Stockholders, we received stockholder approval for the issuance of all of the shares of common stock issuable upon conversion of our 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes in accordance with applicable law and the rules of the NYSE Amex. Accordingly, pursuant to the terms of the Indenture, on September 20, 2010, we effected the automatic conversion of thirty percent of the 2015 Notes, which equaled $19,364,000 aggregate principal amount, into 305,754 shares of Preferred Stock. We also paid an aggregate cash amount of $254,599, equal to all accrued but unpaid interest on the 2015 Notes subject to automatic conversion through September 20, 2010. See Note 4 “Convertible Senior Notes” to the accompanying consolidated financial statements for further discussion.

 

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***Credit Facility***

 

Our Credit Facility limits our borrowings to the borrowing base less our total outstanding letters of credit issued there under. As of March 2, 2011 we have loans of approximately $6.5 million and letters of credit of approximately $25,000 outstanding under our Credit Facility (see Note 8 “Credit Facility” to the accompanying consolidated financial statements for further discussion).

 

Under the terms of our Credit Facility, our borrowing base is subject to semi-annual redetermination by our lenders thereunder (the “Lenders”) based on their valuation of our proved reserves and their internal criteria.  In addition to such semi-annual determinations, our Lenders may request one additional borrowing base redetermination between each semi-annual calculation.   If our borrowing base is further reduced as a result of a redetermination to a level below our then current outstanding borrowings, we will be required to repay the amount by which such outstanding borrowings exceed the borrowing base within 30 days of notification by the Lenders and we will have less or no access to borrowed capital going forward. If we do not have sufficient funds on hand for repayment, we will be required to seek a waiver or amendment from our Lenders, refinance our Credit Facility or sell assets or additional shares of common stock.  We may not be able to refinance or complete such transactions on terms acceptable to us, or at all.  In the event that we are unable to repay the amount owed within 30 days, we will be in default under the Credit Facility, and as such the Lenders party thereto will have the right to terminate their aggregate commitment under the Credit Facility and declare our outstanding borrowings immediately due and payable in whole. An acceleration of the outstanding indebtedness under the Credit Facility in this manner would additionally constitute an event of default under the indentures governing our 2015 Notes and our 2011 Notes. Should an event of default occur and continue under the indentures governing the 2015 Notes and the 2011 Notes, the 2015 Notes and the 2011 Notes may be declared immediately due and payable at their principal amount together with accrued interest and liquidated damages, if any.

 

Our Credit Facility contains covenants including those that require us to maintain (1) a current ratio (defined as current assets plus unused availability under the credit facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1.0; and (2) a ratio of senior debt to EBITDAX (as such term is defined in the Credit Facility) for the most recent four quarters not to be greater than 3.5:1.0 for each fiscal quarter.  In addition, the Credit Facility contains covenants that restrict our ability to incur other indebtedness, create liens or sell our assets, pay dividends on our common stock and make certain investments. Any failure to be in compliance with any material provision or covenant of our Credit Facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under our Credit Facility.  Additionally, should our obligation to repay indebtedness under our Credit Facility be accelerated, we would be in default under the indentures governing our 2015 Notes and 2011 Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such 2015 Notes and 2011 Notes. As of December 31, 2010, our current and senior debt to EBITDAX ratios are 2.2:1.0 and 0.9:1.0, respectively, and we were in compliance with each of the covenants.

 

***Derivatives***

 

Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of December 31, 2010, natural gas derivative instruments were comprised of three swap agreements for 2011 through December 2011 production. The fair value of the agreements was a current asset of $193,959 as of December 31, 2010 and current liability of $1,932,513 and a noncurrent liability of $761,092 as of December 31, 2009. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our economically hedged

 

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production. See further discussion in “Item 7A —Quantitative and Qualitative Disclosures about Market Risk”.

 

During January 2011, we entered into a costless collar agreement which contains a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we will receive the fixed price and pay the market price. If the market price is between the call and the put strike price; no payments are due from either party. This collar agreement is for 2,000 MMBtu/day with a call price of $5.12/MMBtu and a put price of $4.25/MMBtu for production from January 1, 2012 through December 31, 2012.

 

**Critical Accounting Policies and Estimates**

 

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States requires 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 the 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.

 

***Oil and Gas Properties and Reserves***

 

We follow the full cost method of accounting whereby 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, the ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs exceed this ceiling. Under new oil and gas accounting rules, we prepared our oil and gas reserve estimates as of December 31, 2010 and 2009 using the average, first-day-of—the-month price during the 12-month periods then ending. In prior periods, we used the year-end price and subsequent commodity price increases could be utilized to calculate the ceiling value. As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf. There was no additional impairment recorded for the remainder of 2009 or during 2010. Therefore, impairment expense of $41,000,000 was recorded during the year ended December 31, 2009.

 

Estimated reserve quantities and future net cash flows have the most significant impact on us because these reserve estimates are used in providing a measure of the overall value of our company. Estimated quantities are affected by changes in commodity prices and actual well performance. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of our proved properties.  If our reserve quantities change or if additional costs are reclassified from unproved properties into proved properties, depletion expense could be significantly affected.

 

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Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data.  The extent, quality and reliability of this technical data can vary.  The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.

 

The most accurate method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data.  The accuracy of the decline analysis method generally increases with the length of the production history.  Since most of our wells have been producing less than seven years, their production history is relatively short, so other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir were used in conjunction with the decline analysis method to determine the estimates of our proved reserves including developed producing, developed non-producing and undeveloped.  As our wells are produced over time and more data is available, the estimated proved reserves will be redetermined on an annual basis and may be adjusted based on that data.

 

Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the quantities and present value of our reserves.  For example, a 10% decrease in prices used to estimate our reserve quantities as of December 31, 2010 would result in a decrease in our December 31, 2010 present value of future net cash flows of approximately $10,034,000. In addition, we may adjust estimates of proved reserves to reflect production history, acquisitions, divestitures, ownership interest revisions, results of exploration and development and prevailing gas and oil prices.  Our reserves may also be susceptible to drainage by operators on adjacent properties.

 

***Impairment of Long-lived Assets***

 

The cost of our unproved properties is withheld from the depletion base as described above, until it is determined whether or not proved reserves can be assigned to the properties.  These properties are reviewed periodically for possible impairment. Our management reviews all unproved property each quarter. If a determination is made that acreage will be expiring or that we do not plan to develop some of the acreage that is no longer considered to be prospective, we record an impairment of the acreage and reclassify the costs to the full cost pool. We estimate the value of these acres for the purpose of recording the related impairment. The impairments that we have recorded were estimated by calculating a per acre value from the total unproved costs incurred for the applicable acreage divided by the total net acres owned by us. This per acre estimate is then applied to the acres that we do not plan to develop in order to calculate the impairment.  A change in the estimated value of the acreage could have a material impact on the total impairment recorded by us, calculation of depletion expense and the ceiling test analysis.

 

***Stock-Based Compensation***

 

We account for stock option grants and restricted stock awards by recognizing compensation cost for stock-based awards based on the estimated fair value of the award. Compensation cost is measured at the

 

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grant date based on the fair value of the award and is recognized as an expense over the service period, which generally represents the vesting period. We use the Black-Scholes option valuation model to calculate the fair value of option awards. This model requires us to estimate a risk free interest rate and the volatility of our common stock price. The use of a different estimate for any one of these components could have a material impact on the amount of calculated compensation expense.

 

***Derivatives***

 

We have entered into certain commodity derivative instruments to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. We record all derivative instruments at fair value in the accompanying consolidated balance sheets. Changes in the fair value are to be recognized currently in earnings unless specific hedge accounting criteria are met. We recorded a change in the fair value of commodity derivative instruments of $(2,887,564), $11,549,552 and $(9,199,706) during the years ended December 31, 2010, 2009 and 2008, respectively. In addition, during 2010 we recorded a change in fair value of an embedded derivative associated with the Exchange Transaction of $(6,840,392); see Note 4 “Convertible Senior Notes” to the accompanying consolidated financial statements.

 

As of December 31, 2010, the fair value of the natural gas agreements was a current asset of $193,959. The fair value measurement of the commodity derivative assets and liabilities are measured based upon our valuation model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) notional quantities, (d) current market and contractual prices for the underlying instruments and (e) the counterparty’s credit risk. The unobservable inputs related to the volatility of the oil and gas commodity market are very significant in these calculations. Continued volatility in these markets could have a significant impact on the fair value of our derivative contracts. See Note 9 “Fair Value Measurements” to the accompanying consolidated financial statements for further discussion.

 

**Results of Operations**

 

**2010 Compared to 2009**

 

***Oil and Gas Revenue and Production***

 

The table below sets forth the production volumes, price and revenue by product for the periods presented.

 
| ** **                   | ** ** | **For the Years Ended    December 31,** | ** ** |
|------------------------------|------------|------------------------------------------------------------------|------------|
| ** **                   | ** ** | **2010**                                                         | ** ** | **2009** | ** ** |
|                         |       |                                                             |       |   |   |
| Natural gas production (Mcf) |       | 4,105,139                                                        |       | 4,274,849 |   |
| Average sales price per Mcf  |       | $                                                                | 4.15       |   | $ | 3.23 |   |
| Natural gas revenue          |       | $                                                                | 17,053,924 |   | $ | 13,801,679 |   |
|                         |       |                                                             |       |   |   |
| Oil production (Bbl)         |       | 40,532                                                           |       | 42,151 |   |
| Average sales price per Bbl  |       | $                                                                | 64.45      |   | $ | 45.47 |   |
| Oil revenue                  |       | $                                                                | 2,612,233  |   | $ | 1,916,757 |   |
|                         |       |                                                             |       |   |   |
| Equivalent production (Mcfe) |       | 4,348,331                                                        |       | 4,527,755 |   |
| Total oil and gas revenue    |       | $                                                                | 19,666,157 |   | $ | 15,718,436 |   |

 

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The increase in oil and gas revenue of $3,947,721 during 2010 compared with 2009 is comprised of an increase in the average oil and gas prices of $18.98 per Bbl and $0.92 per Mcf partially offset by a 4% decrease in equivalent oil and gas production The decrease in production is primarily due to normal production declines that were partially offset by the new production from recompletion projects on existing wells. The $3,947,721 increase in oil and gas revenue during 2010 represents an increase of $4,573,499 related to the increase in oil and gas prices partially offset by a decrease of $625,778 related to the equivalent production decrease.

 

***Gathering Revenue and Expenses***

 

Gathering revenue and expense represents the income earned from the third-party working interest owners in the wells we operate (our share of gathering revenue is eliminated against the transportation expense included in our lease operating costs) and the expenses incurred from the Riverbend area gathering assets that we constructed during 2004 and 2005. We sold our gathering assets during February 2010, as described in Note 3 “Asset Sales and Acquisitions — Sale of Gathering Assets” to the accompanying consolidated financial statements, which resulted in a decrease in the gathering revenue of $4,408,262 and a decrease of $2,294,328 in gathering operations expenses during year ended December 31, 2010.

 

***Lease Operating Expenses***

 

The table below sets forth the detail of oil and gas lease operating expenses during the periods presented.

 
| ** **                             | ** ** | **For the Years Ended    December 31,** | ** ** |
|----------------------------------------|------------|------------------------------------------------------------------|------------|
| ** **                             | ** ** | **2010**                                                         | ** ** | **2009** | ** ** |
|                                   |       |                                                             |       |   |   |
| Direct operating expenses and overhead |       | $                                                                | 4,778,914  |   | $ | 3,509,242 |   |
| Workover expense                       |       | 361,170                                                          |       | 65,099 |   |
| Total operating expenses               |       | $                                                                | 5,140,084  |   | $ | 3,574,341 |   |
| Operating expenses per Mcfe            |       | $                                                                | 1.18       |   | $ | 0.79 |   |
|                                   |       |                                                             |       |   |   |
| Production and property taxes          |       | $                                                                | 882,761    |   | $ | 777,665 |   |
| Production and property taxes per Mcfe |       | $                                                                | 0.20       |   | $ | 0.17 |   |
|                                   |       |                                                             |       |   |   |
| Total lease operating expense per Mcfe |       | $                                                                | 1.38       |   | $ | 0.96 |   |

 

Lease operating expense increased $1,670,839 during 2010 compared with 2009. The increase is comprised of a $1,565,743 increase in operating expenses and a $105,096 increase in production and property taxes primarily due to the increase in natural gas and oil revenue during 2010.  The increase in operating expenses is primarily due to a $785,000 increase in water disposal fees as we now have to pay the new owner for these services due to the sale of our evaporative facilities in February 2010; a $300,000 increase in workover expenses; and a $190,000 increase in chemicals due to a greater number of chemical treatment projects during 2010; $170,000 incurred in the purchase and installation of certain valves, gauges and meters in order to comply with environmental regulations and an increase of $125,000 in meter calibration fees that we now have to pay as a result of the sale of our gathering assets during February 2010. Prior to the sale of our evaporative facilities in the first quarter of 2010, the revenue and expenses related to water disposal were eliminated. See further description in Note 3 “Asset Sales and Acquisitions — Sale of Gathering Assets” to the accompanying consolidated financial statements.

 

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***Transportation and Processing***

 

Transportation and processing costs of $3,002,719 ($0.69 per Mcfe) represent the costs we incurred to transport the gas production from our wells subsequent to the sale of our gathering assets as described in Note 3 “Asset Sales and Acquisitions — Sale of Gathering Assets” to the accompanying consolidated financial statements. Prior to the sale of our gathering assets during February 2010, these intercompany costs were eliminated from revenue and expense.

 

***Depletion, Depreciation, Amortization and Accretion***

 

Depletion, depreciation and amortization expense during the years ended December 31, 2010 and 2009 is comprised of depletion expense related to our oil and gas properties, depreciation expense of furniture, fixtures and equipment and accretion expense related to the asset retirement obligation. The decrease of $1,989,423 during 2010 compared to 2009 is primarily due to the sale of our gathering assets and evaporative facilities as described in Note 3 “Asset Sales and Acquisitions — Sale of Gathering Assets” to the accompanying consolidated financial statements.

 

***Impairment***

 

As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf. Therefore, impairment expense of $41,000,000 was recorded during the year ended December 31, 2009. No impairments were recorded during the year ended December 31, 2010.

 

***Contract Termination Fee***

 

During February 2009, we released our drilling rig and paid the rig contractor $4,701,000 for early termination of the drilling contract, as calculated at $12,000 per day from the rig release date through March 15, 2010, the expiration date of the contract.

 

***Loss on Sale of Assets, net***

 

The loss on sale of assets, net during the year ended December 31, 2010 is primarily comprised of a net loss reflecting the decrease in the market value of our inventory. The loss on sale of assets, net during the year ended December 31, 2009 includes a loss of $905,850 on the sale of our drilling rig during June 2009 which was partially offset by a net gain of $110,928 representing the increase in the value of our inventory from when it was originally purchased to when it was transferred to the wells.

 

***General and Administrative Expense***

 

The following table summarizes the components of general and administrative expense and stock-based compensation expense incurred during the periods presented.

 

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| ** **                                                                                    | ** ** | **For the Year Ended    December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** **                                                                                    | ** ** | **2010**                                                        | ** ** | **2009** | ** ** |
|                                                                                          |       |                                                            |       |   |   |
| Total general and administrative costs                                                        |       | $                                                               | 6,936,835  |   | $ | 7,497,289 |   |
| General and administrative costs allocated to   drilling, completion and operating activities |       | (1,558,560                                                      | )          | (1,311,913 | ) |
| General and administrative expense                                                            |       | $                                                               | 5,378,275  |   | $ | 6,185,376 |   |
| General and administrative expenses per Mcfe                                                  |       | $                                                               | 1.24       |   | $ | 1.37 |   |
|                                                                                          |       |                                                            |       |   |   |
| Total stock-based compensation costs                                                          |       | $                                                               | 1,363,894  |   | $ | 1,951,885 |   |
| Stock-based compensation (costs) reduction in   costs capitalized                             |       | 1,370                                                           |       | (7,110 | ) |
| Stock-based compensation                                                                      |       | $                                                               | 1,365,264  |   | $ | 1,944,775 |   |
| Stock-based compensation per Mcfe                                                             |       | $                                                               | 0.31       |   | $ | 0.43 |   |
|                                                                                          |       |                                                            |       |   |   |
| Total general and administrative expense including   stock-based compensation                 |       | $                                                               | 6,743,539  |   | $ | 8,130,151 |   |
|                                                                                          |       |                                                            |       |   |   |
| Total general and administrative expense per Mcfe                                             |       | $                                                               | 1.55       |   | $ | 1.80 |   |

 

General and administrative expense decreased by $1,386,612 ($0.25 per Mcfe) during 2010 as compared with 2009 primarily due to $400,000 in legal reimbursements received from our insurance company in connection with the litigation settlement further described in Note 17 “Legal Proceedings” to the accompanying consolidated financial statements, a $880,000 reduction in consulting fees and a $900,000 reduction in legal fees both of which related to our financial transactions during 2009, a $250,000 in cost allocations to our operational activities in 2010 and a $580,000 decrease in stock-based compensation due to the vesting of certain stock options. This decrease was partially offset by $950,000 in severance payments we agreed to make to our former president and CEO in connection with his resignation during January 2010 and increased compensation expense due to the payment of employee bonuses of approximately $700,000 related to the successful completion of  asset sales and purchases and the Exchange Transaction during 2010 and  as further discussed in Note 3 “Asset Sales and Acquisitions”  and Note 4 “Convertible Senior Notes” to the accompanying consolidated financial statements.

 

***Interest Expense***

 

Interest expense increased $12,066,003 during 2010 as compared with 2009 primarily due to the pro-rata portion of the unamortized discount and debt interest costs of $11,903,000 that were recorded as interest expense upon the conversion of 30% of the original principal amount of the 2015 Notes on September 20, 2010, the additional amortization of the discount on our 2015 Notes which was partially offset by the decreased outstanding debt balance during 2010 resulting from the sale of our gathering assets and evaporative facilities as further discussed in Note 3 “Asset Sales and Acquisitions” to the accompanying consolidated financial statements. Cash paid for interest during the years ended December 31, 2010 and 2009 was $4,095,566 and $5,356,086, respectively.

 

***Derivative Gains (Losses)***

 

Derivative gains (losses) during 2010 and 2009 are comprised of realized and unrealized gains and losses on our commodity derivative instruments and the unrealized gain on our embedded conversion features during the third quarter of 2010. The unrealized derivative gains (losses) represent the changes in the fair

 

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value of our derivative assets and liabilities and the realized derivative gains (losses) represent the net settlements due from or to our counterparty based on each month’s settlement during the quarter.

 

***Gain on Extinguishment of Debt***

 

Gain on extinguishment of debt during 2010 represents the difference between the fair value of the 2015 Notes and the debt conversion derivative as compared to the carrying value of the 2011 Notes less unamortized debt issuance costs that were exchanged in the Exchange Transaction as further described in Note 4 “Convertible Senior Notes” to the accompanying consolidated financial statements. Also included is the gain on the repurchase of $68,000 in principal value of our 2011 Notes including interest for $54,400. The difference between the purchase price and the principal value less unamortized debt issuance costs was recorded as a gain on the extinguishment of debt during the third quarter of 2010.

***Amortization of Deferred Income from Sale of Assets***

 

The amortization of the deferred income from the sale of assets during 2010 represents the amortization of the excess of proceeds received over the carrying value of our gathering assets and evaporative facilities as further described in Note 3 “Asset Sales and Acquisitions” of the accompanying consolidated financial statements.

 

**2009 Compared to 2008**

 

***Oil and Gas Revenue and Production***

 

The following table sets forth the production volumes, average sales prices and revenue by product for the periods indicated.

 
| ** **                   | ** ** | **For the Years Ended December 31,** | ** ** |
|------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                   | ** ** | **2009**                                                      | ** ** | **2008** | ** ** |
|                         |       |                                                          |       |   |   |
| Natural gas production (Mcf) |       | 4,274,849                                                     |       | 4,583,028 |   |
| Average sales price per Mcf  |       | $                                                             | 3.23       |   | $ | 7.05 |   |
| Natural gas revenue          |       | $                                                             | 13,801,679 |   | $ | 32,328,579 |   |
|                         |       |                                                          |       |   |   |
| Oil production (Bbl)         |       | 42,151                                                        |       | 42,545 |   |
| Average sales price per Bbl  |       | $                                                             | 45.47      |   | $ | 77.71 |   |
| Oil revenue                  |       | $                                                             | 1,916,757  |   | $ | 3,306,253 |   |
|                         |       |                                                          |       |   |   |
| Production (Mcfe)            |       | 4,527,755                                                     |       | 4,838,298 |   |
| Total oil and gas revenue    |       | $                                                             | 15,718,436 |   | $ | 35,634,832 |   |

 

Oil and gas revenue decreased $19,916,396 in 2009 compared to 2008 due to (i) a 6% decrease in oil and gas production that was primarily the result of normal production declines in existing wells, partially offset by completion activity during 2009 and (ii) a decrease in the average gas price of $3.82 per Mcf and a decrease in the average oil price of $32.24 per Bbl during 2009. The $19,916,396 decrease in oil and gas revenue during 2009 represents a decrease of $18,901,755 (95%) due to a decrease in oil and gas prices and a decrease of $1,014,641 (5%) due to a decrease oil and gas production.

 

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***Gathering Revenue and Expenses***

 

Gathering income increased by $207,795 during 2009 as compared with 2008 due to less revenue being eliminated as a result of our decreased average working interest in the wells during 2009. The decrease in gathering expense of $787,417 during 2009 is primarily due to decreased operating expenses due to the implementation of cost cutting measures as well as decreased production in 2009.

 

***Rental Income***

 

Rental income during 2008 was comprised of the lease payments received from a third party’s use of our drilling rig.  Rental income was eliminated against the full cost pool when the rig was used to drill our operated wells and rental income was recognized when the rig was used to drill third-party wells.  The rig was used for drilling third party wells during the first four months of 2009 as the rig was released from its last drilling project during April 2009 and was sold during June 2009.

 

***Lease Operating Expenses***

 

The table below sets forth the detail of oil and gas lease operating expenses during the periods presented.

 
| ** **                             | ** ** | **For the Years Ended   December 31,** | ** ** |
|----------------------------------------|------------|------------------------------------------------------------|------------|
| ** **                             | ** ** | **2009**                                                   | ** ** | **2008** | ** ** |
|                                   |       |                                                       |       |   |   |
| Direct operating expenses and overhead |       | $                                                          | 3,509,242  |   | $ | 4,998,412 |   |
| Workover expense                       |       | 65,099                                                     |       | 163,728 |   |
| Total operating expenses               |       | $                                                          | 3,574,341  |   | $ | 5,162,140 |   |
| Operating expenses per Mcfe            |       | $                                                          | 0.79       |   | $ | 1.07 |   |
|                                   |       |                                                       |       |   |   |
| Production and property taxes          |       | $                                                          | 777,665    |   | $ | 1,491,558 |   |
| Production and property taxes per Mcfe |       | $                                                          | 0.17       |   | $ | 0.31 |   |
|                                   |       |                                                       |       |   |   |
| Total lease operating expense per Mcfe |       | $                                                          | 0.96       |   | $ | 1.38 |   |

 

Lease operating expense decreased $2,301,692 during 2009 compared with 2008. The decrease is comprised of a $1,587,799 decrease in operating expenses combined with a $713,893 decrease in production and property taxes primarily due to the decrease in natural gas and oil prices during 2009 and to the use of severance tax exemptions related to certain of our gas wells.  The decrease in operating expenses is primarily due the implementation of cost savings measures such as the elimination of over-time worked by our employees and the elimination of contractor services.

 

***Depletion, Depreciation and Amortization***

 

Depletion, depreciation and amortization expense decreased by $4,324,841 during 2009 compared to 2008 is primarily due to the decrease in the full cost pool resulting from a property impairment of $41,000,000 that was recorded during the first quarter of 2009.

 

***Impairment***

 

As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf. Therefore, an impairment expense of $41,000,000 was recorded for the year ended December 31, 2009.

 

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Impairment expense during 2008 represented a reduction in the fair value of our drilling rig. Based upon an independent appraisal of our drilling rig, we believed that the market value of our drilling rig decreased from its carrying value of $5,500,000 to approximately $2,000,000 as of December 31, 2008. Therefore, we recorded an impairment expense of $3,500,000 to reduce the carrying value of the rig during 2008.

 

***Contract Termination Fee***

 

During February 2009, we released our remaining drilling rig and paid the rig contractor $4,701,000 for early termination of the drilling contract, as calculated at $12,000 per day from the rig release date through March 15, 2010, the expiration date of the contract.

 

***Loss on Sale of Assets, net***

 

Loss on sale of assets, net includes a loss of $905,850 on the sale of our drilling rig during June 2009 for proceeds of $1,000,000 which consisted of a cash payment of $500,000 and an interest bearing promissory note of $500,000 that has a maturity date of June 30, 2012. This loss was partially offset by a net gain of $110,928 representing the increase in the value of our inventory from when it was originally purchased to when it was transferred to the wells.

 

***General and Administrative Expense***

 

The following table summarizes the components of general and administrative expense and stock-based compensation expense incurred during the periods presented.

 
| ** **                                                                                       | ** ** | **For the Years Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                                       | ** ** | **2009**                                                      | ** ** | **2008** | ** ** |
|                                                                                             |       |                                                          |       |   |   |
| Total general and administrative costs                                                           |       | $                                                             | 7,497,289  |   | $ | 7,519,064 |   |
| General and administrative costs attributable to   drilling, completion and operating activities |       | (1,311,913                                                    | )          | (1,410,256 | ) |
| General and administrative expense                                                               |       | $                                                             | 6,185,376  |   | $ | 6,108,808 |   |
| General and administrative expenses per Mcfe                                                     |       | $                                                             | 1.37       |   | $ | 1.26 |   |
|                                                                                             |       |                                                          |       |   |   |
| Total stock-based compensation costs                                                             |       | $                                                             | 1,951,885  |   | $ | 3,134,024 |   |
| Stock-based compensation costs capitalized                                                       |       | (7,110                                                        | )          | (31,026 | ) |
| Stock-based compensation                                                                         |       | $                                                             | 1,944,775  |   | $ | 3,102,998 |   |
| Stock-based compensation per Mcfe                                                                |       | $                                                             | 0.43       |   | $ | 0.64 |   |
|                                                                                             |       |                                                          |       |   |   |
| Total general and administrative expense Including   stock-based compensation                    |       | $                                                             | 8,130,151  |   | $ | 9,211,806 |   |
|                                                                                             |       |                                                          |       |   |   |
| Total general and administrative expense per Mcfe                                                |       | $                                                             | 1.80       |   | $ | 1.90 |   |

 

General and administrative expense decreased by $1,081,655 in 2009 as compared with 2008. The decrease was primarily caused by a $1,158,223 decrease in stock-based compensation expense due to certain stock options and restricted stock becoming fully vested and to the cancellation or forfeiture of options and restricted stock during 2009. This decrease was offset by an increase in general and administrative expenses of $76,568 was primarily due to cost cutting measures that we implemented during the first quarter of 2009 partially offset by increased legal fees due to the settlement of a lawsuit

 

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further described in Note 17 — “Legal Proceedings” of the accompanying consolidated financial statements and increased consulting fees related to the hiring of a financial consultant as required by our lenders.

 

***Interest Expense***

 

Interest expense during 2009 and 2008 consisted primarily of interest expense related to our outstanding Convertible Senior Notes which were issued on October 20, 2004 and borrowings under our existing Credit Facility.  The increase in interest expense of $466,614 was primarily due to increased borrowings and increased interest rates under our existing line of credit during 2009.

 

***Derivative Gains (Losses)***

 

Derivative gains were $1,510,522 and $9,761,826 during the years ended December 31, 2009 and 2008, respectively. These gains were comprised of realized and unrealized gains and losses on our derivative instruments. The unrealized derivative gains (losses) represent the mark-to-market changes in our derivative assets and liabilities and the realized derivative gains (losses) represent the net settlements due from or to our counterparties based on each month’s settlement during the year. The change in these gains and losses during 2009 as compared with 2008 were due to the changes in the gas prices during the same periods.

 

***Interest Income***

 

Interest income increased $6,985 in 2009 compared with 2008 primarily due to a higher average cash and cash equivalent balances during 2009.

 

**Recent Accounting Pronouncements**

 

In January 2010, ASC guidance for fair value measurements and disclosure was updated to require additional disclosures related to transfers in and out of level 1 and 2 fair value measurements and enhanced detail in the level 3 reconciliation. The guidance was amended to clarify the level of disaggregation required for assets and liabilities and the disclosures required for inputs and valuation techniques used to measure the fair value of assets and liabilities that fall in either level 2 or level 3. The updated guidance was effective for our fiscal year beginning January 1, 2010, with the exception of the level 3 disaggregation which is effective for our fiscal year beginning January 1, 2011. The adoption had no impact on our consolidated financial position, results of operations or cash flows. Refer to Note 9 “Fair Value Measurements” of the accompanying consolidated financial statements for further details regarding the Company’s assets and liabilities measured at fair value.

 

**Off Balance Sheet Arrangements**

 

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2010, the off-balance sheet arrangements and transactions that we entered into include undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. We do not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

 

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**ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

***Commodity Price Risk***

 

Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. To mitigate a portion of our exposure to adverse market changes, we have entered into various derivative instruments. As of December 31, 2010, our derivative instruments consist of three swap agreements for our 2011 production. The fair value of these agreements is a current asset of $193,959 as of December 31, 2010. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our hedged production. For our swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

 

The Company’s swap agreements as of December 31, 2010 are summarized in the table below:

 
| **Agreement Type** | ** ** | **Remaining********Term** | ** ** | **Quantity**    | ** ** | **Fixed Price********Counterparty payer** | ** ** | **Floating Price (a)********Gasco payer** |
|-------------------------|------------|---------------------------|------------|-----------------|------------|-----------------------------------------------------|------------|----------------------------------------------------------|
| Swap                    |       | 1/11 — 3/11          |       | 3,000 MMBtu/day |       | $4.825/MMBtu                                        |       | NW Rockies                                               |
| Swap (b)                |       | 1/11 — 3/11          |       | 2,000 MMBtu/day |       | $4.418/MMBtu                                        |       | NW Rockies                                               |
| Swap                    |       | 1/11 — 12/11         |       | 2,000 MMBtu/day |       | $4.000/MMBtu                                        |       | NW Rockies                                               |

 

----

(a)                            Northwest Pipeline Rocky Mountains — Inside FERC first of month index price.

(b)                           Includes information pertaining to a portion of a single natural gas derivative contract with declining volumes. The fixed price represents the weighted average price for the entire period from June 2009 through March 2011.

 

During January 2011, we entered into a costless collar agreement which contains a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we will receive the fixed price and pay the market price. If the market price is between the call and the put strike price; no payments are due from either party. This collar agreement is for 2,000 MMBtu/day with a call price of $5.12/MMBtu and a put price of $4.25/MMBtu for production from January 1, 2012 through December 31, 2012.

 

The swap contracts allow us to predict with greater certainty the effective natural gas prices that we will receive for our hedged production and to benefit from operating cash flows when market prices are less than the fixed prices of the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for the hedged production. Our hedging contracts have no requirements for us to post additional collateral based upon the changes in the market value of our hedge instruments.

 

The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production for the year ended December 31, 2010, our annual revenue would increase or decrease by approximately $40,000 for each $1.00 per barrel change in crude oil prices and $410,000 for each $0.10 per Mcf change in natural gas prices.

 

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***Interest Rate Risk***

 

We do not currently use interest rate derivatives to mitigate our exposure, including under our Credit Facility, to the volatility in interest rates. A 1.0% increase in interest rates on the average borrowings outstanding during the year ended 2010 would increase interest expense by approximately $57,000 per year.

 

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**ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA**

 

**INDEX TO FINANCIAL STATEMENTS**

 
| Report of   Independent Registered Public Accounting Firm                                                                    |   | 80     |
|------------------------------------------------------------------------------------------------------------------------------|--------|--------|
|                                                                                                                         |   |   |
| Consolidated Balance   Sheets at December 31, 2010 and 2009                                                             |   | 81     |
|                                                                                                                         |   |   |
| Consolidated   Statements of Operations for the Years Ended December 31, 2010, 2009 and   2008                          |   | 83     |
|                                                                                                                         |   |   |
| Consolidated   Statements of Stockholders’ Equity (Deficit) for the Years Ended   December 31, 2010, 2009 and 2008 |   | 84     |
|                                                                                                                         |   |   |
| Consolidated   Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and   2008                          |   | 85     |
|                                                                                                                         |   |   |
| Notes to   Consolidated Financial Statements                                                                                 |   | 86     |

 

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**Report of Independent Registered Public Accounting Firm**

 

The Board of Directors and Stockholders

Gasco Energy, Inc.:

 

We have audited the accompanying consolidated balance sheets of Gasco Energy, Inc. and subsidiaries (the Company) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the each of the years in the three-year period ended December 31, 2010.  These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gasco Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010 in conformity with U.S. generally accepted accounting principles.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Gasco Energy Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in *Internal Control — Integrated Framework* issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 2, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

/s/ KPMG LLP

 

 

Denver, Colorado

March 2, 2011

 

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**GASCO ENERGY, INC.**

**CONSOLIDATED BALANCE SHEETS**

 
| ** **                                                              | ** ** | **December 31,** | ** ** |
|-------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                              | ** ** | **2010**              | ** ** | **2009** | ** ** |
| **ASSETS**                                                              |       |                  |       |   |   |
|                                                                    |       |                  |       |   |   |
| **CURRENT ASSETS**                                                      |       |                  |       |   |   |
| Cash and cash equivalents                                               |       | $                     | 1,994,542  |   | $ | 10,577,340 |   |
| Accounts receivable                                                     |       |                  |       |   |   |
| Joint interest billings                                                 |       | 1,296,719             |       | 857,405 |   |
| Revenue                                                                 |       | 2,423,114             |       | 2,979,726 |   |
| Inventory                                                               |       | 1,773,079             |       | 1,019,913 |   |
| Derivative instruments                                                  |       | 193,959               |       | — |   |
| Prepaid expenses                                                        |       | 121,637               |       | 292,421 |   |
| Total                                                                   |       | 7,803,050             |       | 15,726,805 |   |
|                                                                    |       |                  |       |   |   |
| **PROPERTY, PLANT AND EQUIPMENT,**at cost                               |       |                  |       |   |   |
| Oil and gas properties (full cost method)                               |       |                  |       |   |   |
| Proved properties                                                       |       | 263,104,555           |       | 254,682,870 |   |
| Unproved properties                                                     |       | 35,941,100            |       | 38,638,936 |   |
| Facilities and equipment                                                |       | 1,120,134             |       | 971,890 |   |
| Furniture, fixtures and other                                           |       | 240,659               |       | 333,049 |   |
| Total                                                                   |       | 300,406,448           |       | 294,626,745 |   |
| Less accumulated depletion, depreciation,   amortization and impairment |       | (230,701,994          | )          | (227,291,163 | ) |
| Total                                                                   |       | 69,704,454            |       | 67,335,582 |   |
| Assets held for sale, net of accumulated   depreciation                 |       | —                |       | 20,155,544 |   |
| Total                                                                   |       | 69,704,454            |       | 87,491,126 |   |
|                                                                    |       |                  |       |   |   |
| **NON-CURRENT ASSETS**                                                  |       |                  |       |   |   |
| Deposit                                                                 |       | 639,500               |       | 139,500 |   |
| Note receivable                                                         |       | 500,000               |       | 500,000 |   |
| Deferred financing costs                                                |       | 1,363,425             |       | 884,282 |   |
|                                                                    |       | 2,502,925             |       | 1,523,782 |   |
|                                                                    |       |                  |       |   |   |
| **TOTAL ASSETS**                                                        |       | $                     | 80,010,429 |   | $ | 104,741,713 |   |

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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**GASCO ENERGY, INC.**

**CONSOLIDATED****BALANCE SHEETS (continued**)

 
| ** **                                                                                                                                                                                                                                                 | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                                                                                                                                 | ** ** | **2010**              | ** ** | **2009** | ** ** |
|                                                                                                                                                                                                                                                       |       |                  |       |   |   |
| **LIABILITIES AND STOCKHOLDERS’   EQUITY (DEFICIT)**                                                                                                                                                                                                  |       |                  |       |   |   |
|                                                                                                                                                                                                                                                       |       |                  |       |   |   |
| **CURRENT LIABILITIES**                                                                                                                                                                                                                                    |       |                  |       |   |   |
| Accounts payable                                                                                                                                                                                                                                           |       | $                     | 2,111,192  |   | $ | 1,110,259 |   |
| Revenue payable                                                                                                                                                                                                                                            |       | 2,598,693             |       | 2,245,545 |   |
| Advances from joint interest owners                                                                                                                                                                                                                        |       | 1,164,414             |       | — |   |
| 5.5% Convertible Senior Notes due 2011                                                                                                                                                                                                                     |       | 400,000               |       | — |   |
| Derivative instruments                                                                                                                                                                                                                                     |       | —                |       | 1,932,513 |   |
| Accrued interest                                                                                                                                                                                                                                           |       | 591,751               |       | 844,108 |   |
| Accrued expenses                                                                                                                                                                                                                                           |       | 1,191,000             |       | 1,215,106 |   |
| Total                                                                                                                                                                                                                                                      |       | 8,057,050             |       | 7,347,531 |   |
|                                                                                                                                                                                                                                                       |       |                  |       |   |   |
| **NONCURRENT LIABILITIES**                                                                                                                                                                                                                                 |       |                  |       |   |   |
| 5.5% Convertible Senior Notes due 2011                                                                                                                                                                                                                     |       | —                |       | 65,000,000 |   |
| 5.5% Convertible Senior Notes due 2015, net   ofunamortized discount of $25,682,484                                                                                                                                                                        |       | 19,485,516            |       | — |   |
| Long-term debt                                                                                                                                                                                                                                             |       | 6,544,969             |       | 34,544,969 |   |
| Deferred income from sale of assets                                                                                                                                                                                                                        |       | 2,868,081             |       | — |   |
| Derivative instruments                                                                                                                                                                                                                                     |       | —                |       | 761,092 |   |
| Asset retirement obligation related to assets held   for sale                                                                                                                                                                                              |       | —                |       | 206,595 |   |
| Asset retirement obligation                                                                                                                                                                                                                                |       | 1,119,561             |       | 1,054,370 |   |
| Deferred rent expense                                                                                                                                                                                                                                      |       | —                |       | 20,555 |   |
| Total                                                                                                                                                                                                                                                      |       | 30,018,127            |       | 101,587,581 |   |
|                                                                                                                                                                                                                                                       |       |                  |       |   |   |
| **COMMITMENTS AND CONTINGENCIES   (NOTE 14)**                                                                                                                                                                                                              |       |                  |       |   |   |
|                                                                                                                                                                                                                                                       |       |                  |       |   |   |
| **STOCKHOLDERS’ EQUITY (DEFICIT)**                                                                                                                                                                                                                    |       |                  |       |   |   |
| Series B Convertible Preferred stock - $.001   par value; 20,000 sharesauthorized;   zero shares outstanding                                                                                                                                          |       | —                |       | — |   |
| Series C   Convertible Preferred stock - $0.001 par value; 2,000,000 sharesauthorized;   225,600 shares outstanding                                                                                                                                   |       | 226                   |       | — |   |
| Common   stock - $.0001 par value; 300,000,000 shares authorized;121,255,748 shares   issued and 121,182,048 share outstanding as of December 31, 2010;   107,789,597 shares issued and 107,715,897 shares outstanding as of   December 31, 2009 |       | 12,126                |       | 10,779 |   |
| Additional paid-in-capital                                                                                                                                                                                                                                 |       | 257,327,315           |       | 221,327,257 |   |
| Accumulated deficit                                                                                                                                                                                                                                        |       | (215,274,120          | )          | (225,401,140 | ) |
| Less cost of treasury stock of 73,700 common   shares                                                                                                                                                                                                      |       | (130,295              | )          | (130,295 | ) |
| Total                                                                                                                                                                                                                                                      |       | 41,935,252            |       | (4,193,399 | ) |
|                                                                                                                                                                                                                                                       |       |                  |       |   |   |
| **TOTAL LIABILITIES AND   STOCKHOLDERS’ EQUITY (DEFICIT)**                                                                                                                                                                                            |       | $                     | 80,010,429 |   | $ | 104,741,713 |   |

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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**GASCO ENERGY, INC.**

**CONSOLIDATED STATEMENTS OF OPERATIONS**

 
| ** **                                            | ** ** | **For the Years Ended December 31,** | ** ** |
|-------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                            | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                                  |       |                                                          |       |   |   |   |   |
| **REVENUES**                                          |       |                                                          |       |   |   |   |   |
| Gas                                                   |       | $                                                             | 17,053,924 |   | $ | 13,801,679 |   | $ | 32,328,579 |   |
| Oil                                                   |       | 2,612,233                                                     |       | 1,916,757 |   | 3,306,253 |   |
| Gathering                                             |       | 595,942                                                       |       | 5,004,204 |   | 4,796,409 |   |
| Rental income                                         |       | —                                                        |       | 366,399 |   | 1,426,932 |   |
| Total                                                 |       | 20,262,099                                                    |       | 21,089,039 |   | 41,858,173 |   |
|                                                  |       |                                                          |       |   |   |   |   |
| **OPERATING EXPENSES**                                |       |                                                          |       |   |   |   |   |
| Lease operating                                       |       | 6,022,845                                                     |       | 4,352,006 |   | 6,653,698 |   |
| Gathering operations                                  |       | 375,848                                                       |       | 2,670,176 |   | 3,457,593 |   |
| Transportation and processing                         |       | 3,002,719                                                     |       | — |   | — |   |
| Depletion, depreciation and amortization              |       | 3,565,672                                                     |       | 5,555,095 |   | 9,476,944 |   |
| Impairment                                            |       | —                                                        |       | 41,000,000 |   | 3,500,000 |   |
| Contract termination fee                              |       | —                                                        |       | 4,701,000 |   | — |   |
| Loss (gain) on sale of assets, net                    |       | 34,726                                                        |       | 794,922 |   | (318,740 | ) |
| General and administrative                            |       | 6,743,539                                                     |       | 8,130,151 |   | 9,211,806 |   |
| Total                                                 |       | 19,745,349                                                    |       | 67,203,350 |   | 31,981,301 |   |
|                                                  |       |                                                          |       |   |   |   |   |
| **OPERATING INCOME (LOSS)**                           |       | 516,750                                                       |       | (46,114,311 | ) | 9,876,872 |   |
|                                                  |       |                                                          |       |   |   |   |   |
| **OTHER INCOME (EXPENSE)**                            |       |                                                          |       |   |   |   |   |
| Interest expense                                      |       | (17,683,753                                                   | )          | (5,617,750 | ) | (5,151,136 | ) |
| Derivative gains                                      |       | 11,316,191                                                    |       | 1,510,522 |   | 9,761,826 |   |
| Gain on extinguishment   of debt                      |       | 15,772,441                                                    |       | — |   | — |   |
| Amortization of deferred   income from sale of assets |       | 168,710                                                       |       | — |   | — |   |
| Interest income                                       |       | 36,681                                                        |       | 33,368 |   | 26,383 |   |
| Total                                                 |       | 9,610,270                                                     |       | (4,073,860 | ) | 4,637,073 |   |
|                                                  |       |                                                          |       |   |   |   |   |
| **NET INCOME (LOSS)**                                 |       | $                                                             | 10,127,020 |   | $ | (50,188,171 | ) | $ | 14,513,945 |   |
|                                                  |       |                                                          |       |   |   |   |   |
| **NET INCOME (LOSS) PER COMMON   SHARE**              |       |                                                          |       |   |   |   |   |
| **BASIC**                                             |       | $                                                             | 0.08       |   | $ | (0.47 | ) | $ | 0.14 |   |
| **DILUTED**                                           |       | $                                                             | 0.08       |   | $ | (0.47 | ) | $ | 0.13 |   |

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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**GASCO ENERGY, INC.**

**CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)**

 
| ** **                                        | ** ** | ** **               | ** ** | ** **            | ** ** | ** **  | ** **  | ** **      | ** ** | **Additional** | ** ** | ** **   | ** **  | ** ** | ** **   | ** **   | ** ** |
|---------------------------------------------------|------------|--------------------------|------------|-----------------------|------------|-------------|-------------|-----------------|------------|----------------|------------|--------------|-------------|------------|--------------|--------------|------------|
| ** **                                        | ** ** | **Preferred Stock** | ** ** | **Common Stock** | ** ** | **Paid-in** | ** **  | **Accumulated** | ** ** | **Treasury**   | ** ** | ** **   | ** **  |
| ** **                                        | ** ** | **Shares**               | ** ** | **Value**             | ** ** | **Shares**  | ** **  | **Value**       | ** ** | **Capital**    | ** ** | **Deficit**  | ** **  | **Stock**  | ** **   | **Total**    | ** ** |
|                                              |       |                     |       |                  |       |        |        |            |       |           |       |         |        |       |         |         |       |
| **Balance December 31, 2007**                |       | —                   |       | —                |       | 107,290,471 |        | $               | 10,728     |           | $          | 215,094,272  |        | $          | (189,726,914 | )            | $          | (130,295 | ) | $ | 25,247,791 |   |
| Exercise of common stock   options                |       | —                   |       | —                |       | 566,566     |        | 56              |       | 1,161,228      |       | —       |        | —     |         | 1,161,284    |       |
| Cancellation of common   stock                    |       | —                   |       | —                |       | (80,039     | )           | (7              | )          | (14,155        | )          | —       |        | —     |         | (14,162      | )          |
| Stock compensation                                |       | —                   |       | —                |       | 49,000      |        | 5               |       | 3,134,025      |       | —       |        | —     |         | 3,134,030    |       |
| Net income                                        |       | —                   |       | —                |       | —      |        | —          |       | —         |       | 14,513,945   |        | —     |         | 14,513,945   |       |
|                                              |       |                     |       |                  |       |        |        |            |       |           |       |         |        |       |         |         |       |
| **Balance December 31, 2008**                |       | —                   |       | —                |       | 107,825,998 |        | 10,782          |       | 219,375,370    |       | (175,212,969 | )           | (130,295   | )            | 44,042,888   |       |
| Cancellation of common   stock                    |       | —                   |       |                  |       | (43,901     | )           | (4              | )          | 4              |       | —       |        | —     |         | —       |       |
| Stock compensation                                |       | —                   |       |                  |       | 7,500       |        | 1               |       | 1,951,883      |       | —       |        | —     |         | 1,951,884    |       |
| Net loss                                          |       | —                   |       | —                |       | —      |        | —          |       | —         |       | (50,188,171  | )           | —     |         | (50,188,171  | )          |
|                                              |       |                     |       |                  |       |        |        |            |       |           |       |         |        |       |         |         |       |
| **Balance December 31, 2009**                |       | —                   |       | —                |       | 107,789,597 |        | 10,779          |       | 221,327,257    |       | (225,401,140 | )           | (130,295   | )            | (4,193,399   | )          |
| Issuance of preferred   stock                     |       | 305,754                  |       | 306                   |       | —      |        | —          |       | 19,363,694     |       | —       |        | —     |         | 19,364,000   |       |
| Reclassification of debt   derivative             |       | —                   |       | —                |       | —      |        | —          |       | 15,358,616     |       | —       |        | —     |         | 15,358,616   |       |
| Conversion of preferred   stock into common stock |       | (80,154                  | )          | (80                   | )          | 13,359,001  |        | 1,336           |       | (54,080        | )          | —       |        | —     |         | (52,824      | )          |
| Stock compensation                                |       |                     |       |                  |       | 107,150     |        | 11              |       | 1,331,828      |       | —       |        | —     |         | 1,331,839    |       |
| Net income                                        |       | —                   |       | —                |       | —      |        | —          |       | —         |       | 10,127,020   |        | —     |         | 10,127,020   |       |
|                                              |       |                     |       |                  |       |        |        |            |       |           |       |         |        |       |         |         |       |
| **Balance December 31, 2010**                |       | 225,600                  |       | $                     | 226        |        | 121,255,748 |            | $          | 12,126         |       | $            | 257,327,315 |       | $            | (215,274,120 | )          | $ | (130,295 | ) | $ | 41,935,252 |   |
|                                                   |            |                          |            |                       |            |             |             |                 |            |                |            |              |             |            |              |              |            |  |  |  |  |  |  |

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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**GASCO ENERGY, INC.**

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

 
| ** **                                                                               | ** ** | **For the Years Ended December 31,** | ** ** |
|------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                               | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
| **CASH FLOWS FROM OPERATING   ACTIVITIES**                                               |       |                                                          |       |   |   |   |   |
| Net income (loss)                                                                        |       | $                                                             | 10,127,020 |   | $ | (50,188,171 | ) | $ | 14,513,945 |   |
| Adjustment to reconcile   net income (loss) to net cash provided by operating activities |       |                                                          |       |   |   |   |   |
| Depletion, depreciation, amortization, accretion   and impairment expense                |       | 3,565,672                                                     |       | 46,555,095 |   | 12,976,944 |   |
| Stock-based compensation                                                                 |       | 1,365,264                                                     |       | 1,944,775 |   | 3,102,998 |   |
| Gain on extinguishment of debt                                                           |       | (15,772,441                                                   | )          | — |   | — |   |
| Change in fair value of derivative instruments                                           |       | (9,727,956                                                    | )          | 11,549,552 |   | (9,199,706 | ) |
| Amortization of debt discount, deferred expenses   and other                             |       | 13,734,361                                                    |       | 1,377,509 |   | 188,684 |   |
| Changes in operating assets and liabilities:                                             |       |                                                          |       |   |   |   |   |
| Accounts receivable                                                                      |       | 117,298                                                       |       | 5,427,455 |   | 247,547 |   |
| Inventory                                                                                |       | (799,092                                                      | )          | 3,257,440 |   | (2,698,902 | ) |
| Prepaid expenses                                                                         |       | 170,784                                                       |       | (103,611 | ) | 138,220 |   |
| Accounts payable                                                                         |       | 816,919                                                       |       | (1,723,143 | ) | (4,367,208 | ) |
| Revenue payable                                                                          |       | 353,148                                                       |       | (1,595,443 | ) | 2,363,717 |   |
| Accrued interest                                                                         |       | (250,965                                                      | )          | (343,387 | ) | 343,401 |   |
| Accrued expenses                                                                         |       | (56,161                                                       | )          | 89,106 |   | 543,000 |   |
| Net cash provided by operating activities                                                |       | 3,643,851                                                     |       | 16,247,177 |   | 18,152,640 |   |
|                                                                                     |       |                                                          |       |   |   |   |   |
| **CASH FLOWS FROM INVESTING   ACTIVITIES**                                               |       |                                                          |       |   |   |   |   |
| Cash paid for acquisitions, development and   exploration                                |       | (6,981,247                                                    | )          | (10,190,020 | ) | (44,250,250 | ) |
| Cash paid for furniture, fixtures and other                                              |       | (17,522                                                       | )          | (5,230 | ) | (86,814 | ) |
| Increase (decrease) in advances from joint   interest owners                             |       | 1,164,414                                                     |       | (612,222 | ) | (5,106,012 | ) |
| Proceeds from property sales                                                             |       | 24,309,000                                                    |       | 539,450 |   | 7,500,000 |   |
| Net cash provided by (used in) investing   activities                                    |       | 18,474,645                                                    |       | (10,268,022 | ) | (41,943,076 | ) |
|                                                                                     |       |                                                          |       |   |   |   |   |
| **CASH FLOWS FROM FINANCING   ACTIVITIES**                                               |       |                                                          |       |   |   |   |   |
| Borrowings under line of   credit                                                        |       | 1,000,000                                                     |       | 13,000,000 |   | 42,000,000 |   |
| Repayment of borrowings                                                                  |       | (29,000,000                                                   | )          | (9,455,031 | ) | (20,000,000 | ) |
| Cash paid for debt and stock issuance costs                                              |       | (2,146,894                                                    | )          | — |   | (161,057 | ) |
| Repurchase of convertible notes                                                          |       | (54,400                                                       | )          | — |   | — |   |
| Payment of deposit                                                                       |       | (500,000                                                      | )          | — |   | — |   |
| Exercise of options to purchase common stock                                             |       | —                                                        |       | — |   | 1,161,284 |   |
| Net cash (used in) provided by financing   activities                                    |       | (30,701,294                                                   | )          | 3,544,969 |   | 23,000,227 |   |
|                                                                                     |       |                                                          |       |   |   |   |   |
| **NET (DECREASE) INCREASE IN CASH   AND CASH EQUIVALENTS**                               |       | (8,582,798                                                    | )          | 9,524,124 |   | (790,209 | ) |
|                                                                                     |       |                                                          |       |   |   |   |   |
| **CASH AND CASH EQUIVALENTS:**                                                           |       |                                                          |       |   |   |   |   |
|                                                                                     |       |                                                          |       |   |   |   |   |
| **BEGINNING OF PERIOD**                                                                  |       | 10,577,340                                                    |       | 1,053,216 |   | 1,843,425 |   |
|                                                                                     |       |                                                          |       |   |   |   |   |
| **END OF PERIOD**                                                                        |       | $                                                             | 1,994,542  |   | $ | 10,577,340 |   | $ | 1,053,216 |   |

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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**GASCO ENERGY INC.**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008**

 

**NOTE 1 — ORGANIZATION**

 

Gasco Energy, Inc. (“Gasco,” “the Company,” “we,” “our” or “us”) was incorporated under the laws of the State of Nevada on April 21, 1997. Gasco is a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. The Company’s principal business strategy is to enhance stockholder value by generating and developing high-potential exploitation resources in this area. The Company’s principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. The Company is currently focusing its operational efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.

 

**NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES**

 

**Basis of Presentation**

 

The accompanying consolidated financial statements include Gasco and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated.

 

**Cash and Cash Equivalents**

 

All highly liquid investments purchased with an initial maturity of three months or less are considered to be cash equivalents.

 

**Concentration of Credit Risk**

 

The Company’s cash equivalents and derivative instruments are exposed to concentrations of credit risk. The Company manages and controls this risk by placing these funds and contracts with major financial institutions with high credit ratings.

 

The Company’s receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.

 

**Significant Customers**

 

During the three years ended December 31, 2010, 83%, 84% and 68%, respectively, of the Company’s production was sold to Anadarko Petroleum Corporation; during 2010 and 2009, 13% and 12% of the Company’s production was sold to EnWest Marketing LLC and during 2008, 21% was sold to ConocoPhillips Company. Approximately 35% of the accounts receivable — revenue as of December 31, 2010 are due from Anadarko Petroleum Corporation. However, Gasco does not believe that the loss of a single purchaser, including Anadarko Petroleum Corporation, would materially affect the Company’s business because there are numerous other purchasers in the areas in which Gasco sells its production.

 

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**Inventory**

 

Inventory consists of pipe and tubular goods intended to be used in the Company’s oil and gas operations, and is stated at the lower of cost or market using the average cost valuation method.

 

**Oil and Gas Properties**

 

The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, internal costs directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $123,753, $47,617 and $329,627 of internal costs during the years ended December 31, 2010, 2009 and 2008, respectively. Additionally, the Company capitalized stock compensation expense related to our drilling consultants as further described in Note 6 “Stock-Based Compensation” herein. Costs associated with production and general corporate activities are expensed in the period incurred. During April 2010, the Company began charging a marketing fee related to the sale of its natural gas production to the wells in which it is the operator and, therefore, the net income attributable to the outside working interest owners from the marketing activities of $127,639 was recorded as a credit to proved properties during the year ended December 31, 2010. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to a cost center.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

 

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development costs to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties of $35,941,100 as of December 31, 2010, are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. During 2010, we reclassified approximately $3,000,000 of acreage costs primarily in Utah into proved property. This acreage represents the value of leases that will expire during 2011 before we are able to develop them further and a reduction in the carrying value of our leases based upon the appraised value of our acreage as of December 31, 2010. During 2009, we reclassified approximately $1,100,000 and $200,000 of expiring acreage primarily in Utah and California, respectively into proved property. These costs were included in the ceiling test and depletion calculations during the quarter in which the reclassifications were made.

 

Total well costs are transferred to the depletable pool even when multiple targeted zones have not been fully evaluated. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Estimated reserve quantities are affected by changes in commodity prices and actual well performance.

 

Under the full cost method of accounting, the ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the

 

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costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs exceed this ceiling limitation. The present value of estimated future net revenues is computed by applying the average, first-day-of—the-month oil and gas price during the 12-month period ended December 31, 2010 for the 12-month period ended December 31, 2010 to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. As of December 31, 2009, the oil and gas accounting rules were revised. Prior to this date, proved oil and gas reserves were determined using the period-end price and subsequent commodity price increases could be utilized to calculate the ceiling value. See Note 2 “Significant Accounting Policies” — Recently Issued Accounting Pronouncements herein, for description of revised accounting rules.

 

As of March 31, 2009, the Company’s full cost pool exceeded the ceiling limitation, based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf, by $41,000,000. Therefore, impairment expense related to our oil and gas properties of $41,000,000 was recorded during the twelve months ended December 31, 2009. No impairment expense related to our oil and gas properties was recorded during 2010 or 2008.

 

**Capitalized Interest**

 

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. No interest was capitalized during the three years ended December 31, 2010.

 

**Facilities and Equipment**

 

The Company constructed two evaporation pits in the Riverbend area of Utah to be used for the disposal of produced water from the wells that Gasco operates in the area. The pits were depreciated using the straight-line method over their estimated useful life of twenty-five years. The costs of water disposal into the evaporation pits were charged to wells operated by Gasco and therefore, the net income or (expense) attributable to the outside working interest owners from the evaporation pits of $106,433, $(49,449) and $260,846 was recorded as an adjustment to proved properties during the years ended December 31, 2010, 2009 and 2008, respectively. These facilities were sold during February 2010 as described in Note 3 “Asset Sales and Acquisitions” herein.

 

The Company’s other oil and gas equipment is depreciated using the straight-line method over an estimated useful life of five to ten years for the equipment, twenty years for the drilling rig (sold in June 2009) and twenty five years for the facilities (sold in February 2010). The rental of the equipment owned by the Company is charged to the wells that are operated by the Company and, therefore, net income or (expense) attributable to the outside working interest owners from the equipment rental of $(16,109), $(52,444), and $688,174 was recorded as an adjustment to proved properties during 2010, 2009 and 2008, respectively.

 

Through the beginning of June 2009, the Company owned a drilling rig that it leased to an operator for the drilling of wells that it did not operate. During June 2009 the Company sold the drilling rig for proceeds of $1,000,000 which consisted of a cash payment of $500,000 and an interest bearing promissory note of $500,000 with a maturity date of June 30, 2012.  The Company recognized a loss of $905,850 on the sale, which is included in “Loss (gain) on sale of assets, net” in the accompanying consolidated financial statements.

 

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**Assets Held for Sale**

 

During the fourth quarter of 2009, the Company adopted a plan to dispose of and was actively engaged in marketing for sale its gathering assets and water disposal facilities. In February 2010, the Company entered into an asset purchase agreement to sell these assets for total cash consideration of $23,000,000 subject to certain adjustments. These assets were separately presented in the balance sheets as of December 31, 2009 at the lower of carrying value or fair value less the cost to sell and at carrying value. Additionally, the asset retirement obligations related to these assets were also reclassified to liabilities associated with assets held for sale as of December 31, 2009.  See Note 3 “Asset Sales and Acquisitions” herein for further discussion.

 

**Impairment of Long-lived Assets**

 

The Company’s unproved properties are evaluated quarterly for the possibility of potential impairment and are reduced to fair value if the sum of expected undiscounted future cash flows is less than net book value. During the year ended December 31, 2008, the Company recorded impairment expense of $3,500,000 related to the decrease in the value of its drilling rig (sold June 2009) based upon an independent appraisal.

 

**Deferred Financing Costs**

 

Deferred financing costs include the costs associated with the Company’s issuance of 5.5% Convertible Senior Notes due 2011 (the “2011 Notes”) during October 2004, the costs incurred in connection with the exchange of the 2011 Notes for the 5.5% Convertible Senior Notes due 2015 (the “2015 Notes) (see Note 4 - Convertible Senior Notes, herein, and the debt issuance costs incurred in connection with the Company’s credit facility and the additional debt issuance costs associated with the amendment of our credit facility as further described in Note 8 “Credit Facility” herein. The Company recorded amortization expense of $13,888,901, $608,621 and $521,428 related to these costs during the years ended December 31, 2010, 2009 and 2008, respectively.

 

**Forward Sales Contracts**

 

During March 2010, per the Base Contract for Sale and Purchase of Natural Gas that the Company has with Anadarko Energy Services Company, dated December 1, 2007, the Company entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of its gross production through 2013 from the Uinta Basin.  The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price. The Company accounts for their agreement to physically settle its production as an executory contract.

 

**Derivatives**

 

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The Company records all derivative instruments at fair value within the accompanying consolidated balance sheets. Changes in fair value are to be recognized currently in earnings unless specific hedge accounting criteria are met. The Company’s management has decided not to use hedge accounting under the accounting guidance for its commodity derivatives and therefore, the changes in fair value are recognized in earnings. In addition, as discussed in Note 4 “Convertible Senior Notes” herein, the Company accounted for the embedded conversion features related to the outstanding 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”), which were issued in June 2010 in the Exchange Transaction as derivatives until September 15, 2010. Changes in fair value were recorded in earnings.

 

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** **

**Asset Retirement Obligation**

 

The Company accounts for its future asset retirement obligations by recording the fair value of the liability during the period in which it was incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties, gathering assets (sold in February 2010) or evaporative facility costs (sold in February 2010) in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and gathering assets using the units-of-production method and the evaporative facilities were depreciated on a straight-line basis over the life of the assets. The Company’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties and gathering assets. The asset retirement liability is allocated to operating expense using a systematic and rational method. The information below reconciles the value of the asset retirement obligation for the periods presented.

 
| ** **                    | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------|------------|--------------------------------------------|------------|
| ** **                    | ** ** | **2010**                                   | ** ** | **2009** | ** ** |
|                          |       |                                       |       |   |   |
| Balance   beginning of period |       | $                                          | 1,260,965  |   | $ | 1,150,179 |   |
| Liabilities   incurred        |       | 2,100                                      |       | 830 |   |
| Property   dispositions       |       | (242,981                                   | )          | — |   |
| Accretion   expense           |       | 99,477                                     |       | 109,956 |   |
| Balance   end of period (a)   |       | $                                          | 1,119,561  |   | $ | 1,260,965 |   |

 

----

(a)            $206,595 was reclassified on the accompanying consolidated balance sheets as asset retirement obligations related to assets held for sale as of December 31, 2009.

 

**Deferred Income from Sale of Assets**

 

The deferred income from sale of assets represents the excess of proceeds received over the carrying value that was recorded in connection with the sale of the Company’s gathering assets and evaporative facilities in February 2010 as further described in Note 3 “Asset Sales and Acquisitions” herein. This income will be amortized over the fifteen-year terms of the gathering and salt water disposal contracts which were entered into at the time of the sale.

 

**Contract Termination Fee**

 

During February 2009, the Company released its remaining leased drilling rig and paid the rig contractor $4,701,000 for early termination of the drilling contract, as calculated at $12,000 per day from the rig release date through March 15, 2010, the expiration date of the contract. Upon the Company’s payment of this fee, the letter of credit in the amount of $6,564,000 for the benefit of the rig contractor was released by the Company’s lenders.

 

**Off Balance Sheet Arrangements**

 

From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2010, the off-balance sheet arrangements and transactions that the Company had entered into include undrawn letters of credit, operating lease

 

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agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

 

**Revenue Recognition**

 

The Company records revenues from the sales of natural gas and crude oil when delivery to the customer has occurred, title has transferred and collectability is reasonably assured. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred.

 

The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2010 and 2009 were not significant.

 

**Computation of Net Loss per Share**

 

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income per share of common stock includes both the vested and unvested shares of restricted stock. Diluted net income or loss per common share of stock is computed by dividing adjusted net income by the diluted weighted-average common shares outstanding.  Potentially dilutive securities for the diluted earnings per share calculation consist of unvested shares of restricted common stock, in-the-money outstanding options to purchase the Company’s common stock, the Company’s outstanding Series C Convertible Preferred Stock, par value $0.001 per share (“Preferred Stock”), which are convertible into shares of the Company’s common stock and the Company’s outstanding 2015 Notes and 5.5% Convertible Senior Noted due 2011 (the “2011 Notes” and together with the 2015 Notes, the “Convertible Senior Notes”) which are convertible into shares of the Company’s common stock.

 

The treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period), is used to measure the dilutive impact of stock options, shares of restricted common stock and shares into which the Convertible Senior Notes and Preferred Stock are convertible.

 

Net income (loss) per share information is determined using the two-class method, which includes the weighted-average number of common shares outstanding during the period and other securities that participate in dividends (“participating security”). The Company considers the Preferred Stock to be a participating security because it includes rights to participate in dividends with the common stock. In applying the two-class method, earnings are allocated to both common stock shares and the Preferred Stock common stock equivalent shares based on their respective weighted-average shares outstanding for the period. Losses are not allocated to Preferred Stock shares. The table below sets forth the computations of basic and diluted net income per share for the three years ended December 31, 2010.

 

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| ** **                                            | ** ** | **For the Years Ended December 31,** | ** ** |
|-------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                            | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
| **Basic Net Income (Loss) Per   Common Share**        |       |                                                          |       |   |   |   |   |
| Numerator:                                            |       |                                                          |       |   |   |   |   |
| Basic net income (loss)                               |       | $                                                             | 10,127,020 |   | $ | (50,188,171 | ) | $ | 14,513,945 |   |
| Net earnings allocated to participating securities    |       | 942,721                                                       |       | — |   | — |   |
| Net income (loss) attributed to common   stockholders |       | 9,184,299                                                     |       | (50,188,171 | ) | 14,513,945 |   |
|                                                  |       |                                                          |       |   |   |   |   |
| Denominator:                                          |       |                                                          |       |   |   |   |   |
| Weighted-average common shares outstanding            |       | 110,058,936                                                   |       | 107,581,871 |   | 107,312,716 |   |
| Basic net income (loss) per share                     |       | $                                                             | 0.08       |   | $ | (0.47 | ) | $ | 0.14 |   |
|                                                  |       |                                                          |       |   |   |   |   |
| **Diluted Net Income (Loss) Per   Common Share**      |       |                                                          |       |   |   |   |   |
| Numerator:                                            |       |                                                          |       |   |   |   |   |
| Basic and diluted net income (loss)                   |       | $                                                             | 10,127,020 |   | $ | (50,188,171 | ) | $ | 14,513,945 |   |
|                                                  |       |                                                          |       |   |   |   |   |
| Denominator:                                          |       |                                                          |       |   |   |   |   |
| Basic weighted average common shares outstanding      |       | 110,058,936                                                   |       | 107,581,871 |   | 107,312,716 |   |
| Effect of dilutive securities:                        |       |                                                          |       |   |   |   |   |
| Unvested restricted stock                             |       | —                                                        |       | — |   | 233,300 |   |
| Options to purchase common stock                      |       | —                                                        |       | — |   | 4,673,627 |   |
| Assumed treasury shares purchased                     |       | —                                                        |       | — |   | (3,127,788 | ) |
| Diluted weighted average common shares outstanding    |       | 110,058,936                                                   |       | 107,581,871 |   | 109,091,855 |   |
|                                                  |       |                                                          |       |   |   |   |   |
| Diluted net income (loss) per share                   |       | $                                                             | 0.08       |   | $ | (0.47 | ) | $ | 0.13 |   |

 

The following were excluded from the computation of diluted earnings (loss) per common share because of their anti-dilutive effect.

 
| ** **                | ** ** | **For the Years Ended December 31,** | ** ** |
|---------------------------|------------|---------------------------------------------------------------|------------|
| ** **                | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
|                      |       |                                                          |       |   |   |   |   |
| Convertible notes         |       | 75,380,000                                                    |       | 16,250,000 |   | — |   |
| Common stock options      |       | 12,689,733                                                    |       | 12,096,672 |   | — |   |
| Unvested restricted stock |       | 191,300                                                       |       | 140,500 |   | — |   |

 

During January 2011, 34,600 shares of Preferred Stock were converted into 5,766,667 shares of common stock. Had this conversion occurred on December 31, 2010, the basic and diluted net income per share would have been $0.08 for the year ended December 31, 2010.

 

**Use of Estimates**

 

The preparation of the financial statements for the Company in conformity with generally accepted accounting principles in the United States (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of 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. Actual results could differ from these estimates.

 

The Company’s financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties, timing and costs associated with its retirement obligations, estimates of the fair value of

 

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derivative instruments, estimates used in stock-based compensation calculations and impairments to unproved property and to proved oil and gas properties.

 

**Other Comprehensive Income (Loss)**

 

The Company does not have any items of other comprehensive income (loss) for the years ended December 31, 2010, 2009 and 2008. Therefore, total comprehensive income (loss) is the same as net income (loss) for these periods.

 

**Income Taxes**

 

The Company uses the asset and liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of temporary differences between the accounting bases and the tax bases of the Company’s assets and liabilities.  The deferred tax assets and liabilities are computed using enacted tax rates in effect for the year in which the temporary differences are expected to reverse.

 

The Company’s policy is to recognize penalties and interest, if any, related to uncertain tax positions as general and administrative expense. The Company files income tax returns in the U.S. federal jurisdiction and various states.  There are currently no federal or state income tax examinations underway for these jurisdictions.  Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2007 and for state and local tax authorities for years before 2006.

 

**Stock Compensation**

 

The Company recognizes compensation cost for stock-based awards based on estimated fair value of the award and records compensation expense over the requisite service period. See Note 6, “Stock-Based Compensation” herein, for further discussion.

 

**Recently Issued Accounting Pronouncements**

 

In January 2010, ASC guidance for fair value measurements and disclosure was updated to require additional disclosures related to transfers in and out of level 1 and 2 fair value measurements and enhanced detail in the level 3 reconciliation. The guidance was amended to clarify the level of disaggregation required for assets and liabilities and the disclosures required for inputs and valuation techniques used to measure the fair value of assets and liabilities that fall in either level 2 or level 3. The updated guidance was effective for the Company’s fiscal year beginning January 1, 2010, with the exception of the level 3 disaggregation which is effective for the Company’s fiscal year beginning January 1, 2011. The adoption had no impact on the Company’s consolidated financial position, results of operations or cash flows. Refer to Note 9 “Fair Value Measurement” herein for further details regarding the Company’s assets and liabilities measured at fair value.

 

In December 2008, the Securities and Exchange Commission (“SEC”) revised its requirements for oil and gas reserves estimation and disclosures and related definitions to align them with current practices and changes in technology. In January 2010, the Financial Accounting Standards Board (“FASB”) aligned the current oil and gas reserve estimation and disclosure requirements with those of the SEC.  As discussed earlier, the Company follows the full cost method of accounting for which the SEC provides guidance. Among other things, the SEC and FASB amendments replace the single-day, year-end pricing assumption with a twelve-month average pricing assumption, revise certain definitions and allow the use of certain technologies to establish reserves.

 

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As of December 31, 2009, the Company changed its method of determining the quantities of oil and gas reserves which impacted the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties. Under the new rules, the Company prepared its oil and gas reserve estimates as of December 31, 2009 using the average, first-day-of-the-month price during the 12-month period ending December 31, 2009. In prior years, the Company used the year-end price. As a result, the new rules impacted the amount of depreciation, depletion and amortization recorded for oil and gas properties and the ceiling test calculation for the quarter ended December 31, 2009.  In addition, under the new guidance, subsequent price increases cannot be considered in the ceiling test calculation.

 

The adoption of the new rules was considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of the new guidance, other than pricing, significantly impacted the reserve estimates or consolidated financial statements. The Company does not believe that it is practicable to estimate the effect of applying the new rules on net loss, loss per share or the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for the year ended December 31, 2009.

 

**NOTE 3 — ASSET SALES AND ACQUISITIONS**

 

***Sale of Gathering Assets***

 

On February 26, 2010, the Company completed the sale (the “Closing”) of materially all of the assets (the “Asset Sale”) comprising its gathering system and its evaporative facilities, located in Uintah County, Utah (the “Gathering Assets”), to Monarch Natural Gas, LLC (“Monarch”) pursuant to an Asset Purchase Agreement dated January 29, 2010 (the “Purchase Agreement”). At Closing, the Company received total cash consideration of $23 million from Monarch, the entirety of which was used to repay amounts outstanding under its Credit Facility.

 

Pursuant to the Purchase Agreement, simultaneous with Closing, Gasco entered into (i) a transition services agreement with Monarch pursuant to which the Company provided certain services relating to the operation of the Gathering Assets to Monarch for a six-month term commencing at Closing; (ii) a gas gathering agreement with Monarch pursuant to which the Company dedicated its natural gas production from all of its Utah acreage for a minimum fifteen-year period and Monarch provides gathering, compression and processing services utilizing the Gathering Assets to the Company; and (iii) a salt water disposal services agreement with Monarch pursuant to which the Company may deliver salt water produced by its operations to the evaporative facilities that Monarch acquired in the Asset Sale for a minimum 15-year period. The Purchase Agreement was subject to customary post-closing terms and conditions for transactions of this size and nature.

 

The Company recorded deferred income of approximately $3 million on the Asset Sale which will be amortized over the fifteen-year terms of the gathering and salt water disposal contracts with Monarch.

 

The following unaudited pro forma information is presented as if the Asset Sale had an effective date of January 1, 2008.

 

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| ** **                                                    | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                    | ** ** | **2010**                                   | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                                          |       |                                       |       |   |   |   |   |
| Revenue as reported                                           |       | $                                          | 20,262,099 |   | $ | 21,089,039 |   | $ | 41,858,173 |   |
| Less revenue from sale of Gathering Assets                    |       | 595,942                                    |       | 5,004,204 |   | 4,796,409 |   |
| Pro forma revenue                                             |       | $                                          | 19,666,157 |   | $ | 16,084,835 |   | $ | 37,061,764 |   |
|                                                          |       |                                       |       |   |   |   |   |
| Net income (loss) as reported                                 |       | $                                          | 10,127,020 |   | $ | (50,188,171 | ) | $ | 14,513,945 |   |
| Add operating loss resulting from the Gathering   Assets sale |       | (824,337                                   | )          | (4,745,058 | ) | (4,795,660 | ) |
| Pro forma net income   (loss)                                 |       | $                                          | 9,302,683  |   | $ | (54,933,229 | ) | $ | 9,718,285 |   |
|                                                          |       |                                       |       |   |   |   |   |
| Net income (loss) per share - basic as reported               |       | $                                          | 0.08       |   | $ | (0.47 | ) | $ | 0.14 |   |
| Add net loss per share - from sale of Gathering   Assets      |       | (0.01                                      | )          | (0.04 | ) | (0.04 | ) |
| Pro forma net income (loss) per share basic                   |       | $                                          | 0.07       |   | $ | (0.51 | ) | $ | 0.10 |   |
|                                                          |       |                                       |       |   |   |   |   |
| Net income (loss) per share – diluted as reported        |       | $                                          | 0.08       |   | $ | (0.47 | ) | $ | 0.13 |   |
| Add net loss per share - from sale of Gathering   Assets      |       | (0.01                                      | )          | (0.04 | ) | (0.04 | ) |
| Pro forma net income (loss) per share diluted                 |       | $                                          | 0.07       |   | $ | (0.51 | ) | $ | 0.09 |   |

 

The Company adopted the plan to dispose of and was actively engaged in marketing for sale its gathering assets and water disposal facilities during the fourth quarter of 2009. As a result, these assets were separately presented in the consolidated balance sheets as of December 31, 2009 at the lower of carrying value or fair value less the cost to sell. Additionally, the asset retirement obligations related to these assets were also reclassified to liabilities associated with assets held for sale. The Company determined that the revenue and expenses from these assets did not qualify for discontinued operations accounting. The following table summarizes the assets and liabilities related to the assets held for sale as of December 31, 2009.

 
| **December 31, 2009**                                | ** ** | **Gathering   Assets** | ** ** | **Water Disposal   Facilities** | ** ** | **Total**  | ** ** |
|----------------------------------------------------------------|------------|------------------------|------------|--------------------------------------|------------|------------|------------|
| Lower of book value or fair value less costs to   sell         |       | $                      | 18,101,536 |                                 | $          | 6,264,003  |       | $ | 24,365,539 |   |
| Accumulated depreciation                                       |       | (3,778,695             | )          | (431,300                             | )          | (4,209,995 | )          |
| Assets held for sale                                           |       | $                      | 14,322,841 |                                 | $          | 5,832,703  |       | $ | 20,155,544 |   |
|                                                           |       |                   |       |                                 |       |       |       |
| Asset retirement obligations related to assets   held for sale |       | $                      | 43,589     |                                 | $          | 163,006    |       | $ | 206,595 |   |

 

***Acquisition of Petro-Canada Assets***

 

On****February 25, 2010, the Company completed the acquisition of two wells and certain oil and gas leases (the “Petro-Canada Assets”) from Petro-Canada Resources (USA) Inc., a Colorado corporation (“Petro-Canada”), for a purchase price of approximately $482,000, subject to customary post-closing terms and conditions for transactions of this size and nature. The sale was made pursuant to a definitive agreement dated February 4, 2010 by and between the Company and Petro-Canada. The Petro-Canada Assets include one producing well, one shut in well with recompletion potential and 5,582 gross and net acres

 

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located in Utah, west of our Gate Canyons operating area. This acquisition was funded with cash flows from operating activities.

 

***Sale of Partial Working Interest in Producing Wells***

 

On March 19, 2010, the Company closed the sale of a partial working interest in 32 wells for $1.25 million. The 32 wells were part of a joint venture project that was started in 2002 under which each of the participants received a net profits interest in these wells for a period of twelve years from initial production date. The Company agreed to sell its interest in these wells related to the period subsequent to the initial twelve year period to one of the joint venture participants and to convert the purchaser’s net profits interest into a working interest. The proceeds received were recorded as a credit to the full cost pool during the year ended December 31, 2010 (during the first quarter of 2010).

 

***Prospect Fee***

 

During September 2010, Gasco entered into an arrangement with an exploration and production company which operates in California, pursuant to which the Company received a $1.5 million prospect fee related to certain of its California acreage. The fee reimburses costs that the Company has invested in the area and provides it with a potential carried interest of 20% in two wells to be drilled on the acreage.  Additionally, the farmee is obligated to obtain and provide to Gasco 3-D Seismic data over the contract area. The proceeds received were recorded as a credit to unproved properties during the year ended December 31, 2010 (during the third quarter of 2010).

 

**NOTE 4 -****CONVERTIBLE SENIOR NOTES**

 

**Exchange Transaction**

 

On June 22, 2010, the Company entered into exchange agreements (collectively, the “Exchange Agreements”) with certain holders (collectively, the “Investors”) of its outstanding 2011 Notes. In accordance with the Exchange Agreements, on June 25, 2010 (the “Closing Date”), the Company exchanged $64,532,000 aggregate principal amount of its 2011 Notes (representing 99.28% of the then outstanding 2011 Notes) for $64,532,000 aggregate principal amount of the Company’s newly issued 2015 Notes, which are convertible, at the option of the holder, into shares of the Company’s common stock and/or shares of the Company’s Preferred Stock which are convertible into shares of common stock (the “Exchange Transaction”). The Company also paid to the Investors an aggregate cash amount of $788,724, equal to all accrued but unpaid interest with respect to the 2011 Notes as of but not including the Closing Date.

 

The 2015 Notes have a final maturity date of October 5, 2015. The 2015 Notes are governed by an indenture (the “Indenture”), dated as of June 25, 2010, by and between the Company and Wells Fargo Bank, National Association, as trustee (the “Trustee”). The 2015 Notes were issued pursuant to the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), provided by Section 4(2) and Regulation D thereunder.

 

The 2015 Notes bear interest at a rate of 5.50% per annum, to be paid in arrears, on April 5 and October 5 of each year commencing on October 5, 2010.

 

As stated above, the 2015 Notes are convertible, at the option of the holder, at any time prior to maturity, into common stock or, at the election of such holder, into Preferred Stock. The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015

 

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Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock, other than pursuant to an automatic conversion (described below), is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the Indenture, the Company could not issue shares of common stock to holders of the 2015 Notes (including shares of common stock issuable upon a conversion of the 2015 Notes or upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes or in payment of any change of control purchase price, make whole premium or conversion make whole payment (each as described in the Indenture)) in excess of 19.9% of the number of shares of common stock outstanding immediately prior to the closing of the Exchange Transaction (the “Exchange Cap”), until stockholder approval of the issuance of common stock in excess of the Exchange Cap was obtained or the Company obtained a written opinion from its outside counsel that such approval was not required. Additionally, pursuant to the Indenture, a holder may not convert all or any portion of such holder’s 2015 Notes into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion, beneficially own more than 4.99% of the outstanding shares of common stock (the “Maximum Ownership Percentage”), provided that such holder, upon not less than 61 days’ prior written notice to the Company, may increase the Maximum Ownership Percentage applicable to such holder (but, for the avoidance of doubt, not for any subsequent or other holder) to 9.9% of the outstanding shares of common stock.

 

The Company may redeem the 2015 Notes in whole or in part for cash at any time at a redemption price equal to 100% of the principal amount of the 2015 Notes plus any accrued and unpaid interest and liquidated damages, if any, on the 2015 Notes redeemed to but not including the redemption date, if the closing price of the Company’s common stock equals or exceeds 150% of the conversion price for at least 20 trading days within the consecutive 30 trading day period ending on the trading day before the redemption date and all of the equity conditions set forth in the Indenture are satisfied (or waived in writing by the holders of a majority in aggregate principal amount of the 2015 Notes then outstanding). If a holder elects to convert its 2015 Notes in connection with such a provisional redemption by the Company, the Company will make an additional payment equal to the total value of the aggregate amount of the interest otherwise payable on the 2015 Notes to be calculated from the last day through which interest was paid on the 2015 Notes through and including the third anniversary of the Closing Date and discounted to the present value of such payment; provided, however, that at the Company’s option, in lieu of such discounted cash payment, the Company may deliver shares of Preferred Stock having a value equal to such discounted cash payment. The value of each share of Preferred Stock to be delivered shall be deemed equal to the product of (i) the average closing price per share of common stock over the ten trading day period ending on the trading day before the redemption date, and (ii) the number of whole shares of common stock into which each share of Preferred Stock is then convertible (without giving effect to any limitations on conversion in the Certificate of Designations of the Preferred Stock) (subject to certain conditions).

 

Upon a change of control (as defined in the Indenture), each holder of 2015 Notes may require the Company to repurchase some or all of its 2015 Notes at a repurchase price equal to 100% of the aggregate principal amount of the 2015 Notes to be repurchased plus accrued and unpaid interest and liquidated damages, if any, to but not including the date of purchase, plus, in certain circumstances, a make whole premium. The Company may pay the change of control purchase price and/or the make whole premium in cash or shares of Preferred Stock at the Company’s option. In addition, in the case of the make whole premium, at the Company’s option, the Company may pay such premium in the same form of consideration used to pay for the shares of common stock in connection with the transaction constituting the change of control. On or after September 15, 2010 or to the extent the Company has exercised its provisional redemption right, holders of the 2015 Notes are permitted to convert the 2015 Notes in full, subject to the Maximum Ownership Percentage.

 

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The Indenture contains usual and customary covenants limiting the Company’s ability to incur additional indebtedness, with certain exceptions, or liens on its property or assets, restricting its ability to make dividends or other distributions, requiring its domestic subsidiaries to guaranty the 2015 Notes, requiring it to list the shares of common stock that may be issued upon conversion of the 2015 Notes and the Preferred Stock on the NYSE Amex or any other U.S. national or regional securities exchange on which the common stock is then listed, and requiring it to use reasonable best efforts to obtain stockholder approval for the issuance of shares of common stock upon conversion of the 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes.

 

Events of default under the Indenture include (1) the Company’s failure to pay (in cash or, if applicable, shares of Preferred Stock) principal or premium (including any make whole premium or conversion make-whole payment) when due; (2) the Company’s failure to pay interest, including liquidated damages, if any, when due on the 2015 Notes, and such failure continues for 30 days after the date when due; (3) the Company’s failure to issue and deliver shares of common stock or Preferred Stock, and any cash in lieu of fractional shares, when such shares of common stock, Preferred Stock or cash in lieu of fractional shares is required to be delivered, and such failure continues for 10 days after the required delivery date; (4) the Company’s failure to give timely notice of a change of control; (5) during the required period, the Company’s failure to file certain reports, statements and other documents required to be filed by the Company with the SEC prior to the periods set forth in the Indenture; (6) the Company’s failure to perform or observe any other term, covenant or agreement in the 2015 Notes or the Indenture for 60 days after written notice of such failure has been given to the Company as provided in the Indenture; (7) the Company’s or that of its significant subsidiaries’ failure to make payments by the end of the applicable grace period, if any, on indebtedness for borrowed money in excess of $5 million or if indebtedness for borrowed money of the Company or a significant subsidiary in excess of $5 million is accelerated in certain circumstances; (8) certain events of bankruptcy, insolvency or reorganization with respect to the Company or a significant subsidiary or any of the Company’s subsidiaries which in the aggregate would constitute a significant subsidiary; and (9) a default occurs under any permitted subordinated indebtedness in excess of $2,000,000 individually or in the aggregate.

 

The 2015 Notes are unsecured and unsubordinated and rank on a parity in right of payment with all of the Company’s existing and future senior unsecured indebtedness (including any 2011 Notes that were not exchanged for 2015 Notes), rank senior in right of payment to any of the Company’s existing and future subordinated indebtedness, and are effectively subordinated in right of payment to any of the Company’s secured indebtedness or other obligations to the extent of the value of the assets securing such indebtedness or other obligations. The Company’s subsidiaries guarantee the 2015 Notes pursuant to a Guaranty Agreement dated as of June 25, 2010, by and among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of the Trustee.

 

The Company received stockholder approval for the issuance of all of the shares of common stock issuable upon conversion of the 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes in accordance with applicable law and the rules of the NYSE Amex at its 2010 Annual Meeting of Stockholders, which was held on September 15, 2010. As provided for in the Indenture, following receipt of the stockholder approval described above, an aggregate principal amount of 2015 Notes equal to the difference (but not less than zero) of (i) 30% of the original principal amount of all 2015 Notes minus (ii) the principal amount, if any, of the 2015 Notes that had been repaid, redeemed or repurchased by the Company, or converted into shares of common stock or Preferred Stock by holders of the 2015 Notes, automatically converted into a number of shares of Preferred Stock equal to the aggregate principal amount of such 2015 Notes to be so converted multiplied by 0.01579.

 

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The Exchange Transaction was recorded as an extinguishment of debt whereby the difference between the fair value of the 2015 Notes and the carrying value of the 2011 Notes (inclusive of unamortized debt issuance costs), was recorded as a gain on the extinguishment of debt in the accompanying consolidated statement of operations. Prior to September 15, 2010, the date on which the Company received shareholder approval for the issuance of the shares of common stock to settle the conversion of the 2015 Notes, the conversion feature in the 2015 Notes was accounted for separately as an embedded derivative at fair value, yet presented together with the 2015 Notes, in the consolidated balance sheet.  The changes in the fair value of the embedded derivative through September 15, 2010 were reported as derivative gains (losses) in the consolidated statement of operations. On September 15, 2010, because shareholders approved the Company’s right to issue common stock to settle the conversion feature in the 2015 Notes, the fair value of the conversion feature at that date was reclassified to additional paid-in-capital under the provisions of ASC paragraph 815-15-40-1. The debt host component of the 2015 Notes was unaffected by this reclassification and continues to be accounted for on an amortized cost basis where the debt discount continued to be accreted to interest expense under the effective interest method at a rate of 26.3%.

 

On September 20, 2010, the Company effected the 30% automatic conversion of $19,364,000 of the outstanding principal amount of the 2015 Notes into 305,754 shares of Preferred Stock which resulted in a reclassification of $306 and $19,363,694 into Preferred Stock, and additional paid-in capital, respectively.  Additionally upon the conversion of 30% of the original principal amount of the 2015 Notes, a pro-rata portion of the unamortized discount and debt interest costs were recorded as interest expense ($12 million). The Company paid an aggregate cash amount of $254,599, equal to all accrued but unpaid interest on the 2015 Notes subject to automatic conversion through the automatic conversion date of September 20, 2010.

 

**Note Purchase**

 

During August 2010, the Company purchased $68,000 in principal value of its 2011 Notes including interest for $54,400. The difference between the purchase price and the principal value less unamortized debt issuance costs was recorded as a gain on the extinguishment of debt.

 

**NOTE 5 — DERIVATIVES**

 

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. As discussed in Note 4 “Convertible Senior Notes” herein, the Company recorded an embedded derivative related to its 2015 Notes during the year ended December 31, 2010. The following table details the fair value of the derivatives recorded in the consolidated balance sheets, by category:

** **
| ** **                         | ** ** | **Location on Consolidated** | ** ** | **Fair Value at December 31,** | ** ** |
|------------------------------------|------------|----------------------------------------|------------|----------------------------------------------------|------------|
| ** **                         | ** ** | **Balance Sheets**                | ** ** | **2010**                                           | ** ** | **2009** | ** ** |
|                               |       |                                   |       |                                               |       |   |   |
| Natural gas derivative   contracts |       | Current assets                         |       | $                                                  | 193,959    |   | $ | — |   |
| Natural gas derivative   contracts |       | Current liabilities                    |       | —                                             |       | 1,932,513 |   |
| Natural gas derivative   contracts |       | Noncurrent liabilities                 |       | —                                             |       | 761,092 |   |
|                                    |            |                                        |            |                                                    |            |  |  |  |  |

 

As of December 31, 2010 and 2009, natural gas derivative instruments consisted of three swap agreements for 2009 through December 2011 production and two swap agreements for 2009 through March 2011 related to gas production, respectively. These natural gas derivative instruments allow the Company to predict with greater certainty the effective natural gas prices to be realized for its production. For its swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating market price

 

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to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

 

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2010, 2009 and 2008.

 
| ** **                                              | ** ** | **For the Years Ended December 31,** | ** ** |
|---------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                              | ** ** | **2010**                                                      | ** ** | **2008** | ** ** | **2007** | ** ** |
|                                                    |       |                                                          |       |   |   |   |   |
| Realized gains on   commodity instruments               |       | $                                                             | 1,588,235  |   | $ | 13,060,074 |   | $ | 562,120 |   |
| Change in fair value of   commodity instruments, net    |       | 2,887,564                                                     |       | (11,549,552 | ) | 9,199,706 |   |
| Change in fair value of   embedded derivative feature   |       | 6,840,392                                                     |       | — |   | — |   |
| Total realized and   unrealized gains (losses) recorded |       | $                                                             | 11,316,191 |   | $ | 1,510,522 |   | $ | 9,761,826 |   |

 

These realized and unrealized gains and losses are recorded in the accompanying consolidated statements of operations as derivative gains (losses).

 

The Company’s swap agreements as of December 31, 2010 are summarized in the table below:

 
| **Agreement   Type** | ** ** | **Remaining********Term** | ** ** | **Quantity**    | ** ** | **Fixed Price********Counterparty payer** | ** ** | **Floating Price (a)********Gasco payer** | ** ** |
|----------------------|------------|---------------------------|------------|-----------------|------------|-----------------------------------------------------|------------|----------------------------------------------------------|------------|
| Swap                 |       | 1/11 — 3/11          |       | 3,000 MMBtu/day |       | $4.825/MMBtu                                        |       | NW Rockies                                               |       |
| Swap (b)             |       | 1/11 — 3/11          |       | 2,000 MMBtu/day |       | $4.418/MMBtu                                        |       | NW Rockies                                               |       |
| Swap                 |       | 1/11 — 12/11         |       | 2,000 MMBtu/day |       | $4.000/MMBtu                                        |       | NW Rockies                                               |       |

 

----

(c)                            Northwest Pipeline Rocky Mountains — Inside FERC first of month index price.

(d)                           Includes information pertaining to a portion of a single natural gas derivative contract with declining volumes. The fixed price represents the weighted average price for the entire period from June 2009 through March 2011.

 

During January 2011, the Company entered into a costless collar agreement that contains a fixed floor price (purchased) and ceiling price (written). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price; no payments are due from either party. This collar agreement is for 2,000 MMBtu/day with a call price of $5.12/MMBtu and a put price of $4.25/MMBtu for production from January 1, 2012 through December 31, 2012.

 

**NOTE 6 — STOCK-BASED COMPENSATION**

 

The Company has outstanding common stock options and restricted stock issued under its equity incentive plans. The Company measures the fair value at the grant date for stock option grants and restricted stock awards and records compensation expense over the requisite service period. The expense recognized over the service period includes an estimate of the awards that will be forfeited.  Gasco is assumes no forfeitures for employee awards based on the Company’s historical forfeiture experience.  For non-employee awards, Gasco is assumed a 3% forfeiture rate for the years ending December 31, 2010, 2009 and 2008.  The fair value of stock options is calculated using the Black-Scholes option-pricing model and the fair value of restricted stock is based on the fair value of the stock on the date of grant.

 

The Company accounts for stock compensation arrangements with non-employees using a fair value approach. Under this approach, the stock compensation related to the unvested stock options issued to

 

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non-employees is recalculated at the end of each reporting period based upon the fair value on that date. During the years ended December 31, 2010, 2009 and 2008, the Company recognized stock-based compensation as follows:

 
| ** **                                                                                    | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                    | ** ** | **2010**                                   | ** ** | **2009** | ** ** | **2008** | ** ** |
| ** **                                                                                    | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Employee compensation                                                                         |       | $                                          | 1,368,863  |   | $ | 1,933,843 |   | $ | 3,047,661 |   |
| Consultant compensation (reduction in   compensation)                                         |       | (4,969                                     | )          | 18,042 |   | 86,363 |   |
| Total stock-based compensation                                                                |       | 1,363,894                                  |       | 1,951,885 |   | 3,134,024 |   |
| Less: consultant compensation expense (reduction   in expense) capitalized as proved property |       | (1,370                                     | )          | 7,110 |   | 31,026 |   |
| Stock-based compensation expense                                                              |       | $                                          | 1,365,264  |   | $ | 1,944,775 |   | $ | 3,102,998 |   |

 

The Company did not recognize a tax benefit from stock-based compensation expense because the Company considers it more likely than not that the related deferred tax assets, which have been reduced by a full valuation allowance, will not be recognized.

 

The Company uses the Black-Scholes option-pricing model to estimate the fair value of the options at the grant date. The fair value of options granted to the Company’s employees and directors during 2010, 2009, and 2008 was calculated using the following assumptions:

 
| ** **                | ** ** | **Employee and Director Options** | ** ** |
|---------------------------|------------|--------------------------------------------------|------------|
| ** **                | ** ** | **2010**                                         | ** ** | **2009** | ** ** | **2008** | ** ** |
| Expected dividend yield   |       | —                                           |       | — |   | — |   |
| Expected price volatility |       | 76-78%                                           |       | 75-80% |   | 70-74% |   |
| Risk-free interest rate   |       | 1.4 – 2.3%                                  |       | 2.2 – 2.8% |   | 1.4 – 4.0% |   |
| Expected life of options  |       | 5 years                                          |       | 5-6 years |   | 5-6 years |   |

 

The weighted average grant-date fair value of options granted to employees and directors during 2010, 2009, and 2008 was $0.23, $0.31, and $1.02, respectively.

 

The expected stock price volatility assumption was determined using the historical volatility of the Company’s common stock over the expected life of the option.

 

***Stock Options***

 

During the year ended December 31, 2010, the Company granted 1,371,000 options to purchase 50,000, 175,000, 646,000 and 500,000 shares of common stock with exercise prices of $0.34, $0.35, $0.36 and $0.37 per share, respectively. These options have a two year vesting period and expire within five years of the grant date. These options were granted contingent on shareholder approval of a new stock option plan, which will be included in the proposals at the Company’s annual meeting of shareholders during June 2011 and may not be exercised until approval is received. Therefore these options are accounted for as liability awards until shareholder approval is obtained. A share-based compensation liability of $32,055 is included in current accrued liabilities in the accompanying consolidated balance sheet as of December 31, 2010.

 

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The following table summarizes the stock option activity in the equity incentive plans during the years ended December 31, 2010, 2009 and 2008:

 
| ** **                       | ** ** | **2010**            | ** ** | **2009**                                  | ** ** | **2008**            | ** ** |
|----------------------------------|------------|---------------------|------------|-------------------------------------------|------------|---------------------|------------|
| ** **                       | ** ** | **Stock   Options** | ** ** | **Weighted   Average   Exercise   Price** | ** ** | **Stock   Options** | ** ** | **Weighted   Average   Exercise   Price** | ** ** | **Stock   Options** | ** ** | **Weighted   Average   Exercise   Price** | ** ** |
| Outstanding at beginning of year |       | 12,096,672          |       | $                                         | 1.82       |                | 11,124,788 |   | $ | 2.06 |   | 10,729,138 |   | $ | 2.58 |   |
| Granted                          |       | 1,371,000           |       | $                                         | 0.36       |                | 1,752,083  |   | $ | 0.66 |   | 2,938,750 |   | $ | 1.76 |   |
| Exercised                        |       | —              |       | —                                    |       | —              |       | — |   | (566,566 | ) | $ | 2.05 |   |
| Forfeited                        |       | (86,547             | )          | $                                         | 1.64       |                | (373,489   | ) | $ | 1.32 |   | (686,573 | ) | $ | 3.14 |   |
| Cancelled                        |       | (691,392            | )          | $                                         | 2.46       |                | (406,710   | ) | $ | 3.78 |   | (1,289,961 | ) | $ | 5.18 |   |
| Outstanding at the end of year   |       | 12,689,733          |       | $                                         | 1.63       |                | 12,096,672 |   | $ | 1.82 |   | 11,124,788 |   | $ | 2.06 |   |
| Exercisable at December 31, |       | 10,548,230          |       | $                                         | 1.83       |                | 8,941,784  |   | $ | 2.03 |   | 7,461,351 |   | $ | 2.17 |   |

 

The following table summarizes information related to the outstanding and vested options as of December 31, 2010:

 
| ** **                                             | ** ** | **Outstanding Options** | ** ** | **Vested options** | ** ** |
|--------------------------------------------------------|------------|------------------------------|------------|-------------------------|------------|
| Number of shares                                       |       | 12,689,733                   |       | 10,548,230              |       |
| Weighted Average Remaining Contractual Life in   years |       | 3.27                         |       | 2.99                    |       |
| Weighted Average Exercise Price                        |       | $                            | 1.63       |                    | $          | 1.83 |   |
| Aggregate intrinsic value                              |       | $                            | 9,200      |                    | $          | 5,000 |   |

 

The aggregate intrinsic value in the table above is based on the Company’s closing common stock price of $0.35 as of December 31, 2010, which would have been received by the option holders had all option holders exercised their options as of that date.

 

There were no options exercised during the years ending December 31, 2010 and 2009.The total intrinsic value of options exercised during the year ending December 31, 2008 was $983,238.

 

The Company settles employee stock option exercises with newly issued common shares.

 

As of December 31, 2010, there was $501,778 of total unrecognized compensation cost related to non-vested options granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 1.7 years.

 

During the year ended December 31, 2009, the Company granted options to purchase 1,752,083 shares of common stock with exercise prices ranging from $0.22 to $5.69 per share. The weighted average grant-date fair value of the options granted during the twelve months ended December 31, 2009 was $0.31 per share.

 

During the year ended December 31, 2008, the Company cancelled 1,255,000 stock options with exercise prices ranging from $3.10 to $5.69.  In exchange, the Company granted to the optionees 316,250 stock options with an exercise price of $1.00.  This resulted in a modification of the original award.  However, because the fair value of the issued options did not exceed the fair value of the cancelled options on the date of the exchange, no incremental compensation expense was recognized.

 

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The following table summarizes the stock options outstanding at December 31, 2010.

 
| **Range of   exercise   Prices per   Share** | ** ** | **Number of   Shares   Outstanding** | ** ** | **Number of   Shares   Exercisable** | ** ** | **Weighted Average   Remaining   Contractual Life of   Shares Outstanding   (years)** | ** ** |
|--------------------------------------------------------|------------|-------------------------------------------|------------|-------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------|------------|
|                                                   |       |                                      |       |                                      |       |                                                                                                      |       |
| $0.00 – $0.99                                     |       | 3,111,500                                 |       | 1,251,477                                 |       | 4.2                                                                                                       |       |
| $1.00 – $1.99                                     |       | 5,520,150                                 |       | 5,308,670                                 |       | 2.7                                                                                                       |       |
| $2.00 – $2.99                                     |       | 1,971,000                                 |       | 1,971,000                                 |       | 2.3                                                                                                       |       |
| $3.00 – $3.99                                     |       | 1,995,000                                 |       | 1,925,000                                 |       | 4.4                                                                                                       |       |
| $4.00 – $4.99                                     |       | 40,000                                    |       | 40,000                                    |       | 7.5                                                                                                       |       |
| $5.00 – $5.99                                     |       | 52,083                                    |       | 52,083                                    |       | 5.3                                                                                                       |       |
| Total                                                  |       | 12,689,733                                |       | 10,548,230                                |       | 3.3                                                                                                       |       |

 

***Restricted Stock***

 

The following table summarizes the restricted stock activity for the years ending December 31, 2010, 2009 and 2008:

 
| ** **                               | ** ** | **2010**               | ** ** | **2009**                              | ** ** | **2008**               | ** ** |
|------------------------------------------|------------|------------------------|------------|---------------------------------------|------------|------------------------|------------|
| ** **                               | ** ** | **Restricted   Stock** | ** ** | **Weighted   Average   Fair   Value** | ** ** | **Restricted   Stock** | ** ** | **Weighted   Average   Fair   Value** | ** ** | **Restricted   Stock** | ** ** | **Weighted   Average   Fair   Value** | ** ** |
| Outstanding at the beginning of the year |       | 140,500                |       | $                                     | 2.39       |                   | 233,300    |   | $ | 2.35 |   | 308,820 |   | $ | 2.36 |   |
| Granted                                  |       | 150,000                |       | $                                     | 0.37       |                   | 7,500      |   | $ | 0.25 |   | 49,000 |   | $ | 3.20 |   |
| Vested                                   |       | (78,500                | )          | $                                     | 2.51       |                   | (62,200    | ) | $ | 2.56 |   | (56,020 | ) | $ | 2.97 |   |
| Forfeited                                |       | (20,700                | )          | $                                     | 2.83       |                   | (38,100    | ) | $ | 1.44 |   | (68,500 | ) | $ | 2.31 |   |
| Outstanding at the end of the year       |       | 191,300                |       | $                                     | 0.70       |                   | 140,500    |   | $ | 2.39 |   | 233,300 |   | $ | 2.35 |   |

 

The total grant date fair value of the shares vested during the years ending December 31, 2010, 2009, and 2008 was $197,055, $159,051 and $166,400, respectively.

 

As of December 31, 2010, there was $106,949 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a weighted-average period of 2.2 years.

 

**NOTE 7 — OIL AND GAS PROPERTY**

 

The Company’s oil and gas properties are summarized in the following table:

 

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| ** **                                                              | ** ** | **As of December 31,** | ** **  |
|-------------------------------------------------------------------------|------------|---------------------------------------|-------------|
| ** **                                                              | ** ** | **2010**                              | ** **  | **2009** | ** ** |
|                                                                    |       |                                  |        |   |   |
| Proved properties                                                       |       | $                                     | 263,104,555 |   | $ | 254,682,870 |   |
| Unproved properties                                                     |       | 35,941,100                            |        | 38,638,936 |   |
| Facilities and equipment                                                |       | 1,120,134                             |        | 971,890 |   |
| Total                                                                   |       | 300,165,789                           |        | 294,293,696 |   |
| Less accumulated depletion, depreciation,   amortization and impairment |       | (230,509,273                          | )           | (227,039,725 | ) |
| Assets held for sale                                                    |       | —                                |        | 20,155,544 |   |
|                                                                    |       | $                                     | 69,656,516  |   | $ | 87,409,515 |   |

 

The following table presents information regarding the Company’s net costs incurred in the purchase of proved and unproved properties and in exploration and development activities:

 
| ** **                  | ** ** | **For the Years Ended December 31,** | ** ** |
|-----------------------------|------------|---------------------------------------------------------------|------------|
| ** **                  | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
| Property acquisition costs: |       |                                                          |       |   |   |   |   |
| Unproved                    |       | $                                                             | 313,238    |   | $ | 647,721 |   | $ | 624,815 |   |
| Proved                      |       | 481,947                                                       |       | — |   | — |   |
| Exploration costs           |       | 968,683                                                       |       | 1,895,981 |   | 24,607,162 |   |
| Development costs           |       | 5,151,909                                                     |       | 2,486,858 |   | 11,758,219 |   |
| Total                       |       | $                                                             | 6,915,777  |   | $ | 5,030,560 |   | $ | 36,990,196 |   |

 

At December 31, 2010 the Company’s unproved properties consist of leasehold acquisition and exploration costs in the following areas:

 
| ** ** | ** ** | **2010** | ** ** | **2009**  | ** ** |
|------------|------------|----------|------------|-----------|------------|
|       |       |     |       |      |       |
| Utah       |       | $        | 34,467,479 |      | $          | 36,980,706 |   |
| California |       | 564,625  |       | 1,049,364 |       |
| Nevada     |       | 908,996  |       | 608,866   |       |
|       |       | $        | 35,941,100 |      | $          | 38,638,936 |   |

 

During the years ended December 31, 2010 and 2009, we reclassified approximately $3,000,000 and $1,100,000 of acreage costs in Utah, respectively and $200,000 of acreage costs primarily in California during the year ended December 31, 2009, into proved property and included these amounts in the ceiling test and depletion calculations. These acreage costs represent the value of leases that would expire during 2011 and 2010 before we are able to develop them further and a reduction in the carrying value of our Utah leases based upon the appraised value of our acreage as of December 31, 2010.

 

The following table sets forth a summary of oil and gas property costs not being amortized as of December 31, 2010, by the year in which such costs were incurred.

 
| ** **        | ** ** | **Balance**  | ** ** | **Costs Incurred During Years Ended December 31,** | ** ** |
|-------------------|------------|--------------|------------|----------------------------------------------------------------------------------|------------|
| ** **        | ** ** | **12/31/10** | ** ** | **2010**                                                                         | ** ** | **2009** | ** ** | **2008** | ** ** | **Prior** | ** ** |
|              |       |         |       |                                                                             |       |   |   |   |   |   |   |
| Acquisition costs |       | $            | 30,131,181 |                                                                             | $          | 166,772 |   | $ | 457,602 |   | $ | 251,649 |   | $ | 29,255,158 |   |
| Exploration costs |       | 5,809,919    |       | 146,467                                                                          |       | 190,116 |   | 869,763 |   | 4,603,573 |   |
| Total             |       | $            | 35,941,100 |                                                                             | $          | 313,239 |   | $ | 647,718 |   | $ | 1,121,412 |   | $ | 33,858,731 |   |

 

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We believe that the majority of our unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before we can explore or develop it further, or by making decisions that further exploration and development activity will not occur.

 

**NOTE 8 — CREDIT FACILITY**

 

The Company’s $250 million revolving credit facility (“Credit Facility”) is available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes. Borrowings made under the Credit Facility are secured by a pledge of the capital stock of certain of the Company’s subsidiaries and mortgages on substantially all of the Company’s oil and gas properties.

 

On February 1, 2010, the Company entered into the Ninth Amendment to Credit Facility, pursuant to which the Credit Facility was amended to, among other things, (i) remove the scheduled redetermination of the borrowing base on or about January 30, 2010, with the effect that scheduled redeterminations for the year ended December 31, 2010 revert to the regular redetermination schedule of every six months on or about May 1 and November 1 of each year, and (ii) reduce the borrowing base to $16 million from $35 million by incremental fixed amounts in connection with certain contemplated asset sales, and, effective as of April 1, 2010, to automatically reduce the borrowing base to $16 million, regardless of whether any of the contemplated asset sales were consummated. The Ninth Amendment also provided for the release of certain liens relating to those assets that secure the Company’s obligations under the Credit Facility.  Effective February 26, 2010, in connection with the consummation of the sale of the Gathering Assets and the application of the proceeds of $23 million therefrom to pay down outstanding borrowings, the Company elected to reduce the borrowing base to $16 million effective immediately as further discussed in Note 3 “Asset Sales and Purchases” herein.

 

The Ninth Amendment also increased the interest rate pricing grid by 25 basis points for Eurodollar based loans and for alternate base rate (“ABR”) priced loans effective February 1, 2010. Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an ABR. The Eurodollar rate is calculated as LIBOR plus an applicable margin that, as amended, varies from 2.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 3.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The ABR, as amended, is equal to the sum of (i) the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50% and (c) the Adjusted LIBOR for a one month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 2.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The Company elects the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the Lenders may require the Company to use the non-elected basis in the event that the elected basis does not adequately and fairly reflect the cost of making such loans. The interest rate on our Credit Facility was 3.36% as of December 31, 2010.

 

On June 22, 2010, in connection with the Exchange Transaction, the Company entered into the Tenth Amendment to the Credit Facility pursuant to which the Credit Facility was amended to, among other things, permit (i) the Company’s incurrence of indebtedness under the 2015 Notes, (ii) the Company’s Subsidiaries’ guarantee of the 2015 Notes; (iii) the Company’s incurrence of indebtedness and related liens relating to certain insurance policies; (iv) the interest payments and equity payments (of common stock and Preferred Stock) required under the 2015 Notes; and (v) and the exchange of the 2011 Notes for the 2015 Notes and other transactions and requirements contemplated by the Exchange Transaction further described in Note 4 “Convertible Senior Notes” herein.

 

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On November 3, 2010, the Company entered into the Eleventh Amendment to Credit Agreement (the “Eleventh Amendment”). The Eleventh Amendment was entered into in connection with the Company’s November 2010 borrowing base redetermination, which under the Credit Agreement are scheduled to occur semi-annually in May and November of each calendar year; the Company and the lenders may also request one additional unscheduled redetermination during each calendar year. Pursuant to the Eleventh Amendment, the Credit Agreement was amended, among other things, to acknowledge and reaffirm that the Company’s borrowing base is $16,000,000, which will remain in effect until the earlier of (i) the next redetermination of the borrowing base, which is currently scheduled for May 2011 and (ii) the date such borrowing base is otherwise reduced pursuant to the terms of the Credit Agreement. The Eleventh Amendment also extended the termination of the credit facility by one year to March 26, 2012.

 

The Credit Facility requires the Company to comply with financial covenants that require it to maintain (1) a current ratio (defined as current assets plus unused availability under the Credit Facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1.0; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Facility) for the most recent four quarters not to be greater than 3.5:1.0 for each fiscal quarter.  In addition, the Credit Facility contains covenants that restrict the Company’s ability to incur other indebtedness, create liens or sell the Company’s assets, pay dividends on the Company’s common stock and make certain investments. Sustained or lower oil and natural gas prices could reduce the Company’s consolidated EBITDAX and thus could reduce the Company’s ability to maintain existing levels of bank debt or incur additional indebtedness. Any failure to be in compliance with any material provision or covenant of the Credit Facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under the Credit Facility.  Additionally, should the Company’s obligation to repay indebtedness under the Credit Facility be accelerated, the Company would be in default under the indentures governing the Convertible Senior Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such Convertible Senior Notes.  To the extent it becomes necessary to address any anticipated covenant compliance issues, the Company will seek to obtain a waiver or amendment of the Credit Facility from the Lenders, and in the event that such waiver or amendment is not granted, the Company may be required to sell a portion of its assets or issue additional securities, which would be dilutive to the Company’s shareholders.  Any sale of assets or issuance of additional securities may not be on terms acceptable to the Company.

 

As of December 31, 2010, the Company’s current and senior debt to EBITDAX ratios are 2.2:1.0 and 0.9:1.0, respectively, and the Company is in compliance with each of the covenants contained in the Credit Facility.

 

As of December 31, 2010, there are loans of $6,544,969 and letters of credit of $25,195 outstanding and our available credit was approximately $9.4 million.

 

**NOTE 9 — FAIR VALUE MEASUREMENTS**

 

The authoritative guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

 

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Level 1: Quoted prices are available in active markets for identical assets or liabilities;

 

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or

 

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

 

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s policy is to recognize transfers in/and or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below in all periods presented.

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2010 and 2009 by level within the fair value hierarchy:

 
| ** **                 | ** ** | **Fair Value Measurements Using** | ** ** |
|----------------------------|------------|--------------------------------------------------|------------|
| ** **                 | ** ** | **Level 1**                                 | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
| **December 31, 2010** |       |                                             |       |   |   |   |   |   |   |
| Assets                     |       |                                             |       |   |   |   |   |   |   |
| Commodity   derivatives    |       | $                                                | —     |   | $ | 193,959 |   | $ | — |   | $ | 193,959 |   |
|                       |       |                                             |       |   |   |   |   |   |   |
| Liabilities:               |       | $                                                | —     |   | $ | — |   | $ | — |   | $ | — |   |
|                       |       |                                             |       |   |   |   |   |   |   |
| **December 31, 2009** |       |                                             |       |   |   |   |   |   |   |
| Assets                     |       | $                                                | —     |   | $ | — |   | $ | — |   | $ | — |   |
|                       |       |                                             |       |   |   |   |   |   |   |
| Liabilities:               |       |                                             |       |   |   |   |   |   |   |
| Commodity   derivatives    |       | $                                                | —     |   | $ | (2,693,605 | ) | $ | — |   | $ | (2,693,605 | ) |

 

As of December 31, 2010, the Company’s commodity derivative financial instruments are comprised of three natural gas swap agreements. The fair values of the swap agreements are determined based primarily on inputs that are derived from observable data at commonly quoted intervals for the full term of the derivatives and are, therefore, considered level 2 in the fair value hierarchy. The Company determines the fair value of these swap contracts under the income valuation technique using a discounted cash flows model. The valuation models require a variety of inputs, including contractual terms, projected gas market prices, discount rate and credit risk adjustments, as appropriate. The Company has consistently applied this valuation technique in all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds. The counterparty in all of the Company’s commodity derivative financial instruments is the Administrative Agent under the Credit Agreement. See Note 8 “Credit Facility” herein.

 

From June 25, 2010 through September 15, 2010, the Company accounted for the embedded cash conversion features related to the 2015 Notes at fair value. The value of the this feature was derived based on both observable and unobservable pricing inputs and, therefore, the data sources utilized in this valuation model were considered level 3 inputs in the fair value hierarchy. The Company determined the fair value of this derivative under the income valuation technique using an option pricing model that 

 

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required inputs such as the trading price of the Company’s stock, time value, price volatility of the Company’s common stock and considerations of the Company’s credit risk. The Company believes it obtained and applied the most accurate information available for this type of derivative. On September 15, 2010, the Company received shareholder approval to issue stock rather than cash upon the conversion of the 2015 Notes. The receipt of shareholder approval resulted in the embedded derivative feature no longer requiring fair value accounting and the carrying value was reclassified to additional paid-in-capital. See Note 4 “Convertible Senior Notes” herein for discussion of embedded derivatives relating to convertible debt.

 

The following table sets forth a reconciliation of changes in the fair value of the embedded conversion feature classified as level 3 in the fair value hierarchy:

 
| Balance   as of January 1, 2010    |   | $           | — |   |
|-----------------------------------------|--------|-------------|--------|--------|
| Total   gains (realized or unrealized): |   |        |   |
| Included   in earnings                  |   | 6,840,392   |   |
| Issuances                               |   | (22,199,008 | )      |
| Settlements                             |   | 15,358,616  |   |
|                                    |   |        |   |
| Balance   as of December 31, 2010  |   | $           | — |   |

 

Other financial instruments not measured at fair value on a recurring basis include cash and cash equivalents, accounts receivable, note receivable, accounts payable, accrued liabilities, 2011 Notes, 2015 Notes and long-term debt. With the exception of the note receivable, 2011 Notes, 2015 Notes and long-term debt, the financial statement carrying amounts of these items approximate their fair values due to their short-term nature. The carrying amount of long-term debt approximates the fair value due to its floating rate structure. The carrying amount of the Company’s note receivable approximates fair value based on current interest rates for similar instruments. The estimated fair value of the 2015 Notes as of December 31, 2010 was $31,766,000 determined using a discounted cash flow and option pricing model. Estimated fair values for 2011 Notes of $312,000 and $40,218,750 as of December 31, 2010 and 2009, respectively, have been determined using market quotes and the Company’s recent purchase of $68,000 in aggregate principal of its 2011 Notes.

 

**NOTE 10 - STOCKHOLDERS’ EQUITY (DEFICIT)**

 

The Company’s capital stock as of December 31, 2010 consists of 300,000,000 authorized shares of common stock, par value $0.0001 per share, 20,000 authorized shares of Series B Convertible Preferred stock, par value $0.001 per share and 2,000,000 authorized shares of Series C Convertible Preferred stock.

 

***Series B Convertible Preferred Stock***

 

As of December 31, 2010 and 2009, Gasco had no shares of Series B Preferred Stock issued and outstanding.

 

***Series C Convertible Preferred Stock***

 

During June 2010, in connection with the Exchange Transaction, the Company created and authorized out of the authorized but unissued shares of the capital stock of the Company, 2,000,000 shares of Series C Convertible Preferred Stock (“Preferred Stock”). The Preferred Stock is entitled to receive cash dividends and other distributions declared on the common stock, as well as distributions upon liquidation,

 

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dissolution or any other winding up event, in each case as set forth in the Certificate of Designations. The Preferred Stock does not have any right or power to vote on any question or in any proceeding or to be represented at or to receive notice of any meeting of holders of capital stock of the Company, except as required by law. The Preferred Stock may not be redeemed by the Company at any time.

 

Each share of Preferred Stock is convertible at the option of the holder thereof, at any time, into the number of fully paid and nonassessable shares of common stock equal to the quotient of (1) one hundred dollars ($100.00) divided by (ii) the conversion price applicable to shares of common stock as determined pursuant to the Indenture and in effect at the time of conversion (and any fractional shares will be paid in cash). As for the 2015 Notes, a holder may not convert all or any portion of such holder’s Preferred Stock into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion beneficially own more than the Maximum Ownership Percentage (as defined in the Indenture governing the 2015 Notes).

 

On September 20, 2010, the Company effected the automatic conversion of $19,364,000 of the outstanding principal amount of the 2015 Notes into 305,754 shares of Preferred Stock which were convertible into 50,959,010 shares of common stock. During the fourth quarter of 2010, 80,154 shares of Preferred Stock were converted into 13,359,001 shares of common stock and as of December 31, 2010, 225,600 shares of Preferred Stock are issued and outstanding which are convertible into 37,600,007 shares of common stock.

 

During January 2011, 34,600 shares of Preferred Stock were converted into 5,766,667 shares of common stock.

 

***Common Stock***

 

Gasco has 121,255,748 shares of common stock issued and outstanding and 73,700 shares held in treasury as of December 31, 2010. The common shareholders are entitled to one vote per share on all matters to be voted on by the shareholders; however, there are no cumulative voting rights. The common shareholders are entitled to dividends and other distributions as may be declared by the board of directors. Upon liquidation or dissolution, the common shareholders will be entitled to share ratably in the distribution of all assets remaining available for distribution after satisfaction of all liabilities and payment of the liquidation preference of any outstanding preferred stock.

 

As of December 31, 2010, we had 12,689,733 shares of common stock issuable upon exercise of outstanding options and an additional 197,450 shares of common stock are issuable under our restricted stock plan.

 

As of December 31, 2010, assuming all of the Convertible Notes are converted at the applicable conversion prices, and all of the Preferred Stock is converted, the number of shares of our common stock outstanding would increase by approximately 112,980,007 shares of common stock resulting in an increase in the outstanding shares as December 31, 2010 to approximately 234,162,055 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).

 

The Company’s common stock equity transactions during 2010 and 2009 are described as follows:

 

During the fourth quarter of 2010, 80,154 shares of Preferred Stock were converted into 13,359,001 shares of common stock.

 

During the years ended December 31, 2010 and 2009, the Company’s Board of Directors approved the issuance of 150,000 and 7,500 shares of common stock, respectively, under the Gasco Energy, Inc.

 

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Amended and Restated 2003 Restricted Stock Plan, (“Restricted Stock Plan”) to certain of the Company’s employees. The restricted shares vest at varying schedules within three to five years. The shares fully vest upon certain events, such as a change in control of the Company, expiration of the individual’s employment agreement and termination by the Company of the individual’s employment without cause.  Any unvested shares are forfeited upon termination of employment for any other reason. The compensation expense related to the restricted stock was measured on the issuance date using the trading price of the Company’s common stock on that date and is amortized over the vesting period. The shares of restricted stock are considered issued and outstanding at the date of grant and are included in shares outstanding upon vesting for the purposes of computing diluted earnings per share. During 2010 and 2009, 11,701 and 6,301 shares of the Company’s common stock were cancelled in satisfaction of the income tax liability of $4,212 and $3,566, respectively, associated with the vesting of restricted stock.

 

**NOTE 11 - STATEMENTS OF CASH FLOWS**

 

During the year ended December 31, 2010, the Company’s non-cash investing and financing activities consisted of the following transactions:

 

·                  Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $2,100.

 

·                  Stock-based reduction in compensation expense of $1,370 capitalized as proved property.

 

·                  Additions to oil and gas properties included in accounts payable of $(184,014).

 

·                  Recognition of deferred income of $3,036,791 in connection with Asset Sale described in Note 3 “Asset Sales and Purchases” herein.

 

·                  Exchange of 2011 Notes for 2015 Notes of $64,532,000 described in Note 4 “Convertible Senior Notes” herein.

 

·                  Exchange of $19,364,000 of the principal value of the 2015 Notes was converted into 305,754 shares of Preferred Stock and debt derivative liabilities of $15,358,616 were reclassified to Additional Paid-in Capital as described in Note 4 “Convertible Senior Notes” herein.

 

·                  Conversion of 80,154 shares of Preferred Stock into 13,359,001 shares of common stock.

 

·                  Cancellation of 11,701 shares of common stock in satisfaction of income taxes of $4,212 related to the vesting of restricted stock.

 

·                  Write-off of fully depreciated furniture and fixtures of $109,912.

 

During the year ended December 31, 2009, the Company’s non-cash investing and financing activities consisted of the following transactions:

 

·                  Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $830.

 

·                  Stock-based compensation expense of $7,110 capitalized as proved property.

 

·                  Additions to oil and gas properties included in accounts payable of $3,087,746.

 

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·                  Sale of assets for a note receivable of $500,000.

 

·                  Cancellation of 6,301 shares of common stock in satisfaction of income taxes of $3,566 related to the vesting of restricted stock.

 

·                  Write-off of fully depreciated furniture and fixtures of $43,786.

 

During the year ended December 31, 2008, the Company’s non-cash investing and financing activities consisted of the following transactions:

 

·                  Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $52,430. Reduction in asset retirement obligation of $11,107 due to property dispositions. Increase in asset retirement obligation of $2,526 due to revisions representing our periodic reassessment of the expected cash flows and assumptions inherent in the calculation of the asset retirement liability.

 

·                  Stock-based compensation of $31,026 capitalized as proved property.

 

·                  Additions to oil and gas properties included in accounts payable of $3,157,809.

 

·                  Cancellation of 11,521 shares of common stock in satisfaction of income taxes of $18,036 related to the vesting of restricted stock.

 

Cash paid for interest during the years ended December 31, 2010, 2009 and 2008 was $4,095,566, $5,356,086, and $4,287,996, respectively. There was no cash paid for income taxes during the years ended December 31, 2010, 2009 and 2008.

 

**NOTE 12 — INCOME TAXES**

 

The provision (benefit) for income taxes for the years ended December 31, 2010, 2009 and 2008 consists of the following:

 
| ** **                         | ** ** | **2010**    | ** ** | **2009**   | ** **  | **2008**   | ** ** |
|------------------------------------|------------|-------------|------------|------------|-------------|------------|------------|
| Current taxes:                     |       |        |       |       |        |       |       |
| Federal                            |       | $           | —     |       | $           | —     |       | $ | — |   |
| State                              |       | —      |       | —     |        | —     |       |
| Deferred taxes:                    |       |        |       |       |        |       |       |
| Deferred provision (benefit)       |       | $           | 12,151,778 |       | (20,159,066 | )          | 6,261,035  |   |
| Less: valuation allowance          |       | (12,151,778 | )          | 20,159,066 |        | (6,261,035 | )          |
| Net income tax provision (benefit) |       | $           | —     |       | $           | —     |       | $ | — |   |

 

A reconciliation of the provision (benefit) for income taxes computed at the statutory rate to the provision for income taxes as shown in the financial statements of operations for the years ended December 31, 2010, 2009 and 2008 is summarized below:

 

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| ** **                                        | ** ** | **2010**  | ** **  | **2009**   | ** ** | **2008**    | ** ** |
|---------------------------------------------------|------------|-----------|-------------|------------|------------|-------------|------------|
|                                              |       |      |        |       |       |        |       |
| Tax provision (benefit) at federal statutory rate |       | $         | 3,544,457   |       | $          | (17,565,860 | )          | $ | 5,079,881 |   |
| State taxes, net of federal tax effects           |       | 2,573,856 |        | (2,330,215 | )          | 320,637     |       |
| Change in Tax Rate from Prior Year                |       | 25,267    |        | 400,528    |       | 185,057     |       |
| Permanent items and other                         |       | 6,008,198 |        | (663,519   | )          | 675,460     |       |
| Valuation allowance                               |       | $         | (12,151,778 | )          | 20,159,066 |        | (6,261,035 | ) |
| Net income tax provision (benefit)                |       | $         | —      |       | $          | —      |       | $ | — |   |

 

The components of the deferred tax assets and liabilities as of December 31, 2010 and 2009 are as follows:

 
| ** **                                                            | ** ** | **2010**    | ** ** | **2009**    | ** ** |
|-----------------------------------------------------------------------|------------|-------------|------------|-------------|------------|
| Deferred   tax assets:                                                |       |        |       |        |       |
| Federal and state net operating loss carryovers                       |       | $           | 74,201,528 |        | $          | 69,245,987 |   |
|                                                                  |       |        |       |        |       |
| Oil and gas property and Other Property,   plant & equipment |       | 4,576,664   |       | 13,372,424  |       |
| Deferred rent                                                         |       | —      |       | 7,869       |       |
| Deferred compensation                                                 |       | 2,704,433   |       | 2,558,358   |       |
| Deferred gain on sale of assets                                       |       | 1,079,194   |       | —      |       |
| Accrued Salaries and Bonus                                            |       | 216,359     |       | 92,265      |       |
| Asset Retirement Obligation                                           |       | 421,265     |       | 482,751     |       |
| Derivatives                                                           |       | —      |       | 1,031,226   |       |
| Other                                                                 |       | 198,910     |       | 177,578     |       |
| Total deferred tax assets                                             |       | 83,398,353  |       | 86,968,454  |       |
| Less: valuation allowance                                             |       | (74,816,676 | )          | (86,968,454 | )          |
|                                                                  |       | 8,581,677   |       | —      |       |
| Deferred tax liabilities:                                             |       |        |       |        |       |
| Derivatives                                                           |       | 72,982      |       | —      |       |
| Deferred COD Income                                                   |       | 8,508,695   |       | —      |       |
| Total deferred tax liabilities                                        |       | $           | 8,581,677  |        | —     |   |
|                                                                  |       |        |       |        |       |
| Net deferred tax asset                                                |       | $           | —     |        | $          | — |   |

 

The Company has $202,095,926 of net operating loss carryover for federal income tax purposes as of December 31, 2010, of which $4,224,569 is not benefited for financial statement purposes as it relates to tax deductions that deviate from compensation expense for financial statement purposes. The benefit of these excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce taxes payable.  The Company has $158,638,969 of net operating loss carryover for state income tax purposes as of December 31, 2010, of which the above excess tax deductions have similarly not been benefited for financial statement purposes. The net operating losses may offset against taxable income through the year ended December 31, 2030. A portion of the net operating loss carryovers begins expiring in 2019.  The Company is in the process of analyzing the implications of a possible ownership change for purposes of IRC Section 382 on its gross deferred tax asset for net operating losses as reported in its financial statements and will make appropriate adjustments when this analysis is finalized.  Such adjustments would have no impact on the financial statements as the Company’s deferred tax assets net of liabilities are subject to a full valuation allowance.  The Company provided a valuation allowance against its net deferred tax asset of $74,816,676 and $86,968,454 as of December 31, 2010 and 2009, respectively,

 

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since it believes that it is more likely than not that the net deferred tax assets will not be fully realized on future income tax returns. The decrease and increase in the valuation allowance for 2010 and 2009 is $(12,151,778) and $20,159,066, respectively.

 

**NOTE 13 — RELATED PARTY TRANSACTIONS**

 

Certain of the Company’s directors and officers have working and/or overriding royalty interests in oil and gas properties in which the Company has an interest.  It is expected that the directors and officers may participate with the Company in future projects. All participation by directors and officers will continue to be approved by the disinterested members of the Company’s Board of Directors.

 

**NOTE 14 - COMMITMENTS**

 

The Company leases approximately 11,840 square feet of office space in Englewood, Colorado, under a lease, which terminates on May 31, 2012. The Company’s future rental payments due under this lease are $129,287 and $43,459 which will be due during 2011 and 2012, respectively. After May 31, 2012, the Company has the option to continue its lease on a month-to-month basis at the current rates.

 

Rent expense for the years ended December 31, 2010, 2009 and 2008 was $166,334, $187,335 and $137,512, respectively.

 

As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells.  If the Company does not pay such commitments, the acreage positions or wells may be lost.

 

On February 8, 2011, the Company entered into new employment agreements with its two key officers, which replace in their entirety the employment agreements previously in effect. Total minimum compensation under the agreements is $590,000 per annum and the initial terms of the agreements will expire on the second anniversary of the effective date and will automatically renew for additional one-year terms unless either party elects not to renew or the agreements is otherwise terminated in accordance with its terms. The agreements contain clauses regarding termination of the officer that would require payment of an amount ranging from 1.5 to two times annual compensation.

 

In January 2010, in connection with the resignation of President and CEO, the Company terminated his employment agreement and entered into a consulting agreement under which the Company made payments to him totaling $825,000 during the year ended December 31, 2010 and will pay another $325,000 to him on March 1, 2011. Additionally, all of his outstanding options to purchase common stock became vested in January 2010. As a result of the acceleration of the vesting of his options, the Company recognized approximately $132,000 in additional stock compensation expense during the first quarter of 2010.

 

During March 2010, per the Base Contract for Sale and Purchase of Natural Gas that the Company has with Anadarko Energy Services Company, dated December 1, 2007, the Company entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of its gross production through 2013 from the Uinta Basin.  The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price.

 

As discussed in Note 2 “Significant Accounting Policies” herein, we have entered into derivative contracts relating to a portion of our natural gas production for 2011 and through December 2012.

 

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** **

**NOTE 15 - EMPLOYEE BENEFIT PLANS**

 

The Company adopted a 401(k) profit sharing plan (the “Plan”) in October 2001, available to employees who meet the Plan’s eligibility requirements.  The Plan is a defined contribution plan.  The Company may make discretionary contributions to the Plan and is required to contribute 3% of each participating employee’s compensation to the Plan.  The contributions made by the Company totaled $127,169, $116,595 and $150,617 during the years ended December 31, 2010, 2009 and 2008, respectively.

 

**NOTE 16 — SELECTED QUARTERLY INFORMATION (Unaudited)**

 

The following represents selected quarterly financial information for the years ended December 31, 2010 and 2009. During the fourth quarter of 2009, the Company was actively engaged in marketing for sale its gathering assets and water disposal facilities. In February 2010, the Company entered into an asset purchase agreement to sell its gathering assets and water disposal facilities as further described in Note 3 “Asset Sales and Acquisitions” herein. The reduction in net revenue from oil and gas operations during the last three quarters of 2010 reflects the elimination of the revenue and expenses associated with the Company’s gathering operations and includes the transportation and processing that is now paid to a third party.

 
| **2010**                                | ** ** | **For the Quarter Ended** | ** ** |
|-----------------------------------------|------------|------------------------------------------|------------|
| ** **                              | ** ** | **March 31,**                       | ** ** | **June 30,** | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
|                                    |       |                                     |       |   |   |   |   |   |   |
| Gross revenue                           |       | $                                        | 6,381,535  |   | $ | 4,944,891 |   | $ | 4,701,687 |   | $ | 4,233,986 |   |
| Net revenue from oil and gas operations |       | 4,824,244                                |       | 2,531,146 |   | 2,477,352 |   | 1,027,945 |   |
| Net income (loss)(a)                    |       | 2,882,248                                |       | 15,379,806 |   | (5,344,098 | ) | (2,790,936 | ) |
| Net income (loss) per share             |       |                                     |       |   |   |   |   |   |   |
| Basic and diluted                       |       | 0.03                                     |       | 0.14 |   | (0.05 | ) | (0.01 | ) |
|                                         |            |                                          |            |  |  |  |  |  |  |  |  |  |  |

 

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(a)          Net income during second quarter of 2010 includes a $15,758,011 gain on extinguishment of debt and the net loss during the third and fourth quarters of 2010 include the amortization of the debt discount in connection with the Exchange Transaction as further described in Note 4 “Senior Convertible Notes”, herein.

 
| **2009**                                | ** ** | **For the Quarter Ended** | ** ** |
|-----------------------------------------|------------|------------------------------------------|------------|
| ** **                              | ** ** | **March 31,**                       | ** ** | **June 30,** | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
|                                    |       |                                     |       |   |   |   |   |   |   |
| Gross revenue                           |       | $                                        | 5,413,622  |   | $ | 4,412,313 |   | $ | 4,437,856 |   | $ | 6,825,248 |   |
| Net revenue from oil and gas operations |       | 3,480,085                                |       | 2,358,335 |   | 2,668,067 |   | 2,859,943 |   |
| Net income (loss) (b)(c)                |       | (43,865,246                              | )          | (3,859,634 | ) | (2,906,729 | ) | 443,438 |   |
| Net income (loss) per share             |       |                                     |       |   |   |   |   |   |   |
| Basic and diluted                       |       | (0.41                                    | )          | (0.04 | ) | (0.03 | ) | 0.00 |   |
|                                         |            |                                          |            |  |  |  |  |  |  |  |  |  |  |

 

----

(b)          The net loss for the first quarter of 2009 includes a $41,000,000 property impairment related to the Company’s oil and gas properties as further discussed in Note 2 “Significant Accounting Policies” herein.

 

(c)           As discussed in Note 2 “Significant Accounting Policies” — Recent Accounting Pronouncements, effective December 31, 2009, the Company changed its method of determining the quantities of

 

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oil and gas reserves which affected the amount of depreciation,depletion and amortization and the ceiling test calculation for oil and gas properties in the fourth quarter of 2009.

 

**NOTE 17— LEGAL PROCEEDINGS**

 

The Company is party to various litigation matters arising out of the normal course of business.  The more significant litigation matters are summarized below.  The ultimate outcome of these matters cannot presently be determined, nor can the liability that could potentially result from an adverse outcome be reasonably estimated at this time.  The Company does not expect that the outcome of these proceedings will have a material adverse effect on its financial position, results of operations or cash flows.

 

**EPA Enforcement Action**

 

In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), a wholly-owned subsidiary of the Company, who was preparing air emission calculations for possible future capacity expansions, preliminarily determined that Riverbend may have not accurately calculated the amount of air pollutants that could be emitted from certain existing equipment at its Riverbend Compressor Station in Uintah County, Utah.  Riverbend thereafter undertook a more detailed assessment, which confirmed that Riverbend had not obtained certain air permits nor complied with certain air pollution regulatory programs that were applicable to its operations at the Riverbend Compressor Station.  On June 22, 2007, Riverbend sent a letter to the United States Environmental Protection Agency (“EPA”) Region 8 office in Denver, Colorado, which—because the Riverbend Compressor Station is located in Indian Country—is the agency that has jurisdiction over federal air permitting and air pollution regulatory programs.  Riverbend’s June 22 letter voluntarily disclosed the potential violations to EPA and informed the agency of the steps that Riverbend had taken and planned to take to achieve compliance.  In November 2007, Riverbend met with EPA Region 8 personnel and discussed the disclosed violations, its plans to bring the Riverbend Compressor Station into compliance, and possible resolution of the disclosed violations.   These discussions culminated in the negotiation of a consent decree that was signed by the parties and lodged in the United States District Court of the District of Utah on December 30, 2010.  The consent  resolves the apparent violations, requires Gasco to pay a civil penalty of $350,000, which has been accrued in the accompanying financial statements, specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that will authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented.  The consent decree is awaiting entry by the court.

 

Under the Purchase Agreement dated January 29, 2010 by which we sold our gathering system and its evaporative facilities located in Uintah County, Utah to Monarch, we retained the obligation to pay any civil penalty assessed and the capital cost of the equipment required to be installed pursuant to the consent decree, and we also agreed to reimburse Monarch for certain miscellaneous expenses incurred to finalize the consent decree and obtain certain changes to the Riverbend Compressor Station’s air permits that are required by the consent decree.  Monarch is also a party to the consent decree and will be responsible for implementing most of the consent decree requirements at the Riverbend Compressor Station other than the payment of a civil penalty and the installation of capital equipment.  We believe that all necessary pollution control and other equipment required by the consent decree is already installed at the site or accounted for in our capital budget, and that the civil penalty and the other expenses required by the consent decree will not materially affect our financial position or liquidity.

 

**Sweeney Litigation**

 

On December 5, 2008, a lawsuit was filed in state court in Cook County, Illinois (“Sweeney litigation”) by eleven individual plaintiffs and Griffin Asset Management, LLC.  The lawsuit alleges that defendants

 

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Richard N. Jeffs (“Jeffs), Marc Bruner (“Bruner”) and the Company through its agency with Bruner, made misrepresentations, committed fraud, aided and abetted a scheme to defraud, and conspired to defraud in connection with the plaintiffs’ investment in Brek Energy Corporation (“Brek”).  The complaint alleged that plaintiffs’ relied on various misrepresentations and omissions by the individual defendants when making the decision to invest in Brek, which merged into the Company in December of 2007.  Plaintiffs sought unspecified damages in an amount in excess of $50,000, punitive damages, attorneys’ fees, and costs.  The Company removed the case to the United States District Court for the Northern District of Illinois, Eastern Division, on January 7, 2009 and answered the complaint, denying all liability, on February 13, 2009. A scheduling conference was held on April 1, 2009.  The judge ordered fact discovery in the case to be completed by December 15, 2009 and set the trial for June 7, 2010.  Following the scheduling conference, Jeffs was served with the complaint and filed a motion to dismiss all counts against him on the grounds that certain claims are barred by limitations, that plaintiffs lack standing to bring other claims, and that plaintiffs have failed to join an indispensable party (Brek).

 

During the fall of 2009, the parties began to engage in the early stages of discovery and numerous depositions were scheduled for late November and the first half of December 2009.  Prior to the start of depositions, however, on November 25, 2009, the parties reached an agreement in principle to settle the claims made against the Company and Bruner in the Sweeney litigation.

 

On December 4, 2009, while counsel for the Company was documenting the partial settlement, counsel for Jeffs sent a letter to the Company demanding that the Company (1) reimburse Jeffs for his defense costs to date in the Sweeney litigation; and (2) indemnify Jeffs for any judgment entered (or settlement made) in the Sweeney litigation.  Jeffs’ counsel claimed that Jeffs was entitled to such reimbursement and indemnification under the bylaws of Brek Energy Corporation that were in effect at the time of Brek’s merger into a wholly-owned subsidiary of the Company.

 

On December 9, 2009, Jeffs also filed an action in Colorado federal district court to obtain a declaration that the 550,000 shares of the Company’s stock being held in escrow under an agreement between the Company and Jeffs belong to, and should be released to, Jeffs pursuant to the terms of the escrow agreement (“Jeffs litigation”).

 

On or around December 18, counsel for the Company, Bruner, Jeffs, and plaintiffs reached an agreement in principle to settle all claims in both the Sweeney litigation and the Jeffs litigation.  This global settlement was documented and finalized in February 2010.

 

On February 5, 2010, counsel for the Company, Bruner, Jeffs, and plaintiffs filed an Agreed Motion for Dismissal with Prejudice of the Sweeney litigation.  On February 9, 2010, the United States District Court for the Northern District of Illinois, Eastern Division entered a docket entry granting the parties’ Agreed Motion and dismissing the Sweeney litigation with prejudice.  On February 10, 2010, a settlement payment was made to the Sweeney plaintiffs in connection with this dismissal with prejudice. On February 16, 2010, counsel for Gasco and Jeffs filed an Agreed Motion for Dismissal with Prejudice of the**Jeffs litigation.  On February 17, 2010, the United States District Court for the District of Colorado entered an Order of Dismissal with Prejudice.  A settlement payment, which was accrued in the accompanying financial statements as of December 31, 2009, was made on February 17, 2010, following this dismissal with prejudice. The Company received a partial reimbursement from its insurance provider related to this matter during the second quarter of 2010.

** **

**NOTE 18 — GUARANTOR SUBSIDIARIES**

 

On August 22, 2008, Gasco filed a Form S-3 shelf registration statement with the SEC. Under this registration statement, which was declared effective on September 8, 2008, Gasco may from time to time

 

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offer and sell securities including common stock, preferred stock, depositary shares and debt securities that may be fully, irrevocably and unconditionally guaranteed by all of its subsidiaries:  Gasco Production Company, Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (collectively, the “Guarantor Subsidiaries”). The stand-alone parent entity, Gasco Energy, Inc., has insignificant independent assets and no operations. Therefore, supplemental financial information on a condensed consolidating basis of the Guarantor Subsidiaries is not required. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries, except those imposed by applicable law.

 

**NOTE 19** — **SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)**

 

The following reserve quantity and future net cash flow information for the Company represents estimated proved reserves located in the United States. The reserves as of December 31, 2010, 2009 and 2008 have been estimated by Netherland, Sewell and Associates, Inc., independent petroleum engineers. The determination of oil and gas reserves is based on estimates, which are highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available.

 

The standardized measure of discounted future net cash flows is prepared under the guidelines set forth by the Securities and Exchange Commission (SEC). Prior to December 31, 2009, this calculation was performed using year-end oil and gas prices. Effective December 31, 2009, the SEC issued new guidance requiring the use of the average, first-of-the-month price rather than the prices on the last day of the year. The oil and gas prices weighted by production over the lives of the proved reserves used as of December 31, 2010, 2009 and 2008 were $64.97 per bbl of oil and $3.62 per Mcf of gas, $44.46 per bbl of oil and $2.85 per Mcf of gas and $15.34 per bbl of oil and $4.63 per Mcf of gas, respectively. Future production costs are based on year-end costs and include severance taxes. Each property that is operated by the Company is also charged with field-level overhead in the reserve calculation. The present value of future cash inflows is based on a 10% discount rate. The Company does not believe that provisions of the new rules, other than pricing, significantly impacted the reserve estimates in 2009. The Company does not believe that it is practicable to estimate the effect of applying the new rules on the following tables for reserve quantities or standardized measure of discounted cash flows for the year ended December 31, 2009.

 

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**Reserve Quantities**

 
| ** **                            | ** ** | **Gas**     | ** ** | **Oil**    | ** ** |
|---------------------------------------|------------|-------------|------------|------------|------------|
| ** **                            | ** ** | **Mcf**     | ** ** | **Bbls**   | ** ** |
| **Proved Reserves:**                  | ** ** | ** **  | ** ** | ** ** | ** ** |
| ** **                            | ** ** | ** **  | ** ** | ** ** | ** ** |
| Balance,   December 31, 2007     |       | 104,338,338 |       | 1,070,802  |       |
| Extensions   and discoveries          |       | 2,400,000   |       | 17,000     |       |
| Revisions   of previous estimates (a) |       | (42,740,002 | )          | (646,072   | )          |
| Sales   of reserves in place          |       | (8,506,000  | )          | (38,000    | )          |
| Purchases   of reserves in place      |       | —      |       | —     |       |
| Production                            |       | (4,583,028  | )          | (42,545    | )          |
|                                  |       |        |       |       |       |
| Balance,   December 31, 2008     |       | 50,909,308  |       | 361,185    |       |
| Extensions   and discoveries          |       | 1,384,000   |       | 8,000      |       |
| Revisions   of previous estimates (b) |       | (3,788,509  | )          | 123,824    |       |
| Sales   of reserves in place          |       | —      |       | —     |       |
| Purchases   of reserves in place      |       | —      |       | —     |       |
| Production                            |       | (4,274,849  | )          | (42,151    | )          |
|                                  |       |        |       |       |       |
| Balance,   December 31, 2009     |       | 44,229,950  |       | 450,858    |       |
| Extensions   and discoveries          |       | —      |       | —     |       |
| Revisions   of previous estimates (c) |       | 632,807     |       | 68,912     |       |
| Sales   of reserves in place          |       | (2,213,000  | )          | (19,000    | )          |
| Purchases   of reserves in place      |       | 1,181,442   |       | 4,421      |       |
| Production                            |       | (4,105,139  | )          | (40,532    | )          |
|                                  |       |        |       |       |       |
| Balance,   December 31, 2010     |       | 39,726,060  |       | 464,659    |       |

 
| ** **                        | ** ** | **Gas**    | ** ** | **Oil**  | ** ** |
|-----------------------------------|------------|------------|------------|----------|------------|
| ** **                        | ** ** | **Mcf**    | ** ** | **Bbls** | ** ** |
|                              |       |       |       |     |       |
| **Proved Developed Reserves**     |       |       |       |     |       |
| Balance,   December 31, 2010 |       | 39,726,060 |       | 464,659  |       |
| Balance,   December 31, 2009 |       | 44,229,950 |       | 450,858  |       |
| Balance,   December 31, 2008 |       | 50,909,308 |       | 361,185  |       |

 

----

(a)          The majority of the revisions of previous estimates during 2008 were primarily due to the decrease in oil and gas prices from $73.95 per barrel and $6.53 per Mcf at December 31, 2007 to $15.34 per barrel and $4.63 per Mcf at December 31, 2008.

 

(b)         The majority of the revisions of previous estimates during 2009 were primarily due to a decrease in the gas price used in the reserve report estimates from $4.63 per Mcf at December 31, 2008 to $2.85 per Mcf at December 31, 2009 and an increase in oil prices from $15.34 per barrel at December 31, 2008 to $44.46 per barrel at December 31, 2009.

 

(c)          Better than anticipated existing well performances yielded positive reserve revisions during the year ended December 31, 2010.

 

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**Standardized Measure of Discounted Future Net Cash Flows**

** **
| ** **                                                 | ** ** | **December 31,** | ** **  |
|------------------------------------------------------------|------------|-----------------------|-------------|
| ** **                                                 | ** ** | **2010**              | ** **  | **2009** | ** ** | **2008** | ** ** |
|                                                       |       |                  |        |   |   |   |   |
| Future   cash flows                                        |       | $                     | 173,982,700 |   | $ | 146,019,900 |   | $ | 241,343,700 |   |
| Future   production and development costs                  |       | (91,157,000           | )           | (79,555,800 | ) | (108,727,900 | ) |
| Future   income taxes (a)                                  |       | —                |        | — |   | — |   |
| Future   net cash flows before discount                    |       | 82,825,700            |        | 66,464,100 |   | 132,615,800 |   |
| 10%   discount to present value                            |       | (35,898,700           | )           | (30,902,700 | ) | (63,133,000 | ) |
| Standardized   measure of discounted future net cash flows |       | $                     | 46,927,000  |   | $ | 35,561,400 |   | $ | 69,482,800 |   |

 

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(a)          The calculations of standardized measure do not include deductions for future income tax expenses because the tax basis of the properties involved and the future tax deductions were greater than the net cash flows from the from the proved oil and gas reserves for the years ended December 31, 2010, 2009 and 2008.

 

**Changes in the Standardized Measure of Discounted Future Net Cash Flows**

** **
| ** **                                                                          | ** ** | **For the Years Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                          | ** ** | **2010**                                                      | ** ** | **2009** | ** ** | **2008** | ** ** |
| Standardized   measure of discounted future net cash flows at the beginning of year |       | $                                                             | 35,561,400 |   | $ | 69,482,800 |   | $ | 160,464,000 |   |
| Sales   of oil and gas produced, net of production costs                            |       | (13,643,312                                                   | )          | (11,366,430 | ) | (28,981,134 | ) |
| Net   changes in prices and production costs                                        |       | 12,137,633                                                    |       | (26,354,834 | ) | (34,529,372 | ) |
| Extensions   and discoveries, net of future production and development costs        |       | —                                                        |       | 920,185 |   | 2,311,000 |   |
| Previously   estimated development costs incurred                                   |       | 4,411,807                                                     |       | 1,703,282 |   | 5,393,989 |   |
| Changes   in estimated future development costs                                     |       | 2,556,404                                                     |       | 65,560 |   | (2,981,737 | ) |
| Revisions   of previous quantity estimates                                          |       | 1,154,884                                                     |       | (2,259,462 | ) | (44,761,342 | ) |
| Purchases   of reserves in place                                                    |       | 2,228,917                                                     |       | — |   | — |   |
| Sales   of reserves in place                                                        |       | (1,663,100                                                    | )          | — |   | (7,703,000 | ) |
| Net   change in income taxes                                                        |       | —                                                        |       | — |   | 1,378,483 |   |
| Accretion   of discount                                                             |       | 3,398,429                                                     |       | 5,633,959 |   | 17,711,306 |   |
| Other                                                                               |       | 783,938                                                       |       | (2,263,660 | ) | 1,180,607 |   |
| Standardized   measure of discounted future net cash flows at the end of year       |       | $                                                             | 46,927,000 |   | $ | 35,561,400 |   | $ | 69,482,800 |   |

 

**NOTE 20 - SUBSEQUENT EVENTS**

 

***Resignation of Former Chief Executive Officer; Appointment of Replacement***

 

Effective January 1, 2011, the Company’s previously announced plan of succession for changes in management was completed.  Charles B. Crowell resigned as the Company’s interim Chief Executive Officer and was replaced by W. King Grant, the Company’s current President and Chief Financial Officer.  At that time, Mr. Grant resigned as Chief Financial Officer. Mr. Crowell maintains his position as Chairman of the Board of Directors of the Company; Mr. Grant also serves as a member of the Board of Directors.

 

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** **

**ITEM 9 –****CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE**

 

None.

 

**ITEM****9A – CONTROLS AND PROCEDURES**

 

**Disclosure Controls and Procedures**

 

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive and principal financial officers or persons performing similar functions, as appropriate to allow such persons to make timely decisions regarding required disclosures.

 

Based upon the results of our evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2010.

 

**Changes in Internal Controls over Financial Reporting during the Fourth Quarter of 2009**

 

There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated by the SEC under the Securities Exchange Act of 1934) during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

In accordance with Item 308 of SEC Regulation S-K, management is required to provide an annual report regarding internal controls over our financial reporting. This report, which includes management’s assessment of the effectiveness of our internal controls over financial reporting, is found below.

 

***Management’s Report on Internal Control Over Financial Reporting***

 

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed, under the supervision of the Company’s chief executive and chief financial officers, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (GAAP). The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

 

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

 

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

 

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

 

The effectiveness of internal control over financial reporting as of December 31, 2010, was audited by KPMG LLP, the independent registered public accounting firm who audited our financial statements for the year ended December 31, 2010, as stated in its report that follows.

 

Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934 this Annual Report on Internal Control Over Financial Reporting has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on March 2, 2011.

 
|   | /s/   W. King Grant                                  |
|--------|------------------------------------------------------|
|   | W.   King Grant                                      |
|   | Chief   Executive Officer & President       |
|   | (Principal   Executive Officer)                      |
|   |                                                 |
|   | /s/   Peggy A. Herald                                |
|   | Peggy   A. Herald                                    |
|   | Vice   President & Chief Accounting Officer |
|   | (Principal   Financial Officer)                      |

 

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**Report of Independent Registered Public Accounting Firm**

 

 

The Board of Directors and Stockholders

Gasco Energy, Inc.:

 

We have audited Gasco Energy, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2010, based on criteria established in*Internal Control — Integrated Framework* issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying *Management’s Report on Internal Control over Financial Reporting*. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

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

 

In our opinion, Gasco Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in *Internal Control — Integrated Framework* issued by the COSO.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gasco Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the each of the years in the three-year period ended December 31, 2010, and our report dated March 2, 2011 expressed an unqualified opinion on those consolidated financial statements.

 

KPMG LLP

 

Denver, Colorado March 2, 2011

 

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** **

**ITEM 9B – OTHER INFORMATION**

 

None.

 

**PART III**

 

**ITEM 10 – DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE**

 

The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2011 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

 

**ITEM 11 – EXECUTIVE COMPENSATION**

 

The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2011 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

 

**ITEM****12 – SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND****MANAGEMENT AND RELATED STOCKHOLDER MATTERS**

 

The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2011 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

 

**ITEM****13****–****CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE**

 

The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2011 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

 

**ITEM 14 – PRINCIPAL ACCOUNTING FEES AND SERVICES**

 

The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2011 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

 

**ITEM 15 – EXHIBITS, FINANCIAL STATEMENT SCHEDULES**

 

The following is a list of exhibits filed or furnished (as indicated) as part of this 10-K. Where so noted, exhibits which were previously filed are incorporated herein by reference.

 

(a)        1. See “Index to Financial Statements” under Item 8 on page 79.

2. Financial Statement Schedules — none.

3. Exhibits — See Index to Exhibits, below.

 

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**INDEX TO EXHIBITS**

 

 
| 3.1 |   | Amended   and Restated Articles of Incorporation (incorporated herein by reference to   Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999,   filed on January 21, 2000, File No. 000-26321).                                                                                                                                                              |
|-----|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.2 |   | Certificate   of Amendment to Articles of Incorporation (incorporated herein by reference   to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31,   2001, filed on February 16, 2001, File No. 000-26321).                                                                                                                                                     |
| 3.3 |   | Certificate   of Amendment to Articles of Incorporation dated June 21, 2005   (incorporated herein by reference to Exhibit 3.3 to the Company’s   Form 10-Q/A for the quarter ended June 30, 2005, filed on   August 9, 2005, File No. 001-32369).                                                                                                               |
| 3.4 |   | Certificate   of Amendment to Articles of Incorporation dated September 20, 2010   (incorporated herein by reference to Exhibit 3.1 to the Company’s   Form 8-K dated September 20, 2010, filed on September 20,   2010, File No. 001-32369).                                                                                                                    |
| 3.5 |   | Second   Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8,   2009 (incorporated herein by reference to Exhibit 3.1 to the Company’s   Form 8-K dated April 8, 2009, filed on April 8, 2009, File   No. 001-32369).                                                                                                                          |
| 3.6 |   | Certificate   of Designation for Series B Convertible Preferred Stock (incorporated   herein by reference to Exhibit 3.5 to the Company’s Form S-1   Registration Statement dated April 16, 2003, filed April 17, 2003,   File No. 333-104592).                                                                                                                  |
| 3.7 |   | Certificate   of Designation, Preferences and Rights of Series C Convertible Preferred   Stock dated as of June 22, 2010 (incorporated by reference to   Exhibit 3.1 to the Company’s Form 8-K dated June 22, 2010,   filed on June 28, 2010, File No. 001-32369).                                                                                          |
| 4.1 |   | Indenture   dated as of October 20, 2004, between Gasco Energy, Inc. and Wells   Fargo Bank, National Association, as Trustee (incorporated herein by   reference to Exhibit 4.1 to the Company’s Current Report on   Form 8-K filed on October 20, 2004, File No. 000-26321).                                                                                   |
| 4.2 |   | Form of   Global Note representing $65 million principal amount of 5.5% Convertible   Senior Notes due 2011 (incorporated herein by reference to Exhibit A to   Exibit 4.1 to the Company’s Current Report on Form 8-K filed on   October 20, 2004, File No. 000-26321).                                                                                              |
| 4.3 |   | Registration   Rights Agreement dated October 20, 2004, among Gasco Energy, Inc.,   J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporated herein   by reference to Exhibit 4.10 to the Company’s Form 10-Q for the   quarter ended September 30, 2004 filed on November 12, 2004, File   No. 000-26321).                                   |
| 4.4 |   | Pledge   and Security Agreement dated March 29, 2006 by and among Gasco   Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC,   Myton Oilfield Rentals, LLC and JPMorgan Chase Bank, N.A. (incorporated   herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated   March 29, 2006, filed March 31, 2006, File No. 001-32369). |
| 4.5 |   | Voting   Agreement dated September 20, 2006 by and among Gasco Energy, Inc.,   Richard N. Jeffs, Gregory Pek, Ian Robinson, Michael L. Nazmack, Eugene   Sweeney and Shawne Malone (incorporated herein by reference to   Exhibit 4.1 to the Company’s Form 8-K dated September 20,   2006, filed September 21, 2006, File No. 001-32369).             |
| 4.6 |   | Indenture   (including form of 2015 Note) dated as of June 25, 2010 between Gasco   Energy, Inc. and Wells Fargo Bank, National Association (incorporated by   reference to Exhibit 4.1 to the Company’s Form 8-K dated   June 22, 2010, filed on June 28, 2010, File No. 001-32369).                                                                       |

 

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| 4.7  |   | First   Supplemental Indenture dated as of September 22, 2010 (incorporated by   reference to Exhibit 10.7 to the Company’s Form 10-Q dated   September 30, 2010, filed on November 2, 2010, File   No. 001-32369).                                                                                                                                                                                                                                            |
|------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.8  |   | Guaranty   Agreement dated as of June 25, 2010 among Gasco Production Company,   Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of   Wells Fargo Bank, National Association (incorporated by reference to   Exhibit 4.2 to the Company’s Form 8-K dated June 22, 2010,   filed on June 28, 2010, File No. 001-32369).                                                                                                                 |
| 4.9  |   | Investor   Rights Agreement dated as of June 25, 2010 among Gasco   Energy, Inc., CNH CA Master Account, L.P. and AQR Absolute Return Master   Account, L.P. (incorporated by reference to Exhibit 4.3 to the Company’s   Form 8-K dated June 22, 2010, filed on June 28, 2010, File   No. 001-32369).                                                                                                                                                    |
| 10.1 |   | Credit   Agreement dated March 29, 2006 by and among Gasco Energy, Inc.,   Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield   Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc.   (incorporated herein by reference to Exhibit 4.1 to the Company’s   Form 8-K dated March 29, 2006, filed March 31, 2006, File   No. 001-32369).                                                                             |
| 10.2 |   | First   Amendment to the Credit Agreement dated April 22, 2008 by and among   Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering,   LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan   Securities Inc. (incorporated herein by reference to Exhibit 4.13 to the   Company’s Form 10-Q dated March 31, 2008, filed May 6, 2008,   File No. 001-32369).                                                       |
| 10.3 |   | Second   Amendment to the Credit Agreement, dated as of December 10, 2008, by and   among by and among Gasco Energy, Inc., as Borrower, certain subsidiaries   of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and   JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by   reference to Exhibit 10.1 to the Company’s Form 8-K dated   December 12, 2008, filed on December 12, 2008, File   No. 001-32369). |
| 10.4 |   | Third   Amendment to the Credit Agreement, dated as of May 14, 2009, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party hereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to Exhibit 10.1 to the Company’s Form 8-K dated May 15, 2009,   File No. 001-32369).                                                             |
| 10.5 |   | Fourth   Amendment to the Credit Agreement, dated as of July 6, 2009, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 8-K dated July 7, 2009, File No. 001-32369).                                                                                  |
| 10.6 |   | Fifth   Amendment to the Credit Agreement, dated as of August 28, 2009, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 8-K dated August 31, 2009, File   No. 001-32369).                                                                           |
| 10.7 |   | Sixth   Amendment to the Credit Agreement, dated as of September 30, 2009, by   and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 8-K dated October 1, 2009, File   No. 001-32369).                                                                        |

 

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| 10.8      |   | Seventh   Amendment to the Credit Agreement, dated as of October 30, 2009, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 10-Q dated September 30, 2009, File   No. 001-32369).                                       |
|-----------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.9      |   | Eighth   Amendment to the Credit Agreement, dated as of December 1, 2009, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 8-K dated December 1, 2009, File   No. 001-32369).                                           |
| 10.10     |   | Ninth   Amendment to the Credit Agreement, dated as of February 1, 2010, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 8-K dated February 1, 2010, File   No. 001-32369).                                            |
| 10.11     |   | Tenth   Amendment to Credit Agreement dated as of June 22, 2010 by and among   Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2   to the Company’s Form 8-K dated June 22, 2010, filed on   June 28, 2010, File No. 001-32369).             |
| 10.12     |   | Eleventh   Amendment to Credit Agreement dated as of November 3, 2011 by and among   Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated by reference to   Exhibit 10.1 to the Company’s Form 8-K dated November 3, 2011,   filed on November 9, 2011, File No. 001-32369). |
| #   10.13 |   | 1999   Stock Option Plan (incorporated herein by reference to Exhibit 4.1 to   the Company’s Form 10-KSB for the fiscal year ended December 31,   1999, filed on April 14, 2000, File No. 000-26321).                                                                                                                                                                                                                                  |
| #   10.14 |   | Form of   Stock Option Agreement under the 1999 Stock Option Plan (incorporated herein   by reference to Exhibit 10.8 to the Company’s Form 10-K for the   fiscal year ended December 31, 2001, filed on March 29, 2002, File   No. 000-26321).                                                                                                                                                                                   |
| #   10.15 |   | Stock   Option Agreement dated January 2, 2001 between Gasco and Mark A.   Erickson (Filed as Exhibit 10.9 to the Company’s Form 10-K for the   fiscal year ended December 31, 2001, filed on March 29, 2002, File   No. 000-26321).                                                                                                                                                                                              |
| #   10.16 |   | Form of   Stock Option Agreement between Gasco and each of the individuals named   therein (incorporated herein by reference to Exhibit 4.6 to the   Company’s Form S-8 Registration Statement (Reg. No. 333-122716),   filed on February 10, 2005).                                                                                                                                                                                   |
| #   10.17 |   | Mark   A. Erickson Amended and Restated Employment Contract dated February 14,   2003 (incorporated herein by reference to Exhibit 10.12 to the Company’s   Form 10-K for the fiscal year ended December 31, 2002, filed on   March 29, 2003, File No. 000-26321).                                                                                                                                                                |
| #   10.18 |   | Amended   and Restated Consulting Agreement dated February 14, 2003, between Gasco   and Marc Bruner (incorporated herein by reference to Exhibit 10.13 to   the Company’s Form 10-K for the fiscal year ended December 31,   2002, filed on March 29, 2003, File No. 000-26321).                                                                                                                                                 |
| #   10.19 |   | 2003   Restricted Stock Plan (incorporated herein by reference to Appendix B to the   Company’s Proxy Statement dated August 25, 2003 for its 2003 Annual   Meeting of Stockholders, filed on August 25, 2003, File   No. 000-26321).                                                                                                                                                                                                            |

 

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| #10.20 |   | Form of   Amendment to Gasco Energy, Inc. Employment Agreement, dated as of   December 31, 2008, and effective as of January 1, 2009, by and   among Gasco Energy, Inc. and certain of its Executives (incorporated   herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated   January 7, 2009, filed January 7, 2009, File No. 001-32369). |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| #10.21 |   | Form of   Second Amendment to Gasco Energy, Inc. Employment Agreement, dated as of   January 22, 2009, by and among Gasco Energy, Inc. and certain of   its Executives (incorporated herein by reference to Exhibit 10.12 to the   Company’s Form 10-K for the fiscal year ended December 31, 2008,   File No. 001-32369).                                         |
| 10.22  |   | Asset Purchase Agreement dated January 29,   2010 by and among Gasco Energy, Inc., Riverbend Gas Gathering, LLC, and   Monarch Natural Gas, LLC (incorporated herein by reference to   Exhibit 10.1 to Gasco Energy, Inc.’s Current Report on   Form 8-K filed on February 3, 2010, File No. 001-32369).                                                                |
| #10.23 |   | Consulting   Agreement and Release, dated January 29, 2010, by and between Gasco   Energy, Inc. and Mark A. Erickson (incorporated herein by reference to Exhibit 10.1 to Gasco   Energy, Inc.’s Current Report on Form 8-K filed on February 1,   2010, File No. 001-32369).                                                                                           |
| 10.24  |   | Gas   Gathering and Processing Agreement, effective March 1, 2010, by and   between Gasco Production Company and Monarch Natural Gas, LLC (incorporated   by reference to Exhibit 10.1 to the Company’s Current Report on   Form 8-K filed on March 3, 2010, File No. 001-32369).                                                                                                 |
| 10.25  |   | Form of   Exchange Agreement dated as of June 22, 2010 between Gasco   Energy, Inc. and each of the Investors (incorporated by reference to   Exhibit 10.1 to the Company’s Form 8-K dated June 22, 2010,   filed on June 28, 2010, File No. 001-32369).                                                                                                           |
| 10.26  |   | Confidential   Information Memorandum dated as of June 22**,** 2010 (incorporated by reference to Exhibit 99.1 to   the Company’s Form 8-K dated June 22, 2010, filed on June 28,   2010, File No. 001-32369).                                                                                                                                                               |
| #10.27 |   | Employment Agreement entered into by and between   Gasco Energy, Inc. and W. King Grant, effective as of February 8, 2011 (incorporated by reference to   Exhibit 10.1 to the Company’s Form 8-K dated February 8, 2011,   filed on February 11, 2011, File No. 001-32369).                                                                                             |
| #10.28 |   | Employment Agreement entered into by and between   Gasco Energy, Inc. and Michael K. Decker, effective as of   February 8, 2011 (incorporated by reference to Exhibit 10.2 to the   Company’s Form 8-K dated February 8, 2011, filed on   February 11, 2011, File No. 001-32369).                                                                                       |
| *23.1  |   | Consent   of Netherland, Sewell & Associates, Inc.                                                                                                                                                                                                                                                                                                                                                |
| *23.2  |   | Consent   of KPMG                                                                                                                                                                                                                                                                                                                                                                                               |
| *31.1  |   | Rule 13a-14(a)/15d-14(a) Certification   of Principal Executive Officer                                                                                                                                                                                                                                                                                                                               |
| *31.2  |   | Rule 13a-14(a)/15d-14(a) Certification   of Principal Financial Officer                                                                                                                                                                                                                                                                                                                               |
| *32.1  |   | Section 1350   Certification of Principal Executive Officer                                                                                                                                                                                                                                                                                                                                                |
| *32.2  |   | Section 1350   Certification of Principal Financial Officer                                                                                                                                                                                                                                                                                                                                                |
| *99.1  |   | Report   of Netherland, Sewell & Associates, Inc., independent petroleum   engineers and geologists.                                                                                                                                                                                                                                                                                              |

 

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*  Filed herewith.

#  Identifies management contracts and compensatory plans or arrangements.

 

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**SIGNATURES**

 

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

 
| **GASCO ENERGY, INC.** | Dated:   March 2, 2011 |
|-----------------------------|-----------------------------|

 
| By:    | /s/   W. King Grant                |   |
|--------|------------------------------------|--------|
|   | W.   King Grant, President and CEO |   |

 

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

 
| **Signature**                      | ** ** | **Title**                                   | ** ** | **Date**           |
|------------------------------------|------------|---------------------------------------------|------------|--------------------|
|                               |       |                                        |       |               |
| /s/   Charles B. Crowell           |       | Director                                    |       | March 2, 2011 |
| Charles B. Crowell                 |       |                                        |       |               |
|                               |       |                                        |       |               |
| /s/   Marc A. Bruner               |       | Director                                    |       | March 2, 2011 |
| Marc   A. Bruner                   |       |                                        |       |               |
|                               |       |                                        |       |               |
| /s/   Carmen Lotito                |       | Director                                    |       | March 2, 2011 |
| Carmen   (“Tony”) Lotito |       |                                        |       |               |
|                               |       |                                        |       |               |
| /s/   Richard S. Langdon           |       | Director                                    |       | March 2, 2011 |
| Richard   S. Langdon               |       |                                        |       |               |
|                               |       |                                        |       |               |
| /s/   R. J. Burgess                |       | Director                                    |       | March 2, 2011 |
| R.J.   Burgess                     |       |                                        |       |               |
|                               |       |                                        |       |               |
| /s/   John A. Schmit               |       | Director                                    |       | March 2, 2011 |
| John   A. Schmit                   |       |                                        |       |               |
|                               |       |                                        |       |               |
| /s/   Steven D. (Dean) Furbush     |       | Director                                    |       | March 2, 2011 |
| Steven   D. (Dean) Furbush         |       |                                        |       |               |
|                               |       |                                        |       |               |
| /s/   Peggy A. Herald              |       | Vice President and Chief Accounting Officer |       | March 2, 2011 |
| Peggy   A. Herald                  |       | (Principal Financial Officer)               |       |               |

 

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** **

**INDEX TO EXHIBITS**

 
| 3.1 |   | Amended   and Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1   to the Company’s Form 8-K dated December 31, 1999, filed on January 21,   2000, File No. 000-26321).                                                                                                                                                              |
|-----|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.2 |   | Certificate   of Amendment to Articles of Incorporation (incorporated herein by reference   to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31,   2001, filed on February 16, 2001, File No. 000-26321).                                                                                                                                                     |
| 3.3 |   | Certificate   of Amendment to Articles of Incorporation dated June 21, 2005   (incorporated herein by reference to Exhibit 3.3 to the Company’s Form 10-Q/A   for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).                                                                                                                 |
| 3.4 |   | Certificate   of Amendment to Articles of Incorporation dated September 20, 2010   (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K   dated September 20, 2010, filed on September 20, 2010, File No. 001-32369).                                                                                                                      |
| 3.5 |   | Second   Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8,   2009 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K   dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).                                                                                                                            |
| 3.6 |   | Certificate   of Designation for Series B Convertible Preferred Stock (incorporated   herein by reference to Exhibit 3.5 to the Company’s Form S-1   Registration Statement dated April 16, 2003, filed April 17, 2003,   File No. 333-104592).                                                                                                                  |
| 3.7 |   | Certificate   of Designation, Preferences and Rights of Series C Convertible Preferred   Stock dated as of June 22, 2010 (incorporated by reference to Exhibit 3.1   to the Company’s Form 8-K dated June 22, 2010, filed on June 28,   2010, File No. 001-32369).                                                                                          |
| 4.1 |   | Indenture   dated as of October 20, 2004, between Gasco Energy, Inc. and Wells   Fargo Bank, National Association, as Trustee (incorporated herein by   reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K   filed on October 20, 2004, File No. 000-26321).                                                                                   |
| 4.2 |   | Form of   Global Note representing $65 million principal amount of 5.5% Convertible   Senior Notes due 2011 (incorporated herein by reference to Exhibit A to   Exibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20,   2004, File No. 000-26321).                                                                                              |
| 4.3 |   | Registration   Rights Agreement dated October 20, 2004, among Gasco Energy, Inc.,   J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporated herein   by reference to Exhibit 4.10 to the Company’s Form 10-Q for the   quarter ended September 30, 2004 filed on November 12, 2004, File No. 000-26321).                                     |
| 4.4 |   | Pledge   and Security Agreement dated March 29, 2006 by and among Gasco Energy, Inc.,   Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield   Rentals, LLC and JPMorgan Chase Bank, N.A. (incorporated herein by reference   to Exhibit 4.2 to the Company’s Form 8-K dated March 29, 2006,   filed March 31, 2006, File No. 001-32369). |
| 4.5 |   | Voting   Agreement dated September 20, 2006 by and among Gasco Energy, Inc.,   Richard N. Jeffs, Gregory Pek, Ian Robinson, Michael L. Nazmack, Eugene   Sweeney and Shawne Malone (incorporated herein by reference to Exhibit 4.1   to the Company’s Form 8-K dated September 20, 2006, filed September 21,   2006, File No. 001-32369).             |
| 4.6 |   | Indenture   (including form of 2015 Note) dated as of June 25, 2010 between Gasco   Energy, Inc. and Wells Fargo Bank, National Association (incorporated by   reference to Exhibit 4.1 to the Company’s Form 8-K dated June 22,   2010, filed on June 28, 2010, File No. 001-32369).                                                                       |
| 4.7 |   | First   Supplemental Indenture dated as of September 22, 2010 (incorporated by   reference to Exhibit 10.7 to the Company’s Form 10-Q dated September 30,   2010, filed on November 2, 2010, File No. 001-32369).                                                                                                                                                |

 

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| 4.8  |   | Guaranty   Agreement dated as of June 25, 2010 among Gasco Production Company,   Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of   Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2   to the Company’s Form 8-K dated June 22, 2010, filed on June 28,   2010, File No. 001-32369).                                                                                                               |
|------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.9  |   | Investor   Rights Agreement dated as of June 25, 2010 among Gasco Energy, Inc.,   CNH CA Master Account, L.P. and AQR Absolute Return Master Account, L.P.   (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K   dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).                                                                                                                                                    |
| 10.1 |   | Credit   Agreement dated March 29, 2006 by and among Gasco Energy, Inc.,   Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield   Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc.   (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 8-K   dated March 29, 2006, filed March 31, 2006, File No. 001-32369).                                                                             |
| 10.2 |   | First   Amendment to the Credit Agreement dated April 22, 2008  by and among Gasco Energy, Inc., Gasco   Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals,   LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc. (incorporated   herein by reference to Exhibit 4.13 to the Company’s Form 10-Q   dated March 31, 2008, filed May 6, 2008, File No. 001-32369).                                                 |
| 10.3 |   | Second   Amendment to the Credit Agreement, dated as of December 10, 2008, by and   among by and among Gasco Energy, Inc., as Borrower, certain subsidiaries   of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and   JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by   reference to Exhibit 10.1 to the Company’s Form 8-K dated December 12,   2008, filed on December 12, 2008, File No. 001-32369). |
| 10.4 |   | Third   Amendment to the Credit Agreement, dated as of May 14, 2009, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party hereto, and JPMorgan Chase   Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1   to the Company’s Form 8-K dated May 15, 2009, File No. 001-32369).                                                             |
| 10.5 |   | Fourth   Amendment to the Credit Agreement, dated as of July 6, 2009, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 8-K dated July 7, 2009, File No. 001-32369).                                                                                |
| 10.6 |   | Fifth   Amendment to the Credit Agreement, dated as of August 28, 2009, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 8-K dated August 31, 2009, File No. 001-32369).                                                                           |
| 10.7 |   | Sixth   Amendment to the Credit Agreement, dated as of September 30, 2009, by   and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 8-K dated October 1, 2009, File No. 001-32369).                                                                        |

 

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| 10.8    |   | Seventh   Amendment to the Credit Agreement, dated as of October 30, 2009, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 10-Q dated September 30, 2009, File No. 001-32369).                                         |
|---------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.9    |   | Eighth   Amendment to the Credit Agreement, dated as of December 1, 2009, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 8-K dated December 1, 2009, File No. 001-32369).                                             |
| 10.10   |   | Ninth   Amendment to the Credit Agreement, dated as of February 1, 2010, by and   among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco   Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan   Chase Bank, N.A., as Administrative Agent (incorporated herein by reference   to the Company’s Form 8-K dated February 1, 2010, File No. 001-32369).                                              |
| 10.11   |   | Tenth   Amendment to Credit Agreement dated as of June 22, 2010 by and among   Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc.,   as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as   Administrative Agent (incorporated by reference to Exhibit 10.2 to the   Company’s Form 8-K dated June 22, 2010, filed on June 28,   2010, File No. 001-32369).             |
| 10.12   |   | Eleventh   Amendment to Credit Agreement dated as of November 3, 2011 by and among   Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc.,   as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as   Administrative Agent (incorporated by reference to Exhibit 10.1 to the   Company’s Form 8-K dated November 3, 2011, filed on November 9,   2011, File No. 001-32369). |
| # 10.13 |   | 1999   Stock Option Plan (incorporated herein by reference to Exhibit 4.1 to   the Company’s Form 10-KSB for the fiscal year ended December 31,   1999, filed on April 14, 2000, File No. 000-26321).                                                                                                                                                                                                                                  |
| # 10.14 |   | Form of   Stock Option Agreement under the 1999 Stock Option Plan (incorporated herein   by reference to Exhibit 10.8 to the Company’s Form 10-K for the   fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).                                                                                                                                                                                     |
| # 10.15 |   | Stock   Option Agreement dated January 2, 2001 between Gasco and Mark A.   Erickson (Filed as Exhibit 10.9 to the Company’s Form 10-K for the   fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).                                                                                                                                                                                                |
| # 10.16 |   | Form of   Stock Option Agreement between Gasco and each of the individuals named   therein (incorporated herein by reference to Exhibit 4.6 to the Company’s   Form S-8 Registration Statement (Reg. No. 333-122716), filed on February 10,   2005).                                                                                                                                                                                   |
| # 10.17 |   | Mark   A. Erickson Amended and Restated Employment Contract dated February 14,   2003 (incorporated herein by reference to Exhibit 10.12 to the Company’s   Form 10-K for the fiscal year ended December 31, 2002, filed on March 29,   2003, File No. 000-26321).                                                                                                                                                                |
| # 10.18 |   | Amended   and Restated Consulting Agreement dated February 14, 2003, between Gasco   and Marc Bruner (incorporated herein by reference to Exhibit 10.13 to   the Company’s Form 10-K for the fiscal year ended December 31,   2002, filed on March 29, 2003, File No. 000-26321).                                                                                                                                                 |
| # 10.19 |   | 2003   Restricted Stock Plan (incorporated herein by reference to Appendix B to the   Company’s Proxy Statement dated August 25, 2003 for its 2003 Annual   Meeting of Stockholders, filed on August 25, 2003, File No. 000-26321).                                                                                                                                                                                                              |

 

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Table of Contents

 
| #10.20 |   | Form of   Amendment to Gasco Energy, Inc. Employment Agreement, dated as of   December 31, 2008, and effective as of January 1, 2009, by and   among Gasco Energy, Inc. and certain of its Executives (incorporated   herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated   January 7, 2009, filed January 7, 2009, File No. 001-32369). |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| #10.21 |   | Form of   Second Amendment to Gasco Energy, Inc. Employment Agreement, dated as of   January 22, 2009, by and among Gasco Energy, Inc. and certain of   its Executives (incorporated herein by reference to Exhibit 10.12 to the   Company’s Form 10-K for the fiscal year ended December 31, 2008,   File No. 001-32369).                                         |
| 10.22  |   | Asset Purchase Agreement dated January 29,   2010 by and among Gasco Energy, Inc., Riverbend Gas Gathering, LLC, and   Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1   to Gasco Energy, Inc.’s Current Report on Form 8-K filed on February 3,   2010, File No. 001-32369).                                                                |
| #10.23 |   | Consulting   Agreement and Release, dated January 29, 2010, by and between Gasco   Energy, Inc. and Mark A. Erickson (incorporated herein by reference to Exhibit 10.1 to Gasco Energy, Inc.’s   Current Report on Form 8-K filed on February 1, 2010, File No. 001-32369).                                                                                             |
| 10.24  |   | Gas   Gathering and Processing Agreement, effective March 1, 2010, by and   between Gasco Production Company and Monarch Natural Gas, LLC (incorporated   by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K   filed on March 3, 2010, File No. 001-32369).                                                                                                 |
| 10.25  |   | Form of   Exchange Agreement dated as of June 22, 2010 between Gasco Energy, Inc.   and each of the Investors (incorporated by reference to Exhibit 10.1 to   the Company’s Form 8-K dated June 22, 2010, filed on June 28,   2010, File No. 001-32369).                                                                                                           |
| 10.26  |   | Confidential   Information Memorandum dated as of June 22**,** 2010 (incorporated by reference to Exhibit 99.1 to   the Company’s Form 8-K dated June 22, 2010, filed on June 28,   2010, File No. 001-32369).                                                                                                                                                               |
| #10.27 |   | Employment Agreement entered into by and between   Gasco Energy, Inc. and W. King Grant, effective as of February 8, 2011 (incorporated by reference to Exhibit 10.1   to the Company’s Form 8-K dated February 8, 2011, filed on February 11,   2011, File No. 001-32369).                                                                                             |
| #10.28 |   | Employment Agreement entered into by and between   Gasco Energy, Inc. and Michael K. Decker, effective as of February 8,   2011 (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K   dated February 8, 2011, filed on February 11, 2011, File No. 001-32369).                                                                                         |
| *23.1  |   | Consent   of Netherland, Sewell & Associates, Inc.                                                                                                                                                                                                                                                                                                                                                |
| *23.2  |   | Consent   of KPMG                                                                                                                                                                                                                                                                                                                                                                                               |
| *31.1  |   | Rule 13a-14(a)/15d-14(a) Certification   of Principal Executive Officer                                                                                                                                                                                                                                                                                                                               |
| *31.2  |   | Rule 13a-14(a)/15d-14(a) Certification   of Principal Financial Officer                                                                                                                                                                                                                                                                                                                               |
| *32.1  |   | Section 1350   Certification of Principal Executive Officer                                                                                                                                                                                                                                                                                                                                                |
| *32.2  |   | Section 1350   Certification of Principal Financial Officer                                                                                                                                                                                                                                                                                                                                                |
| *99.1  |   | Report   of Netherland, Sewell & Associates, Inc., independent petroleum   engineers and geologists.                                                                                                                                                                                                                                                                                              |

 

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*  Filed herewith.

#  Identifies management contracts and compensatory plans or arrangements.

 

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