UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

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

Commission file number: 001-32369

GASCO ENERGY, INC.

(Exact name of registrant as specified in its charter)

NEVADA (State or other jurisdiction of incorporation or organization)		98-0204105 (I.R.S. Employer 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 COMMON STOCK, $0.0001 PAR VALUE		Name of each exchange on which registered 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 þ

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 þ

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 þ 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 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 þ (Do not check if a smaller reporting company)		Smaller reporting company o

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

As of June 30, 2009, approximately 107,728,798 shares of Common Stock, par value $0.0001 per share were outstanding, and the aggregate market value of the outstanding shares of Common Stock of the Company held by non-affiliates was approximately $28,299,104 based on a closing price of $0.28 per share, which was the closing price per share on June 30, 2009. As of March 3, 2010, 107,715,897 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 2010 annual meeting of stockholders to be filed within 120 days of December 31, 2009.

 

 

Table of Contents

Part I
Item 1. Business			1
Item 1 A. Risk Factors			14
Item 1 B. Unresolved Staff Comments			32
Item 2. Properties			32
Item 3. Legal Proceedings			39
Item 4. Submission of Matters to a Vote of Security Holders			41
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			41
Item 6. Selected Financial Data			41
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			42
Item 7A. Quantitative and Qualitative Disclosures about Market Risk			67
Item 8. Financial Statements and Supplementary Data			68
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			119
Item 9A. Controls and Procedures			119
Item 9B. Other Information			123

Part III
Item 10. Directors, Executive Officers and Corporate Governance			123
Item 11. Executive Compensation			123
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			123
Item 13. Certain Relationships and Related Transactions and Director Independence			123
Item 14. Principal Accounting Fees and Services			123
Item 15. Exhibits, Financial Statement Schedules			123
EX-23.1
EX-23.2
EX-31
EX-32
EX-99.1

PART I

ITEM 1 — BUSINESS

Business of Gasco

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 using technologies new to a specific area to generate and develop high-potential exploitation resources in this area. 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 activities 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, 2009, we held interests in 282,326 gross acres (228,724 net acres) located in Utah, Wyoming, California and Nevada. As of December 31, 2009, we held an interest in 132 gross producing wells (77.6 wells, net to our interest) and three shut-in wells (3.0 net) located on these properties.

During 2009, we reached total depth on two gross operated wells (0.84 net), one of which was in progress at December 31, 2008, in the Riverbend Project. We spudded one new well during 2009 and upon reaching total depth on this well, we released our drilling rig. We conducted initial completion operations on two Upper Mancos wells and we re-entered three gross operated wells (0.92 net wells) to complete pay zones that were behind pipe. Additionally, we performed limited workover operations on certain Green River Formation oil wells to enhance oil production during the improved crude oil prices received during the last three quarters of 2009. As of December 31, 2009, we operated 132 gross producing wells. We currently have an inventory of 34 operated wells with up-hole completion potential and one well awaiting initial completion activities.

During June 2009, we sold our 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. We recognized a loss of $905,850 on the sale which is recorded in “Loss on sale of assets, net” in the accompanying consolidated financial statements (see Note 2 “Significant Accounting Policies – Facilities and Equipment” of the accompanying consolidated financial statements).

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.

Recent Developments

     Sale of Gathering Assets

On February 26, 2010, we completed the sale (the “Closing”) of materially all of the assets (the “Asset Sale”) comprising our gathering system and our 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, we received total cash consideration of $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 Closing we entered into (i) a transition services agreement with Monarch pursuant to which we will provide 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 we dedicated our 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 in the Asset Sale. These agreements will result in less revenue and additional costs with an aggregate annual impact, inclusive of a reduction in depreciation expense, of approximately $3.5 million based on 2009 activity. The Purchase Agreement is subject to customary post-closing terms and conditions for transactions of this size and nature.

     Acquisition of Petro-Canada Assets

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 include 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.

     Amendment to Credit Facility

On February 1, 2010, our revolving 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. Following the $23 million debt repayment, our available credit is approximately $4.0 million.

     Resignation of Former Chief Executive Officer; Appointment of Replacement

Effective January 27, 2010, our former Chief Executive Officer and President, Mark Erickson, resigned and was replaced by Charles Crowell as Chief Executive Officer and W. King Grant as President.

     Principal Products or Services and Markets

We focus our exploitation activities on locating natural gas and crude petroleum. The principal markets for these commodities are natural gas transmission pipeline and marketing companies, utilities, refining companies and private industry end-users. Historically, nearly all of our sales have been to a few customers. The majority of our production was sold to one customer during each of the years ended December 31, 2009, 2008 and 2007: Anadarko Petroleum Corporation (“Anadarko”) during 2009 and 2008 and ConocoPhillips during 2007. However, we do not believe that the loss of a single purchaser, including Anadarko or ConocoPhillips, would materially affect our business because there are numerous other potential purchasers in the areas in which we sell our production. For the years ended December 31, 2009, 2008 and 2007, purchases by the following companies exceeded 10% of our total oil and gas revenues.

		For the Years Ended December 31,
		2009				2008				2007
Revenues associated with EnWest Marketing LLC (“EnWest”) purchases		$	1,916,757				—				—
Revenues associated with ConocoPhillips purchases		$	13,429			$	7,537,841			$	15,272,000
Revenues associated with Anadarko purchases		$	13,173,402			$	24,406,071				—
Percentage of oil and gas revenues attributable to:
EnWest			12	%			—				—
ConocoPhillips			—				21	%			80	%
Anadarko			84	%			68	%			—

Rockies natural gas prices continued their lower trend during 2009. These low prices are due in part to weak demand resulting from a lower level of economic activity.

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 with greater financial and other resources.

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.

Financial Information About Geographic Areas

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, result in 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 a material 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.

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.

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 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. In a letter to the EPA dated January 23, 2008, Riverbend confirmed its willingness to sign a consent decree with the United States that resolves the apparent violations, specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that will effectively authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented. Riverbend has continued to work with the EPA and the Department of Justice on a settlement of this matter, and it anticipates that such a resolution will be achieved during 2010. We believe that all necessary pollution control and other equipment likely to be required by such a resolution is already installed at the site or accounted for in our capital budget, and that any civil penalty that may be assessed in conjunction with a resolution of this matter will not materially affect our financial position or liquidity. On February 26, 2010, we sold substantially all of the assets comprising our Riverbend gathering system, including the Riverbend Compressor Station. Pursuant to that sale agreement, the buyer will also be a party to the consent decree and will be responsible for implementing the consent decree requirements at those assets that it purchased, other than the payment of the civil penalty and the installation of the remaining capital equipment required by the consent decree, which will remain Riverbend’s responsibility.

     In response to scientific studies suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere, there are a number of parallel initiatives to restrict or regulate emissions of greenhouse gases. On June 26, 2009, the United States House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide “cap and trade” program to reduce domestic emissions of greenhouse gases. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions or suppliers of carbon-based fuels so that such sources could continue to emit greenhouse gases into the atmosphere or market such fuels. The market price of these allowances would be expected to increase significantly over time, thereby encouraging the use of alternative energy sources or greenhouse gas emission control technologies by imposing ever-increasing costs on the use of carbon-based fuels, including natural gas and refined petroleum products. The United States Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas “cap and trade” programs. These programs operate similarly to the program contemplated by ACESA. Depending on the particular state or regional program, we could be required to purchase and surrender emission allowances, either for greenhouse gas emissions resulting from our operations (e.g., compressor stations) or from the combustion of fuels (e.g., natural gas) that we process.

Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al.v. EPA, EPA was required to determine whether greenhouse gas emissions posed an endangerment to

human health and the environment and whether emissions from mobile sources, such as cars and trucks contributed to that endangerment. On December 7, 2009, the EPA announced its findings that emissions of greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and causing other climatic changes and that mobile sources are contributing to such endangerment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, EPA proposed two sets of regulations in anticipation of finalizing its endangerment finding: one to reduce emissions of greenhouse gases from motor vehicles and the other to control emissions of greenhouse gases from stationary sources. Although the motor vehicle rules are expected to be adopted in March 2010, it may take EPA several years to impose regulations limiting emissions of greenhouse gases from stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the annual reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, and these sources are expected to include some of our facilities when EPA amends its reporting rule, probably in 2010. Any federal greenhouse gas legislation is expected to prevent EPA from regulating greenhouse gases under existing Clean Air Act regulatory programs to some extent, but if Congress fails to pass greenhouse gas legislation, the EPA is expected to continue its announced greenhouse gas regulatory actions under the Clean Air Act. Any limitation on emissions of greenhouse gases from our equipment and operations or the requirement that we obtain allowances for such emissions, could require us to incur significant costs to reduce emissions of greenhouse gases associated with our operations or acquire allowances at the prevailing rates in the marketplace.

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 could 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.

Employees

As of March 3, 2010, we had 28 full-time employees.

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 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.

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;
	•		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;
	•		estimated reserves of natural gas and oil, including uncertainties about the effects of the SEC’s new rules governing reserve reporting;
	•		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.

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.

     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

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. (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, as defined in paragraph (a)(2) of this section, 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.

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 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. In addition, the current global economic environment intensifies many of these risks.

Future economic conditions in the US and key international markets may materially adversely impact our operating results.

The US and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. Growth has resumed, but is modest. 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 crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

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

Historically, other than for the year ended December 31, 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 current economic environment and commodity price levels, we may not be able to successfully develop any prospects that we have or acquire without adequate financing and we may not achieve profitability from operations in the near future or at all.

During the years ended December 31, 2009 and 2007, we incurred a net loss of $50,188,171 and $104,373,921, respectively. As of December 31, 2009, we had an accumulated deficit of $225,401,140. 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.

Oil and natural gas prices are volatile. The extended decline in commodity prices has adversely affected, and in the future will 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 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. 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 2010, it will have similar adverse effects on our reserves and global borrowing base. Further, because we have elected to use the full-cost accounting method, we must perform each quarter a “ceiling test” that is affected by declining prices. 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. During the first quarter of 2009, we recorded an impairment of $41,000,000.

In addition, significant or extended price declines may 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. Any of these factors could negatively impact our ability to replace our production and our future rate of growth. We intend to fund our 2010 capital expenditures budget from cash flows generated from operations in anticipation of continuing current or declining commodity prices.

The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. Oil spot prices reached historical highs in July 2008, peaking at more than $145 per barrel, and natural gas spot prices reached near historical highs in July 2008, peaking at more than $13 per MMBtu. These prices have declined significantly since that time and may continue to fluctuate widely in the future, either collectively or independent of one another, in response to 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;
	•		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.

Lower natural gas and oil prices may not only decrease our revenue, but also may reduce the amount of natural gas and oil that we can produce economically. This reduction may 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 $15.33 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 2009 prices we will be unable to economically develop most of our acreage.

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.

     We may not be able to maintain adequate cash flow from operations or obtain adequate financing to 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 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. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our stockholders. 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.

During the fourth quarter of 2008 and through 2009, the severe disruptions in the credit markets and reductions in global economic activity had significant adverse impacts on stock markets and oil and gas-related commodity prices, which contributed to a significant decline in the our stock price and negatively impacted our liquidity. We expect our liquidity will continue to be negatively affected in 2010 by the effects of this activity. 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 2010 budget. Effective February 26, 2010, our borrowing base under our revolving credit facility was reduced to $16 million from $35 million and as of March 3, 2010, we had $11.5 million of outstanding borrowings thereunder. Our borrowing base could be further reduced in the future by our lenders. Though we anticipate funding our capital budget of $6 million for 2010 through cash flows from operations, an inability to access additional borrowings in excess of our existing $4 million of existing capacity under

our revolving credit agreement will limit our ability to increase our operating budget and execute on our growth plans. The maturity of our revolving credit facility and our outstanding $65 million 5.50% Convertible Senior Notes occur in March and October of 2011, respectively. The lenders under our revolving credit facility may elect not to extend the maturity of such facility without our having previously refinanced, restructured or repaid the 5.50% Convertible Senior Notes due 2011. Accordingly, an inability to refinance, restructure or repay such convertible notes prior to their maturity on terms acceptable to us may impair our ability to execute on future growth plans. Furthermore, the failure to refinance, restructure or repay such convertible notes or our revolving credit facility prior to their maturities may impair our ability to obtain alternate sources of financing. Any refinancing, restructuring or repayment could cause substantial dilution to our stockholders either through the issuance of additional equity or the sale of assets.

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. Additionally, should our obligation to repay indebtedness under our revolving credit facility be accelerated, we would be in default under the indenture governing our 5.50% Convertible Senior Notes due 2011, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes. Similarly, should our obligation to repay indebtedness under our convertible notes be accelerated, we would be in default under our revolving credit facility, which would require repayment of the outstanding principal, interest and any other amounts then due.

Lower oil and natural gas prices could negatively impact our ability to borrow. Additionally, 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. As of December 31, 2009, our borrowing base was $35.0 million and our outstanding letter of credit sublimit was $10.0 million. In February 2010, our borrowing base decreased to $16 million. 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 2010. If our borrowing base is further reduced as a result of a redetermination, we may be required to repay an additional portion of our outstanding borrowings and will have less access to borrowed capital going forward. If we do not have sufficient funds on hand for repayment, we may be required to seek a wavier 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 could result in a default under our revolving credit facility, which could adversely affect our business, financial condition and results or operations. Additionally, should our obligation to repay indebtedness under our revolving credit facility be accelerated, we would be in default under the indenture governing our 5.50% Convertible Senior Notes due 2011, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes. Please read “Item 7. Management’s Discussion and Analysis of Financial Position and Results of Operations — Liquidity and Capital Resources — Credit Facility.”

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

Our revolving credit facility imposes 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, 2009, our current and senior debt to EBITDAX ratios were 2.9:1 and 2.3:1, respectively, and we were in compliance with each of the covenants as of December 31, 2009. Any failure to be in compliance with any material provision or covenant of our revolving credit facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under our revolving credit facility. Additionally, should our obligation to repay indebtedness under our revolving credit facility be accelerated, we would be in default under the indenture governing our 5.50% Convertible Senior Notes due 2011, 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 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.

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 the gas gathering agreement, 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.

Pipeline constraints may limit our ability to sell production and may negatively affect the price at which we sell our production.

Our production is transported 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. 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.

Our estimates of proved reserves have been prepared under new 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, 2009, which have been prepared and presented under new SEC rules. These new rules are effective for fiscal years ending on or after December 31, 2009, and 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. As a result of these changes, direct comparisons to our previously-reported reserves amounts may be more difficult.

Another impact of the new SEC 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. This new 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.

The SEC has not reviewed our or any reporting company’s reserve estimates under the new rules and has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on the new rules. Accordingly, while the estimates of our proved reserves at December 31, 2009 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.

Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these 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 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. Please see “Our estimates of proved reserves have been prepared under new 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.” 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 had been producing less than nine years as of December 31, 2009, 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, 2009. 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.

Lower oil and gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.

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 the estimated proved reserves, increases in the estimates of development costs or deterioration in the exploration results.

We follow the full cost method of accounting under which 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.

Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues is computed by applying the twelve month trailing average first of month prices of 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. Once an impairment of gas and oil properties is recognized, it is not reversible at a later date even if oil or gas prices increase. During February 2010, we sold our gathering assets and entered into a gathering agreement with the purchaser. As a result, our gathering expenses will increase which we expect will lower the value of our reserves in the future. This reduction in reserve value may cause us to record a future impairment of our proved properties.

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.

Investments in unproved properties with a carrying value of approximately $38,600,000 as of December 31, 2009, including capitalized interest costs, are also 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.

During 2009 we reclassified approximately $1,100,000 and $200,000 of expiring acreage costs primarily in Utah and California, respectively into proved property. This acreage represents the leases that will expire during 2010 before we are able to develop them further.

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

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. Other hazards, such as unusual or unexpected geological formations, pressures, fires, blowouts, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well. Adverse weather conditions can also hinder drilling operations.

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.

Delays in obtaining drilling permits could have a materially 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.

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. Such companies may be able to pay more for productive petroleum and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. 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. In addition, 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 on a timely basis or at all. We do not believe that our competitive position in the petroleum and natural gas industry is significant.

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.

Insurance against every operational risk is not available at economic rates. We may suffer losses from uninsurable hazards that we have, or the operator thereof has, chosen not to insure against because of high premium costs or other reasons. We may become subject to liability for pollution, fire, explosion, blowouts, cratering and oil spills against which we cannot insure or against which we may elect not to insure. Such events could result in substantial damage to oil and gas wells, producing facilities and other property and personal injury. 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.

If there are any title defects in the properties in which we hold an interest, we 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 ability to market the oil and gas that we produce is essential to our business.

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. For example, we currently distribute the gas that we produce through a single pipeline. 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.

Environmental costs and liabilities and changing environmental regulation could materially affect our cash flow.

Our operations are subject to stringent federal, state and local laws and regulations relating to environmental protection. These laws and regulations may require the acquisition of permits or other governmental approvals, limit or prohibit our operations on environmentally sensitive lands, and place burdensome restrictions on the management and disposal of wastes. 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. Any stringent changes to these environmental laws and regulations may result in increased costs to us with respect to

the disposal of wastes, the performance of remedial activities, and the incurrence of capital expenditures. Please read “Item 1 —Business—Governmental Regulations and Environmental Laws” above.

Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of greenhouse gases and more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. Also, the U.S. Supreme Court’s holding in its 2007 decision, Massachusetts, et al. v. EPA, that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act could result in future regulation of greenhouse gas emissions from stationary sources, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for the natural gas we produce.

We are subject to complex governmental regulations which may adversely affect the cost of our business.

Petroleum and natural gas exploration, development and production are subject to various types of regulation by local, state and federal agencies. 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.

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.

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, 2009 was a current liability of $1,932,513 and a non-current liability of $761,092. 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.

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

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 Financial 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, Marc A Bruner, is the largest shareholder of Petrohunter Energy Corporation (Petrohunter) and Exxcel Energy. Mr. Bruner also serves as a Director and is the Chief Executive Officer of Falcon Oil and Gas, Ltd (Falcon) Falcon operations and projects are in Hungary, Australia, and South Africa. 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. Charles Crowell, one of our directors, is currently serving as our Chief Executive Officer 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 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 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. 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.

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.

On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human 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. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil, natural gas and NGLs that we produce.

Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support of legislation to reduce greenhouse gas emissions through an emission allowance system.

Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that we produce.

Even if such legislation is not adopted at the national level, 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. Any one of these climate change regulatory and legislative initiatives could have a material 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.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress currently is considering broad financial regulatory reform legislation that among other things would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace and could affect the use of derivatives in hedging transactions. The financial regulatory reform bill adopted by the House of Representatives on December 11, 2009, would subject swap dealers and “major swap participants” to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants. For these purposes, a major swap participant generally would be someone other than a dealer who maintains a “substantial” net position in outstanding swaps, excluding swaps used for commercial hedging or for reducing or mitigating commercial risk, or whose positions create substantial net counterparty exposure that could have serious adverse effects on the financial stability of the U.S. banking system or financial markets. The House-passed bill also would provide the Commodity Futures Trading Commission (CFTC) with express authority to impose position limits for OTC derivatives related to energy commodities. Separately, in late January, 2010, the CFTC proposed regulations that would impose speculative position limits for certain futures and option contracts in natural gas, crude oil, heating oil, and gasoline. These proposed regulations would make an exemption available for certain bona fide hedging of commercial risks. Although it is not possible at this time to predict whether or when Congress will act on derivatives legislation or the CFTC will finalize its proposed regulations, any laws or regulations that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

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

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or

increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

Risks Related to Our Capital Stock

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. Our listing on the NYSE Amex is being continued pursuant to this extension through the extension period subject to certain conditions.

We will be subject to periodic review by the NYSE Amex during the extension period. There can be no assurance that we will be able to achieve compliance with Sections 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide within the required time frame. If we are not able to make progress consistent with our plan or to regain compliance with the continued listing standards by the end of the extension period, 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.

Our common stock has experienced, and may continue to experience, price volatility and a 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, 2009, we had 107,715,897 shares of common stock issued and outstanding and outstanding options to purchase an additional 12,096,672 shares of common stock. Additional options may be granted to purchase 1,275,918 shares of common stock under our stock option plan and an additional 326,750 shares of common stock are issuable under our restricted stock plan. As of December 31 of each year, the number of shares of common stock issuable under our stock option plan automatically adjusts so that the total number of shares of common stock issuable under such plan is equal to 10% of the total number of shares of common stock outstanding on such date.

Assuming all of our outstanding 5.50% Convertible Senior Notes due 2011 are converted at the applicable conversion prices, the number of shares of our common stock outstanding would increase by approximately 16,250,000 shares to approximately 123,965,897 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).

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 contains 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 116,444 gross acres in the Uinta Basin of northeastern Utah, of which we hold interests in approximately 80,944 net acres as of December 31, 2009. Historically, our engineering and geologic focus has been concentrated on three tight-sand 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 located between approximately 6,000 and 13,000 feet in depth that are completed using up to ten staged fracs.

During 2009, we reached total depth on 2 gross wells (approximately 0.84 net wells), one of which was in progress at December 31, 2008, in the Riverbend area. We spudded one new well during 2009 and upon reaching total depth on this well, we released our remaining drilling rig. We did not conduct any initial completion operations. We re-entered three gross operated wells (0.92 net wells) to complete pay zones that were behind pipe. Additionally, we performed limited workover operations on certain Green River Formation oil wells to enhance oil production during the improved oil prices received during the last three quarters of 2009. As of December 31, 2009, we operated 132 gross producing wells. We currently have an inventory of 34 operated wells with up-hole recompletion opportunities and one Upper Mancos well awaiting initial completion activities.

Based on current expectations, we intend to fund our 2010 capital expenditure program entirely through cash flow from operations. This program will focus primarily on completion and recompletion projects on our existing wells. Consequently, we will monitor spending and cash flow throughout the year and may accelerate or delay investment depending on commodity prices, cash flow expectations and changes in our borrowing capacity. During 2009 we reclassified approximately $1,100,000 and $200,000 of expiring acreage primarily in Utah and California, respectively into proved property. This acreage represents the leases that will expire during 2010 before we are able to develop it further.

On February 26, 2010, we completed the sale (the “Closing”) of materially all of the assets (the “Asset Sale”) comprising our gathering system and our 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, we received total cash consideration of $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 Closing we entered into (i) a transition services agreement with Monarch pursuant to which we will provide 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 we dedicated our 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 in the Asset Sale. These agreements will result in less revenue and additional costs with an aggregate annual impact, inclusive of a reduction in depreciation expense, of approximately $3.5 million based on 2009

activity. The Purchase Agreement is subject to customary post-closing terms and conditions for transactions of this size and nature.

On February 25, 2010, we completed the acquisition of certain oil and gas leases and lands (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 include one producing well, one shut-in well with recompletion potential and 5,582 gross and net acres located in Utah west of our Gate Canyon operating area. We funded this acquisition with cash flow from operating activities.

     Greater Green River Basin Project

As of December 31, 2009, we had a leasehold interest in approximately 25,124 gross (14,908 net) acres in the Greater Green River Basin area of Wyoming. The acreage covers two prospects identified by us.

The low natural gas prices in this area has 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. We currently have no plans to develop this acreage.

     Southern California Project

As of December 31, 2009, we had a leasehold interest in approximately 24,996 gross acres (18,492 net acres) in Kern and San Luis Obispo Counties of Southern California. On one of our prospects in Kern County, we entered into a farm-out agreement with a large exploration and production company who has a considerable California operations presence. We received a prospect fee and will be carried for a 20% working interest on the initial well and will turn over operations on the prospect to our partner. The operator has the option to drill a second well in which we will be carried for a 20% working interest.

We have entered into agreements and currently receive prospect fees and working interests on three of our California prospects.

In one of our prospects in the San Joaquin Basin of Southern California, exploratory drilling commenced during the fourth quarter of 2009. In mid-December, total depth of 2,400 feet was reached on this non-operated well in which we have a 33.3% carried working interest. The well encountered oil shows but not in quantities deemed economic to produce and this well was plugged and abandoned. We did not incur any exploration expense or dry well costs on this well. We are currently in discussions with the operator to determine how best to proceed in this area. The operator has approximately 150 days to propose another test well in which we will be carried for a 33.3% working interest.

     Nevada Project

As of December 31, 2009 we had a leasehold interest in approximately 115,762 gross (114,380 net acres) in eleven prospects within White Pine and Elko Counties Nevada. Two wells were drilled in this area during 2007, both were dry wells. We continue to pay leasehold rentals and geological expenses to preserve our acreage positions and are marketing these prospects to attract drilling partners for the development of this area.

Oil and Natural Gas Reserves

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 expand 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.

Accordingly, our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure at December 31, 2009 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2009 through December 2009, 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 $44.46 for oil and oil equivalents and $2.85 for gas. We do not believe that it is practicable to estimate the effect of applying the new rules for the changes in reserve quantities or the standardized measure of discounted cash flows for the year ended December 31, 2009.The amendments to the definition of oil and gas producing activities did not have an impact on our total proved reserves as of December 31, 2009.

     Company Reserve Estimates

Our proved reserve information as of December 31, 2009 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 20 “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 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 2009 through December 2009, 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, 2009 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 pre-tax present value of discounted future net cash flows (“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 $2.85 per Mcf of gas and $44.46 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, 2009 reserve estimates.

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

		Mcf of Gas				Bbls of Oil
Total Proved Reserve Quantities			44,229,950				450,858

		Proved Undeveloped				Proved Developed				Total
Present Value of Discounted Future Net Cash Flows (a)		$	0			$	35,561,400			$	35,561,400

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.

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. As of December 31, 2009, the present value of discounted future net cash flows 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.

The technical persons at NSAI 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 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.

										Oil and Gas
		Oil				Gas				Equivalent
Price Case		(MBbls)				(MMcf)				(Mmcfe)				PV 10
SEC pricing (a)			450.9				44,230				46,935			$	35,561,400
Scenario 1 (b)			485.7				46,022				48,936			$	42,919,000
Scenario 2 (c)			410.0				41,909				44,369			$	28,348,600

Volumes, Prices and Operating Expenses

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

		For the Years Ended December 31,
		2009				2008				2007
Natural gas production (Mcf)			4,274,849				4,583,028				4,011,978
Average sales price per Mcf		$	3.23			$	7.05			$	4.19
Oil production (Bbl)			42,151				42,545				41,454
Average sales price per Bbl		$	45.47			$	77.71			$	56.38
Equivalent production of oil and gas (Mcfe)			4,527,755				4,838,298				4,260,702
Expenses per Mcfe:
Lease operating		$	0.96			$	1.38			$	0.92
General and administrative		$	1.75			$	1.90			$	2.12
Depreciation, depletion and amortization		$	0.95			$	1.96			$	2.29
Impairment		$	9.06			$	0.72			$	22.79

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,
		2009				2008				2007
Property acquisition costs:
Unproved		$	647,721			$	624,815			$	35,578,808
Proved			—				—				2,496,100
Exploration costs			1,895,981				24,607,162				44,421,848
Development costs			2,486,858				11,758,219				—
Total		$	5,030,560			$	36,990,196			$	82,496,756

Productive Oil and Gas Wells

The following summarizes the Company’s productive and shut-in oil and gas wells as of December 31, 2009.

		Productive Oil and Gas
		Wells
		Gross				Net
Producing oil wells			13				12.8
Shut-in oil wells			2				2.0
Producing gas wells			116				64.8
Shut-in gas wells			1				1.0
			132				80.6

As of December 31, 2009, we operated 132 gross (77.6 net to our interest) producing wells and 3 gross (3 net) shut-in wells located on these properties.

Oil and Gas Acreage

The following table sets forth our undeveloped and developed leasehold acreage, by area as of December 31, 2009. 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.

		Undeveloped Acres								Developed Acres
		Gross				Net				Gross				Net
Utah			111,364				77,053				5,080				3,891
Wyoming			25,044				14,848				80				60
Nevada			115,762				114,380				—				—
California			24,996				18,492				—				—
Total acres			277,166				224,773				5,160				3,951

The following table summarizes the gross and net undeveloped acres by area that will expire in each of the next three years. The Company’s acreage positions are maintained by the payment of delay rentals or by the existence of a producing well on the acreage.

		Expiring in 2010								Expiring in 2011								Expiring in 2012
		Gross				Net				Gross				Net				Gross				Net
Utah			4,328				2,042				3,179				3,131				1,117				1,117
Wyoming			19,491				9,213				3,633				3,804				—				136
California			8,914				5,388				2,573				2,409				2,432				936
Nevada			—				—				—				—				—				—
Total			32,733				16,643				9,385				9,344				3,549				2,189

As of December 31, 2009, 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. The aggregate carrying value of our unproved acreage is approximately $38,600,000 as of December 31, 2009.

Drilling Activity

The following table sets forth our drilling activity during the years ended December 31, 2009, 2008 and 2007.

		For the Years Ended December 31,
		2009								2008								2007
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells:
Productive			2				0.8				6				2.5				23				10.1
Dry			—				—				—				—				—				—
Total wells			2				0.8				6				2.5				23				10.1
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, 2010. The average rent for this space over the life of the lease is approximately $151,200 per year. During February 2010, we extended our current lease through May 31, 2011 at an annual rate of approximately $165,600.

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 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. In a letter to the EPA dated January 23, 2008, Riverbend confirmed its willingness to sign a consent decree with the United States that resolves the apparent violations, specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that will effectively authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented. Riverbend has continued to work with the EPA and the Department of Justice on a settlement of this matter, and it anticipates that such a resolution will be achieved during 2010. Although we are unable to estimate a range of possible costs, we believe that all necessary pollution control and other equipment likely to be required by such a resolution is already installed at the

site or accounted for in our capital budget, and that any civil penalty that may be assessed in conjunction with a resolution of this matter will not materially affect our financial position or liquidity. The compliance costs could, however, materially affect our results of operations for a particular period.

Brek 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 alleges 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 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, was made on February 17, 2010, following this dismissal with prejudice.

ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

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

The Company’s common stock is traded on the NYSE Amex under the symbol “GSX.” As of March 3, 2010, the Company had 165 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
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
2008
First Quarter		$	2.80			$	1.80
Second Quarter			4.55				2.38
Third Quarter			4.35				1.44
Fourth Quarter			1.77				0.28

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.

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 balance sheet information below gives effect to the sale of materially all of the assets (the “Asset Sale”) comprising our gathering system and our evaporative facilities, which have been reflected as assets held for sale for all periods presented. See Note 4 “Assets Held for Sale” to the accompanying consolidated financial statements for further discussion. 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,
		2009				2008				2007				2006				2005
Summary of Operations
Gas revenue		$	13,801,679			$	32,328,579			$	16,818,623			$	19,851,663			$	13,462,977
Oil revenue			1,916,757				3,306,253				2,337,129				1,187,509				605,330
General & administrative expense			7,920,014				9,211,806				9,021,977				9,415,787				5,987,019
Impairment			41,000,000				3,500,000				97,090,000				51,000,000				—
Net income (loss)			(51,542,696	)			14,513,945				(104,373,921	)			(55,817,767	)			(37,635	)
Net income (loss) per share
Basic			(0.48	)			0.14				(1.12	)			(0.65	)			(0.00	)
Diluted			(0.48	)			0.13				(1.12	)			(0.65	)			(0.00	)

		As of December 31,
		2009				2008				2007				2006				2005
Balance Sheet
Working capital (deficit)		$	8,440,548			$	10,894,674			$	(9,330,209	)		$	11,129,942			$	86,078,958
Cash and cash equivalents			10,577,340				1,053,216				1,843,425				12,876,879				62,661,368
Property, plant and equipment, net			67,293,582				109,000,014				91,193,894				115,846,114				95,743,453
Total assets			104,741,713				153,885,508				122,511,789				165,454,418				201,199,972
Noncurrent liabilities			101,587,581				97,196,768				75,090,876				65,981,536				65,302,674
Stockholders’ equity (deficit)			(4,193,399	)			44,042,888				25,247,791				77,171,921				127,440,160

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 using technologies new to a specific area to generate and develop high-potential exploitation resources in this area. 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 those leases. We are currently focusing our drilling efforts in the Riverbend Project located in the Unita Basin of northeastern Utah, targeting the Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.

Recent Developments

     Sale of Gathering Assets

On February 26, 2010, we completed the sale (the “Closing”) of materially all of the assets (the “Asset Sale”) comprising our gathering system and our 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, we received total cash consideration of $23 million from Monarch, the entirety of which was used to repay amounts outstanding under our Credit Facility (defined below).

Pursuant to the Purchase Agreement, simultaneous with Closing we entered into (i) a transition services agreement with Monarch pursuant to which we will provide 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 we dedicated our 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 in the Asset Sale. These agreements will result in less revenue and additional costs with an aggregate annual impact, inclusive of a reduction in depreciation expense, of approximately $3.5 million based on 2009 activity. The Purchase Agreement is subject to customary post-closing terms and conditions for transactions of this size and nature.

     Acquisition of Petro-Canada

On February 25, 2010, we completed the acquisition of certain oil and gas leases and lands (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 include one producing well, one shut-in well with recompletion potential and 5,582 gross and net acres located in Utah west of our Gate Canyon operating area. We funded this acquisition with cash flow from operating activities.

     Amendment 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. Following the $23 million debt repayment, our available credit is approximately $4.0 million.

     Resignation of Former Chief Executive Officer; Appointment of Replacement

Effective January 27, 2010, our former Chief Executive Officer and President, Mark Erickson, resigned and was replaced by Charles Crowell as interim Chief Executive Officer and W. King Grant as President.

Impact of Current Credit Markets and Commodity Prices

The severe disruptions in the credit markets and reductions in global economic activity had significant adverse impacts on stock markets and oil and gas-related commodity prices, which contributed to a significant decline in our stock price and negatively impacted our future liquidity. We expect our liquidity will continue to be negatively affected in 2010 by the effects of this activity. The following discussion outlines the potential impacts that reduced commodity prices could have on our business, financial condition and results of operations.

     Reduced Cash Flows from Operations Could Impact Our Ability to Fund Capital Expenditures and Meet Working Capital Needs

Oil and gas prices have declined significantly since historic highs in July 2008. To mitigate the impact of lower commodity prices on our cash flows, we entered into commodity derivative instruments for 2009 through the first quarter of 2011 (see Note 5 “Derivatives” to the accompanying consolidated financial statements for further discussion). In the event that commodity prices stay depressed or decline further, our cash flows from operations would be reduced even taking into account our commodity derivative instruments for 2010 and 2011 and may not be sufficient when coupled with available capacity under our Credit Facility to meet our working capital needs or, in the event of a significant decline in commodity prices, fund our 2010 capital expenditure budget. This could cause us to alter our business plans, including further reducing our exploration and development plans.

We are operating under a preliminary capital budget subject to board approval for 2010 of $6 million which will be used primarily for the completion and recompletion projects on our existing wells. Based on current expectations, we intend to fund our budget entirely through cash flow from operations. Consequently, we will monitor spending and cash flow throughout the year and may accelerate or delay investment depending on commodity prices, cash flow expectations and changes in our borrowing capacity.

Effective February 26, 2010, our borrowing base under our Credit Facility was reduced to $16 million from $35 million and as of March 3, 2010, we had $11.5 million of outstanding borrowings thereunder. Our borrowing base could be further reduced in the future by our lenders. Though we anticipate funding our capital budget of $6 million for 2010 through cash flows from operations, an inability to access additional borrowings in excess of our existing $4 million of existing capacity under our Credit Facility will limit our ability to increase our operating budget and execute on our growth plans. The maturity of our Credit Facility and our outstanding $65 million 5.50% Convertible Senior Notes occur in March and October of 2011, respectively. The lenders under our Credit Facility may elect not to extend the maturity of such facility without our having previously refinanced, restructured or repaid the 5.50% Convertible Senior Notes due 2011. Accordingly, an inability to refinance, restructure or repay such convertible notes prior to their maturity on terms acceptable to us may impair our ability to execute on future growth plans. Furthermore, the failure to refinance, restructure or repay such convertible notes or our Credit Facility prior to their maturities may impair our ability to obtain alternate sources of financing. Any refinancing, restructuring or repayment could cause substantial dilution to our stockholders either through the issuance of additional equity or the sale of assets.

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.

     Reduced Cash Flows from Operations Could Result in a Default under Our Credit Facility and Convertible Senior Notes due 2011

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. As of December 31, 2009, our current and senior debt to EBITDAX ratios were 2.9:1.0 and 2.3:1.0, respectively, and we were in compliance with each of the covenants as of December 31, 2009. 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.

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 indenture governing our Convertible Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such Convertible Notes. 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 and may not be on terms acceptable to us.

     Reduced Commodity Prices Could Impact the Borrowing Base under Our Credit Facility

Our Credit Facility limits our borrowings to the borrowing base less our total outstanding letters of credit issued there under. As of December 31, 2009, we had loans of approximately $34.5 million outstanding under our Credit Facility and letters of credit in the amount of approximately $455,000 (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 indenture governing to our 5.50% Convertible Senior Notes due 2011 (the “Convertible Notes”). Should an event of default occur and continue under the indenture governing the Convertible Notes, the Convertible Notes may be declared immediately due and payable at their principal amount

together with accrued interest and liquidated damages, if any. 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, we may be forced into an involuntary reorganization in bankruptcy.

     Reduced Commodity Prices May Result in Ceiling Test Write-Downs and Other Impairments

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 (see Note 2 “Significant Accounting Policies-Oil & Gas Properties” to the accompanying consolidated financial statements for further discussion). Therefore, impairment expense relating to our ceiling test of $41,000,000 was recorded during the year ended December 31, 2009.

We may be required to further write down the carrying value of our gas and oil properties as a result of low gas and oil prices or if there are substantial downward adjustments to the estimated proved reserves, increases in the estimates of development costs or deterioration in the exploration results.

Investments in unproved properties are also assessed periodically to ascertain whether impairment has occurred. Our evaluation of impairment of unproved properties incorporates our expectations of developing unproved properties given current and forward-looking economic conditions and commodity prices. As discussed above, we reclassified approximately $1,100,000 and $200,000 of expiring acreage primarily in Utah and California, respectively into proved property. This reclassification represents the value of the leases that will expire during 2010 before we are able to develop them further. 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.

     Reduced Commodity Prices May Impact Our Ability to Produce Economically

Significant or extended price declines may 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. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

Amendments to Credit Facility

Our 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 the Guarantors and mortgages on substantially all of the Company’s oil and gas properties. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2011.

During May 2009, our Credit Facility was amended to among other things, (i) lower our borrowing base to $35,000,000 from $45,000,000; (ii) increase the interest rate pricing grid; (iii) amend the definition of LIBO Rate to include a floor of 2.00%; (iv) increase the required collateral coverage and the title requirement relating thereto; (v) require us to engage a financial consultant on or prior to May 29, 2009 and (vi) permit us to monetize our commodity hedges (as described in Note 2 of the accompanying financial statements) and use the proceeds to pay down a portion of the approximate $9,000,000 deficiency created by the reduced borrowing base. A special redetermination of our borrowing base on or

around June 30, 2009 was also added, in addition to the scheduled redeterminations and special redeterminations available at our request or the request of the lenders party thereto.

During July 2009, the Credit Facility was amended, among other things, to reschedule the special redetermination of our borrowing base on or about June 30, 2009 to on or about August 31, 2009.

During August 2009, the Credit Facility was further amended, among other things, to increase the interest rate pricing grid by 25 b.p. for Eurodollar based loans and for Alternate Base Rate (“ABR”) priced loans with respect to any periods in which we have utilized at least 90% of the borrowing base. Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies from 2.50% (for periods in which we have utilized less than 50% of the borrowing base) to 3.50% (for periods in which we have utilized at least 90% of the borrowing base). The alternate base rate 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 LIBO Rate for a one month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.50% (for periods in which we have utilized less than 50% of the borrowing base) to 2.50% (for periods in which we have utilized at least 90% of the borrowing base). We elect the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the Lenders may require us 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. This amendment also delayed the special redetermination of our borrowing base previously scheduled to occur on or about August 31, 2009, to on or about September 30, 2009.

During September 2009, the Credit Facility was further amended, among other things, to delay indefinitely the special redetermination of our borrowing base previously scheduled to occur on or about September 30, 2009, as discussed above. On October 30, 2009, the Credit Facility was further amended, among other things, to reschedule the scheduled mid-year redetermination of the borrowing base pursuant to Section 3.02 of the Credit Facility originally scheduled to occur on or about November 1, 2009 to on or about November 30, 2009. Pursuant to the Credit Facility, should there be a borrowing base deficiency after this scheduled mid-year redetermination on or about November 30, 2009, we were permitted 30 days to eliminate such deficiency.

During December 2009, the Credit Facility was amended, among other things, to revise the definition of “Redetermination Date” with respect to scheduled redeterminations for the year ended December 31, 2009 to be on our about May 1 of each year, thereby removing the scheduled redetermination previously scheduled to occur on or about November 30, 2009, and with respect to scheduled redeterminations for the year ended December 31, 2010 to be on our about January 30, May 1 and November 1 of such year. With respect to any scheduled redetermination in subsequent years, however, the Redetermination Date continues to be on or about May 1 and November 1 of each such year. Pursuant to this amendment, should there be a borrowing base deficiency after the scheduled redetermination on or about January 30, 2010. Additionally, the Credit Facility permitted us to terminate the engagement of our financial advisor effective November 29, 2009.

During February 2010, the Credit Facility was amended, among other things, (i) to remove the scheduled redetermination of our 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) to reduce our borrowing base to $16 million from $35 million in connection with the sale of our gas gathering system and water disposal facilities and the sale of our interest in certain oil and gas properties (collectively, the “Assets”). Pursuant to the amendment, the borrowing base would be reduced by a fixed amount upon the

consummation of each sale and, effective as of April 1, 2010, would be automatically reduced to $16 million, regardless of whether any of the Assets are sold.

This amendment also increased the interest rate pricing grid by 25 basis points for Eurodollar based loans and for ABR priced loans effective February as of 1, 2010. Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that, as amended, varies from 2.75% (for periods in which we have utilized less than 50% of the borrowing base) to 3.75% (for periods in which we have utilized at least 90% of the borrowing base). The alternate base rate, 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 LIBO Rate 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 we have utilized less than 50% of the borrowing base) to 2.75% (for periods in which we have utilized at least 90% of the borrowing base). This amendment further provides that if the borrowing base is greater than $16,000,000 on March 1, 2010, then effective on and after such date the interest rate pricing grid will automatically increase an additional by 25 basis points for Eurodollar based loans and for ABR priced loans. We elect the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the Lenders may require us 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. Additionally, this amendment provided for the release of certain liens relating to the Assets that secure our obligations under the Credit Facility.

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, we elected to reduce the borrowing base to $16 million effective immediately. Following the $23 million debt repayment, our available credit is approximately $4.0 million.

Asset Sales & Acquisitions

During June 2009, we sold our 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. We recognized a loss of $905,850 on the sale which is recorded in “Loss on sale of assets, net” in the accompanying consolidated financial statements (see Note 2 “Significant Accounting Policies – Facilities and Equipment” to the accompanying consolidated financial statements for further discussion).

On February 26, 2010, we completed the Asset Sale to Monarch pursuant to the Purchase Agreement. At Closing, we received total cash consideration of $23 million from Monarch, the entirety of which was used to repay amounts outstanding under our Credit Facility.

On February 25, 2010, we completed the acquisition of the “Petro-Canada Assets from 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 include one producing well, one shut-in well with recompletion potential and 5,582 gross and net acres located in Utah west of our Gate Canyon operating area. We funded this acquisition with cash flow from operating activities.

Notice from the NYSE Amex LLC

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. Our listing on the NYSE Amex is being continued pursuant to this extension through the extension period subject to certain conditions.

We will be subject to periodic review by the NYSE Amex during the extension period. There can be no assurance that we will be able to achieve compliance with Sections 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide within the required time frame. If we are not able to make progress consistent with our plan or to regain compliance with the continued listing standards by the end of the extension period, we will be subject to delisting procedures as set forth in the NYSE Amex Company Guide.

Drilling Activity

During 2009, we reached total depth on 2 gross wells (approximately 0.84 net wells), one of which was in progress at December 31, 2008, in the Riverbend area. We spudded one new well during 2009 and upon reaching total depth on this well, we released our remaining drilling rig. We did not conduct any initial completion operations. We re-entered three gross operated wells (0.92 net wells) to complete pay zones that were behind pipe. Additionally, we performed limited workover operations on certain Green River Formation oil wells to enhance oil production during the improved oil prices received during the last three quarters of 2009. As of December 31, 2009, we operated 132 gross producing wells. We currently have an inventory of 34 operated wells with up-hole recompletion opportunities and two Upper Mancos wells awaiting initial completion activities.

California Projects

As of December 31, 2009, we had a leasehold interest in approximately 24,996 gross acres (18,492 net acres) in Kern and San Luis Obispo Counties of Southern California. On one of our prospects in Kern County, we entered into a farm-out agreement with a large exploration and production company who has a considerable California operations presence. We received a prospect fee and will be carried for a 20% working interest on the initial well and will turn over operations on the prospect to our partner. The operator has the option to drill a second well in which we will be carried for a 20% working interest.

We currently have entered into agreements and received prospect fees and working interests on three of our California prospects.

In one of our prospects in the San Joaquin Basin of Southern California, exploratory drilling commenced during the fourth quarter of 2009. In mid-December, total depth of 2,400 feet was reached on this non-

operated well in which we have a 33.3% carried working interest. The well encountered oil shows but not in quantities deemed economic to produce and this well was plugged and abandoned. We did not incur any exploration expense or dry well costs on this well. We are currently in discussions with the operator to determine how best to proceed in this area. The operator has approximately 150 days to propose another test well in which we will be carried for a 33.3% working interest.

Summary of Capital Expenditures

The following table summarizes our capital expenditures during 2009 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		$	10,190,020
Cash spent for 2008 property costs that were accrued at 12/31/08			(3,560,000	)
Capital expenditures for 2009 projects		$	6,630,020
Lease acquisitions and related costs		$	647,721
Gathering system, facilities and equipment costs			1,444,917
Drilling, completion and recompletion activity			4,537,382
Capital expenditures for 2009 projects		$	6,630,020

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 expand 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 issued Accounting Standards Update (ASU) No. 2010-03 “Oil and Gas Reserve Estimation and Disclosure,” which aligns 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, 2009 using the average, first-day-of–the- month price during the 12-month period ending December 31, 2009. In prior years, we used the year-end price; therefore, reserve estimates for the year ended December 31, 2009 may not be directly comparable to those presented for prior periods. See Note 3 “Change in Method of Determining Oil and Gas Reserves” of the accompanying financial statements for further discussion. The following table

presents certain of our production information for each of the three years ended December 31, 2009 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,
		2009				2008				2007
Natural gas production (Mcf)			4,274,849				4,583,028				4,011,978
Average sales price per Mcf		$	3.23			$	7.05			$	4.19
Year-end estimated proved gas reserves (Mcf)			44,229,950				50,909,308				104,338,338
Oil production (Bbl)			42,151				42,545				41,454
Average sales price per Bbl		$	45.47			$	77.71			$	56.38
Year-end estimated proved oil reserves (Bbl)			450,858				361,185				1,070,802
Production (Mcfe)			4,527,755				4,838,298				4,260,702
Year-end estimated proved reserves (Mcfe)			46,935,098				53,076,418				110,763,150

Our oil and gas production decreased by approximately 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. During 2009 our proved reserve quantities decreased by approximately 13% primarily due to the production during 2009 and the decrease in gas prices used to estimate reserves 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 used to estimate our reserve quantities from $15.33 per barrel at December 31, 2008 to $44.46 per barrel at December 31, 2009.

Oil and gas production increased by approximately 14% during 2008 as compared with 2007 primarily due to the completion of 22 gross (7.3 net) new wells and the recompletion of 13 gross (6.4 net) existing wells during 2008. We elected to shut-in or curtail a portion of our daily production during October and the first part of November 2008 due to lower commodity prices. This curtailment as well as normal production declines partially offset our increased production during 2008. During 2008 our proved reserve quantities decreased by approximately 52% primarily due to the decrease in oil and gas prices used to estimate the reserves from $73.95 per barrel and $6.53 per Mcf at December 31, 2007 to $15.33 per barrel and $4.63 per Mcf at December 31, 2008. Also contributing to the decrease in reserve quantities was the sale of our interest in four gross producing (one net) wells during August 2008.

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 $15.33 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 $15.33 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.

The majority of the revisions of previous estimates during 2007 were primarily the result of an increase in proved undeveloped reserves due to the increase in oil and gas prices used to estimate the reserves from $45.53 per barrel and $4.47 per Mcf in 2006 to $73.95 per barrel and $6.53 per Mcf at December 31, 2007.

Reserve Quantities

		Gas				Oil
		Mcf				Bbls
Proved Reserves:
Balance, December 31, 2006			39,975,964				370,581
Extensions and discoveries			23,854,007				160,302
Revisions of previous estimates (a)			35,609,338				517,340
Sales of reserves in place			(681,007	)			(5,302	)
Purchases of reserves in place			9,592,014				69,335
Production			(4,011,978	)			(41,454	)
Balance, December 31, 2007			104,338,338				1,070,802
Extensions and discoveries			2,400,000				17,000
Revisions of previous estimates (b)			(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 (c)			(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

		Gas				Oil
		Mcf				Bbls
Proved Developed Reserves
Balance, December 31, 2009			44,229,950				450,858
Balance, December 31, 2008			50,909,308				361,185
Balance, December 31, 2007			50,820,623				695,019

Liquidity and Capital Resources

The borrowing base under our Credit Facility was reduced to $16,000,000 effective February 26, 2010. Additionally our Credit Facility provides for periodic and special borrowing base redeterminations which could further affect our available borrowing base. Please see “—Impact of Credit Market and Commodity Prices” above for a discussion of our liquidity and the impact of current market conditions thereon.

Sources and Uses of Funds

The following table summarizes our sources and uses of cash for each of the three years ended December 31, 2009, 2008 and 2007.

		For the Years Ended December 31,
		2009				2008				2007
Net cash provided by operating activities		$	16,247,177			$	18,152,640			$	8,883,728
Net cash used in investing activities			(10,268,022	)			(41,943,076	)			(48,096,453	)
Net cash provided by financing activities			3,544,969				23,000,227				28,179,271
Net cash flow			9,524,124				(790,209	)			(11,033,454	)

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. The increase in cash provided by operating activities from 2007 to 2008 is primarily due to the 86% increase in oil and gas revenue resulting from a 14% increase in production as well as an increase in oil and gas prices of $2.86 per Mcf and $21.33 per bbl during 2008.

Our investing activities during the three years ended December 31, 2009 related primarily to our development and exploration activities. In 2009 we had sales proceeds of $539,450 related to the sale of our drilling rig and certain other field equipment, in 2008 we had sales proceeds of $7,500,000 which represented the sale of a non-operated interest in four producing wells and in 2007 we had sales proceeds of $3,475,153 which represented the sale of a partial interest in two of our producing wells. We sold $6,000,000 of our short-term investments during 2007. The remaining investing activity during 2007 consisted of changes in our restricted investments.

During 2009, 2008 and 2007, our financing activity consisted primarily of borrowings and repayments under our Credit Facility. The activity in 2008 included $1,161,057 in proceeds from the exercise of options to purchase common stock. The 2007 activity included a public offering of 10,000,000 shares of our common stock for gross proceeds of approximately $19,300,000.

Monetization of Derivative Contracts

During May 2009, we monetized selected natural gas hedge contracts for net proceeds of $8,528,731. These proceeds were used to repay a portion of our outstanding borrowings under our Credit Facility as further described in Note 8 “Credit Facility” in the accompanying consolidated financial statements. Concurrent with the monetization of the hedges, we re-hedged a portion of our production for the period June 2009 through March 2011. The new derivative contracts were entered into at a weighted average price over the contract periods. We elected the weighted average price scenario for a portion of our natural gas volumes in an effort to secure the best prices for the 2009 contract period. See Note 5 “Derivatives” to the accompanying consolidated financial statements for further discussion.

Sales of Assets

During June 2009, we sold our 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. We recognized a loss of $905,850 on the sale which is recorded in “Loss on sale of assets, net” in the accompanying consolidated financial statements (see Note 2 “Significant Accounting Policies – Facilities and Equipment” to the accompanying consolidated financial statements for further discussion).

In February 2010, we completed the Asset Sale to Monarch pursuant to the Purchase Agreement. At Closing, we received total cash consideration of $23 million from Monarch, the entirety of which was used to repay the amounts outstanding under our credit facility.

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, 2009.

			Payments due by Period
																			More than
Contractual Obligations			Total				Less than 1 year				1–3 years				3–5 years				5 years
Convertible Notes
Principal			$	65,000,000			$	—			$	65,000,000			$	—			$	—
Interest				6,305,903				3,575,000				2,730,903				—				—
Credit Facility Principal	(a)			34,544,969				—				34,544,969				—				—
Operating leases	(b)			85,491				85,491				—				—				—
Employment & consulting Contracts	(c)			247,443				247,443				—				—				—
Asset retirement obligations	(d)			1,260,965				—				—				—				1,260,965
Total Contractual Cash Obligations			$	107,744,771			$	3,907,934			$	102,275,872			$	—			$	1,260,965

Forward Sales Contracts

During April 2009, we entered into a firm sales and transportation agreement to sell up to 50,000 MMBtu per day of our 2010 and 2011 gross production from the Uinta Basin. The contract 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 believe that we are not required to treat the contracts as derivatives and the contracts will not be marked to market because we anticipate that (1) we will produce the volumes required to be delivered under the terms of the contracts, (2) it is probable the delivery will be made to the applicable counterparty and (3) the applicable counterparty will fulfill its contractual obligations under the terms of the contracts.

Capital Budget

Based on current expectations, we intend to fund our 2010 capital expenditure program entirely through cash flow from operations. This program will focus primarily on completion and recompletion projects on our existing wells. Consequently, we will monitor spending and cash flow throughout the year and may accelerate or delay investment depending on commodity prices, cash flow expectations and changes in our borrowing capacity.

Credit Facility

The 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 the Guarantors and mortgages on substantially all of the Company’s oil and gas properties. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2011.

On February 1, 2010, we amended our Credit Facility to, among other things, (i) remove the scheduled redetermination of our 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 our borrowing base to $16 million from $35 million in connection with the contemplated sale of our gathering assets and the sale of our interest in certain oil and gas properties. The amendment provided that the borrowing base would be incrementally reduced by a fixed amount upon the consummation of each sale and, effective as of April 1, 2010, would be automatically reduced 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 sale of our gathering assets and the application of the proceeds therefrom to pay down outstanding borrowings, we elected to reduce the borrowing base to $16 million effective immediately. Following the $23 million debt repayment, our available credit is approximately $4.0 million. For further discussion of each amendment, see “Amendments to Credit Facility” in “Item 7 –Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The Credit Facility requires us to comply with financial covenants 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 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 our ability to incur other indebtedness, create

liens or sell our assets, pay dividends on our common stock and make certain investments. 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. 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 our obligation to repay indebtedness under the Credit Facility be accelerated, we would be in default under the indenture governing the Convertible Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes. To the extent it becomes necessary to address any anticipated covenant compliance issues, we 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, we may be required to sell a portion of our assets or issue additional securities, which would be dilutive to our shareholders. Any sale of assets or issuance of additional securities may not be on terms acceptable to us.

As of December 31, 2009, there were loans of $34,544,969 outstanding and letters of credit in the amount of $455,029 under the Credit Facility, which are considered usage for purposes of calculating availability and commitment fees.

As of December 31, 2009, our current and senior debt to EBITDAX ratios were 2.9:1.0 and 2.3:1.0, respectively, and we were in compliance with each of the covenants contained in the Credit Facility.

Convertible Notes

On October 20, 2004 (the “Issue Date”), we closed the private placement of $65,000,000 in aggregate principal amount of 5.50% Convertible Senior Notes due 2011 (the “Convertible Notes”) pursuant to an Indenture dated as of October 20, 2004 (the “Indenture”), between us and Wells Fargo Bank, National Association, as trustee. The amount sold consisted of $45,000,000 principal amount originally offered plus the exercise by the initial purchasers of their option to purchase an additional $20,000,000 principal amount. The Convertible Notes were sold only to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933.

The Convertible Notes are convertible into our common stock, $.0001 par value per share, at any time prior to maturity at a conversion rate of 250 shares of common stock per $1,000 principal amount of Convertible Notes (equivalent to a conversion price of $4.00 per share), which is subject to certain anti-dilution adjustments.

Interest on the Convertible Notes accrues from the most recent interest payment date, and is payable in cash semi-annually in arrears on April 5th and October 5th of each year, and commenced on April 5, 2005. Interest is payable to holders of record on March 15th and September 15th immediately preceding the related interest payment dates, and will be computed on the basis of a 360-day year consisting of twelve 30-day months.

We may, at our option, at any time on or after October 10, 2009, in whole, and from time to time in part, redeem the Convertible Notes on not less than 20 nor more than 60 days’ prior notice mailed to the holders of the Convertible Notes, at a redemption price equal to 100% of the principal amount of Convertible Notes to be redeemed plus any accrued and unpaid interest to but not including the redemption date, if the closing price of the common stock has exceeded 130% of the conversion price for at least 20 trading days in any consecutive 30 trading-day period.

Upon a “change of control” (as defined in the Indenture), each holder of Convertible Notes can require us to repurchase all of that holder’s notes 45 days after we give notice of the change of control, at a repurchase price equal to 100% of the principal amount of Convertible Notes to be repurchased plus accrued and unpaid interest to, but not including, the repurchase date, plus a make-whole premium under certain circumstances described in the Indenture.

The Convertible Notes are unsecured (except as described above) and unsubordinated obligations and rank on parity (except as described above) in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. The Convertible Notes effectively rank junior to any future secured indebtedness and junior to our subsidiaries’ liabilities. The Indenture does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of our securities or the incurrence of indebtedness.

Upon a continuing event of default, the trustee or the holders of 25% principal amount of a series of Convertible Notes may declare the Convertible Notes immediately due and payable, except that a default resulting from our entry into a bankruptcy, insolvency or reorganization will automatically cause all Convertible Notes under the Indenture to become due and payable.

The fair value of the Convertible Notes was $40,218,750 as of December 31, 2009, based on market quotes.

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, 2009, natural gas derivative instruments were comprised of two swap agreements for 2010 through March 2011 production. The fair value of the agreements was a current liability of $1,932,513 and a noncurrent liability of $761,092 as of December 31, 2009. The fair value of the agreements was a current asset of $8,855,947 as of December 31, 2008. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our economically hedged production. See further discussion in “Item 7A –Quantitative and Qualitative Disclosures about Market Risk”.

Critical Accounting Policies and Estimates

The preparation of the Company’s 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 the Company’s 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, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated

with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment would be recognized. Under the new rules, we prepared our 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 through September 30, 2009, we used the year-end price. Prior to December 31, 2009, subsequent commodity price increases could be utilized to calculate the ceiling value. See Note 3 “Change in Method of Determining Oil and Gas Reserves” to the accompanying consolidated financial statements for further discussion of changes in the ceiling test as of December 31, 2009. 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. 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.

Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the Securities and Exchange Commission (“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 decrease in prices used to estimate our reserve quantities as of December 31, 2009 of $0.10 per Mcf for natural gas and $1.00 per barrel of oil would result in a decrease in our December 31, 2009 present value of future net cash flows of approximately $2,427,400. 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. During 2009, we reclassified approximately $1,100,000 and $200,000 of expiring acreage primarily in Utah and California, respectively into proved property. This reclassification represents the value of the leases that will expire during 2010 before we are able to develop them further. Management believes that the current fair value is in excess of the carrying value of the remaining unproved property.

     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 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 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 derivative instruments of $(11,549,552), $9,199,706 and $(343,759) during the years ended December 31, 2009, 2008 and 2007, respectively.

As of December 31, 2009, the fair value of the agreements was a current liability of $1,932,513 and a non-current liability of $761,092. The fair value measurement of these 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 and our credit ratings. 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 10 “Fair Value Measurements” to the accompanying consolidated financial statements for further discussion.

Results of Operations

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.

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 netted against the transportation expense included in our lease operating costs) and the expenses incurred from the Riverbend area pipeline that we constructed during 2004 and 2005. The 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 is comprised of the lease payments received from a third party’s use of our drilling rig. Rental income is eliminated against the full cost pool when the rig is used to drill our operated wells and rental income is recognized when the rig is 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 as further described below.

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		$	3,712,279			$	4,998,412
Workover expense			65,099				163,728
Total operating expenses		$	3,777,378			$	5,162,140
Operating expenses per Mcfe		$	0.83			$	1.07
Production and property taxes		$	574,628			$	1,491,558
Production and property taxes per Mcfe		$	0.13			$	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 $1,384,762 decrease in operating expenses combined with a $916,930 decrease in production 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 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 $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.

Impairment expense during 2008 represents a reduction in the fair value of our drilling rig. Based upon an independent appraisal of our drilling rig, we believe 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 partially offset by losses resulting from a decrease in the market value of certain types of inventory (see Note 2 “Significant Accounting Policies-Facilities and Equipment” to the accompanying consolidated financial statements for further discussion).

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 further described in Note 18 – “Legal Proceedings” in 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 consists primarily of interest expense related to our outstanding Convertible Senior Notes which were issued on October 20, 2004 and borrowings under or existing line of credit. 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.

2008 Compared to 2007

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,
		2008				2007
Natural gas production (Mcf)			4,583,028				4,011,978
Average sales price per Mcf		$	7.05			$	4.19
Natural gas revenue		$	32,328,579			$	16,818,623
Oil production (Bbl)			42,545				41,454
Average sales price per Bbl		$	77.71			$	56.38
Oil revenue		$	3,306,253			$	2,337,129
Production (Mcfe)			4,838,298				4,260,702
Total oil and gas revenue		$	35,634,832			$	19,155,752

The increase in oil and gas revenue of $16,479,080 in 2008 compared to 2007 is comprised of a 14% increase in oil and gas production primarily due to the drilling and completion activity during 2008 and an increase of $2.86 per Mcf in the average gas price and an increase of $21.33 per Bbl in the average oil price during 2008. The production increase during 2008 was partially offset by our decision to curtail production on some of our existing wells during the fourth quarter due to low natural gas prices as discussed previously as well as normal production declines on wells drilled during earlier periods. The $16,479,080 increase in oil and gas revenue during 2008 represents an increase of $12,365,840 related to an increase in oil and gas prices and an increase of $4,113,240 related to increased oil and gas production.

Gathering Revenue and Expenses

Gathering income increased by $2,858,624 in 2008 as compared to 2007 due to the increased production resulting from our drilling activity in the Riverbend area. The increase in gathering expense of $985,948 during 2008 is primarily due to the addition of compression in early 2008, as well as increased operating expenses due to the production increase during 2008.

Rental Income

Rental income was comprised of the lease payments received from a third party’s use of the Company’s drilling rig. Rental income is eliminated against the full cost pool when the rig is used to drill Company operated wells and rental income is recognized when the rig is used to drill third-party wells. The rig has been used for drilling third party wells only since April 2007. The increase in this income during 2008 is due to the rig being used on third party wells for all of 2008 versus nine months of 2007.

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,
		2008				2007
Direct operating expenses and overhead		$	4,998,412			$	2,728,738
Workover expense			163,728				323,657
Total operating expenses		$	5,162,140			$	3,052,395
Operating expenses per Mcfe		$	1.07			$	0.72
Production and property taxes		$	1,491,558			$	880,529
Production and property taxes per Mcfe		$	0.31			$	0.20
Total lease operating expense per Mcfe		$	1.38			$	0.92

Lease operating expense increased $2,720,774 during 2008 compared with 2007. The increase was comprised of a $2,109,745 increase in operating expenses and a $611,029 increase in production taxes during 2008. The increase in operating expenses was primarily due to increased water disposal costs along with increased chemical treatment costs related to the transition from contract pumpers to Company pumpers as older wells were repaired and returned to production. Additionally, the number of producing wells increased from 112 gross wells in 2007 to 126 gross wells in 2008.

Depletion, Depreciation and Amortization

The decrease in depletion, depreciation and amortization expense of $303,823 during 2008 compared with 2007 was primarily due to a $97,090,000 reduction in the full cost pool due to the impairments recorded during the second quarter and third quarter of 2007, as described below, which resulted in a lower depletion base partially offset by an impairment of unproved properties and lower quantities of reserves during 2008. However, the decline in depletion, depreciation, and amortization resulting from the impairment was partially offset by an increase in oil and gas production and related capital costs resulting from our increased drilling and completion activity discussed above.

Impairment

Impairment expense during 2008 represents a reduction in the fair value of our drilling rig. In light of market conditions and lower commodity prices during 2008, many oil and gas companies cut back on their drilling plans for 2009. As a result, the demand for drilling rig services also declined. Based upon an independent appraisal of our drilling rig, we believe 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 impairment expense of $3,500,000 to reduce the carrying value of the rig.

Impairment expense of $97,090,000 during 2007 represents the impairments recorded as of June 30, 2007 and September 30, 2007 because the present value of our future net revenue discounted at 10% exceeded our full cost pool based on current oil and gas prices. As of June 30, 2007, oil and gas prices were $54.09 per barrel and $3.90 per mcf. Therefore, impairment expense of $64,300,000 was recorded during the quarter ended June 30, 2007. As of September 30, 2007, oil and gas prices were $0.345 per mcf and $62.29 per barrel. Our oil and gas reserves became uneconomic as the gas price on September 30, 2007 was less than our gathering costs to transport the gas to a sales point and would have resulted in an impairment of $65,620,000. However, subsequent to September 30, 2007, oil and gas prices increased; and using prices our full cost pool would have exceeded the above described ceiling by $32,790,000. Therefore, impairment expense of $32,790,000 was recorded during the quarter ended September 30, 2007.

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,
		2008				2007
Total general and administrative costs		$	7,519,064			$	7,004,761
General and administrative costs attributable to drilling, completion and operating activities			(1,410,256	)			(1,067,905	)
General and administrative expense		$	6,108,808			$	5,936,856
General and administrative expenses per Mcfe		$	1.26			$	1.40
Total stock-based compensation costs		$	3,134,024			$	3,131,406
Stock-based compensation costs capitalized			(31,026	)			(46,285	)
Stock-based compensation		$	3,102,998			$	3,085,121
Stock-based compensation per Mcfe		$	0.64			$	0.72
Total general and administrative expense Including stock-based compensation		$	9,211,806			$	9,021,977
Total general and administrative expense per Mcfe		$	1.90			$	2.12

General and administrative expense increased by $189,829 in 2008 as compared with 2007 primarily due to increased consulting fees associated with the preparation and analysis of our mid-year and year-end reserve reports during 2008.

Interest Expense

The increase in interest expense of $876,322 from 2007 to 2008 was primarily due to increased borrowings under our existing line of credit during 2008.

Derivative Gain (Loss)

The Company began hedging its production in December 2007 for 2008 and 2009 production. Derivative gains, net, during 2008 were $9,761,826. The gain was comprised of a realized net gain of $562,120 and an unrealized gain of $9,199,706 during 2008. The derivative loss during 2007 was a noncash expense representing the recording of the fair value of a natural gas swap agreement that was entered into during December 2007.

Interest Income

Interest income decreased $392,951 in 2008 compared with 2007 primarily due to lower average cash and cash equivalent balances during 2008 resulting from our investment in oil and gas properties.

Recent Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued “FASB Accounting Standards Codification^™ (“Codification”), as the single source of authoritative US GAAP” for all non-governmental entities, with the exception of the SEC and its staff. The Codification, which became effective July 1, 2009, changes the referencing and organization of accounting guidance and was effective for interim and annual periods ending after September 15, 2009. We adopted the Codification on July 1, 2009 which provides for changes in references to technical accounting literature (if used) in this Annual Report on Form 10-K and subsequent reports, but did not have a material impact on the our financial position, results of operations or cash flows.

In June 2009, the FASB issued new accounting guidance related to the accounting and disclosures of subsequent events. This guidance incorporates the subsequent events guidance contained in the auditing standards literature into authoritative accounting literature. It also requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. This guidance was effective for all interim and annual periods ending after June 15, 2009. We adopted this guidance upon its issuance and it had no material impact on our consolidated financial statements. We evaluate subsequent events up to immediately prior to the issuance of its consolidated financial statements, and for purposes of the accompanying consolidated financial statements, We have evaluated subsequent events through March 3, 2010, the filing date of this 10-K, and have disclosed such items in Note 8 “Credit Facility,” Note 15 “Commitments,” Note 18 “Legal Proceedings” and Note 21 “Subsequent Events” in the accompanying consolidated financial statements.

In August 2009, the FASB issued new accounting guidance to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. This guidance became effective for us on October 1, 2009. We adopted this guidance on October 1, 2009, and it had no material impact on the consolidated financial statements.

Please refer to the earlier disclosure for Derivatives, Note 3 “Change in Method of Determining Oil and Gas Reserves” and Note 10 “Fair Value Measurements” for additional information on the recent adoption of new authoritative accounting guidance.

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, 2009, the off-balance sheet arrangements and transactions that we had entered into included undrawn letters of credit, operating lease 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 currently or in the future.

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, 2009, our derivative instruments consisted of two swap agreements for our 2010 through March 2011 production. The fair market values of these agreements were a 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 hedged production. Our derivative contracts are described below:

•

For our swap instruments, we receive a fixed price for the hedged commodity and pays 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.

Our swap agreements for 2010 through March 2011 are summarized in the table below:

Remaining

Fixed Price

Floating Price (a)

Agreement Type

Term

Quantity

Counterparty payer

Gasco payer

Swap (b)

1/10 — 12/10

3,500 MMBtu/day

$4.418/MMBtu

NW Rockies

Swap

1/10 — 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

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.

Interest Rate Risk

We do not currently use interest rate derivatives to mitigate our exposure, including under our revolving credit facility, to the volatility in interest rates.

ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm			69-70
Consolidated Balance Sheets at December 31, 2009 and 2008			71-72
Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007			73
Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2009, 2008 and 2007			74
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007			75
Notes to Consolidated Financial Statements			76-118

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, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended. 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, 2009 and 2008, and the results of its operations and its cash flows for the years then ended 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, 2009, 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 3, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Denver, Colorado
March 3, 2010

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
Gasco Energy, Inc.

We have audited the consolidated balance sheet of Gasco Energy, Inc. and subsidiaries as of December 31, 2007 (not separately included herein), and the related consolidated statements of income, retained earnings and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our 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 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 audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Gasco Energy, Inc. and subsidiaries as of December 31, 2007, and the results of their operations and their cash flows for each of the year ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

/s/ Hein & Associates LLP
HEIN & ASSOCIATES LLP

Denver, Colorado
February 29, 2008

GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS

		December 31,
		2009				2008
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	10,577,340			$	1,053,216
Accounts receivable
Joint interest billings			857,405				5,436,636
Revenue			2,979,726				3,827,950
Inventory			1,019,913				4,177,967
Derivative instruments			—				8,855,947
Prepaid expenses			292,421				188,810
Total			15,726,805				23,540,526
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved properties			254,682,870				247,976,854
Unproved properties			38,638,936				39,280,348
Wells in progress			—				644,688
Facilities and equipment			971,890				3,696,785
Furniture, fixtures and other			333,049				371,605
Total			294,626,745				291,970,280
Less accumulated depletion, depreciation, amortization and impairment			(227,291,163	)			(182,970,266	)
Total			67,335,582				109,000,014
Assets held for sale, net of accumulated depreciation			20,155,544				19,712,565
Total			87,491,126				128,712,579
NON-CURRENT ASSETS
Deposit			139,500				139,500
Note receivable			500,000				—
Deferred financing costs			884,282				1,492,903
			1,523,782				1,632,403
TOTAL ASSETS		$	104,741,713			$	153,885,508

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

GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)

		December 31,
		2009				2008
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable		$	1,110,259			$	5,879,150
Revenue payable			2,245,545				3,840,985
Advances from joint interest owners			—				612,222
Derivative instruments			1,932,513				—
Accrued interest			844,108				1,187,495
Accrued expenses			1,215,106				1,126,000
Total			7,347,531				12,645,852
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes			65,000,000				65,000,000
Long-term debt			34,544,969				31,000,000
Derivative instruments			761,092				—
Asset retirement obligation related to assets held for sale			206,595				187,238
Asset retirement obligation			1,054,370				962,941
Deferred rent expense			20,555				46,589
Total			101,587,581				97,196,768
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDERS’ EQUITY (DEFICIT)
Series B Convertible Preferred stock — $.001 par value; 20,000 shares authorized; zero shares outstanding			—				—
Common stock — $.0001 par value; 300,000,000 shares authorized; 107,789,597 shares issued and 107,715,897 shares outstanding as of December 31, 2009; 107,825,998 shares issued and 107,752,298 shares outstanding as of December 31, 2008			10,780				10,783
Additional paid-in-capital			221,327,256				219,375,369
Accumulated deficit			(225,401,140	)			(175,212,969	)
Less cost of treasury stock of 73,700 common shares			(130,295	)			(130,295	)
Total			(4,193,399	)			44,042,888
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)		$	104,741,713			$	153,885,508