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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

For the fiscal Year Ended December 31, 2008


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 (IRS Employer Identification No)


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

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

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


Title of each class COMMON STOCK, $00001 PAR VALUE		Name of each exchange on which registered NYSE ALTERNEXT US LLC

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

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



Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o (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, 2008, approximately 107,788,309 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 $418,263,676 based on a closing price of $4.15 per share, which was the closing price per share on June 30, 2008. As of March 4, 2009, 107,752,298 shares of Common Stock, par value $0.0001 per share were outstanding.

Documents incorporated by reference:

Certain information required by Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2008 annual meeting of stockholders to be filed within 120 days of December 31, 2008.

PART I

ITEM 1 — BUSINESS

Business of Gasco

Gasco is a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. 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 drilling efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations. As of December 31, 2008, we held interests in 330,923 gross acres (214,483 net acres) located in Utah, Wyoming, California and Nevada. As of December 31, 2008, we held an interest in 126 gross producing wells (7.73 wells, net to our interest) and 5 shut-in wells (5.0 net) located on these properties.

During 2008, we spudded 14 gross operated wells (5.3 net) and reached total depth on 13 gross operated wells (4.9 net) in the Riverbend Project Initial completion operations were conducted on 22 operated wells (7.3 net) and we re-entered thirteen gross operated wells (6.4 net) to complete pay zones that were behind pipe. We have completed 18 wells in the Mancos shale interval since we began targeting the Mancos in mid-2007. We currently have two Mancos shale wells awaiting initial completion. As of December 31, 2008, we operated 125 gross producing wells We currently have an inventory of 30 operated wells with up-hole completion potential and two wells awaiting initial completion activities.

Gasco was incorporated on April 21, 1997 under the laws of the State of Nevada. The Company operated as a “shell” company until December 31, 1999.

Principal Products or Services and Markets

Gasco focuses its 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 the Company’s 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, 2008, 2007 and 2006: Anadarko Petroleum Corporation (“Anadarko”) during 2008 and ConocoPhillips during 2007 and 2006. However, Gasco does not believe that the loss of a single purchaser, including Anadarko or ConocoPhillips, would materially affect the Company’s business because there are numerous other potential purchasers in the areas in which Gasco sells its production. For the years ended December 31, 2008, 2007 and 2006, purchases by the following companies exceeded 10% of the total oil and gas revenues of the Company.


	For the Years Ended December 31,
	2008			2007			2006
Revenues associated with ConocoPhillips purchases	$	7,537,841		$	15,272,000		$	19,777,000
Revenues associated with Anadarko purchases	$	24,406,071			—			—
Percentage of oil and gas revenues attributable to:
ConocoPhillips		21	%		80	%		94	%
Anadarko		68	%		—			—

Rockies natural gas prices continued their lower trend during the fourth quarter of 2008. These low prices are due in part to gas-on-gas sales competition in the Rockies resulting from the region’s capacity to produce natural gas exceeding the take-away capacity of interstate pipelines that move the natural gas to other consuming regions in the United States as well. As a result of the low natural gas prices received, we elected to shut-in or curtail a portion of our daily production from some of our existing gas wells during the fourth quarter of 2008. Late in the fourth quarter of 2008 when natural gas prices increased, we brought the curtailed production back on line. As we have in prior periods, we continue to manage a portion of our sales volumes to maximize our realized prices by strategically curtailing production during the shoulder months heading into the winter heating season.

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

The Company’s 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, Gasco competes with a number of other companies operating in its 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,” Gasco is required to obtain drilling and right of way permits for its wells, and there is no assurance that such permits will be available timely or at all.

The prices of the Company’s products are controlled by 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. Gasco, and projects in which it participates, is 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.

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 once 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”), a wholly owned subsidiary of the Company, that was preparing air emission calculations for possible future capacity expansions, preliminarily determined that Riverbend may have not accurately calculated the amount of air pollutants that could be emitted from certain existing equipment at its Riverbend Compressor Station in Uintah County. Utah Riverbend thereafter undertook a more detailed assessment, which confirmed that Riverbend had not obtained certain air permits nor complied with certain air pollution regulatory programs that were applicable to its operations at the Riverbend Compressor Station. On June 22, 2007, Riverbend sent a letter to the United States Environmental Protection Agency (“EPA”) Region 8 office in Denver, Colorado, which—because the Riverbend Compressor Station is located in Indian Country—is the agency that has jurisdiction over federal air permitting and air pollution regulatory programs. Riverbend’s June 22 letter voluntarily disclosed the potential violations to EPA and informed the agency of the steps that Riverbend had taken and planned to take to achieve compliance. In November 2007, Riverbend met with EPA Region 8 personnel and discussed the disclosed violations, its plans to bring the Riverbend Compressor Station into compliance, and possible resolution of the disclosed violations. In a letter to 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 EPA and the Department of Justice on a settlement of this matter, and it anticipates that such a resolution will be achieved during 2009. Riverbend believes 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 the Company’s capital budget, and that any civil penalty that may be assessed in conjunction with a resolution of this matter will not materially affect the Company’s financial position.

In response to certain 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, President Obama has expressed support for, and it is anticipated that the current session of Congress will consider, legislation to restrict or regulate emissions of greenhouse gases. In addition, 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. Depending on the particular program, we could be required to purchase and surrender allowances for greenhouse gas emissions resulting from our operations.

Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile

sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. 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 even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. 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 new federal, regional or state restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business 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.

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 2009 and will potentially allow us to drill approximately 1,500 wells in the development phase. The estimated cost of the EIS is expected to be approximately $500,000. 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 4, 2009, Gasco had 37 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 those discussed under the caption “Risk Factors”.

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;

	•		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.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this annual report 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 hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

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 hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well.

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 pretax 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 prices 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 well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

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. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production responses that increased recovery will be achieved.

Proved oil and gas reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (b) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil, natural gas and natural gas liquids that may occur in undrilled prospects; and (d) crude oil, natural gas and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved properties. Properties with proved reserves.

Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves may not include estimates attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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 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 year-end prices, 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 intention 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 commercial 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

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

Historically, other than for the year ended December 31, 2008, our operations have not generated sufficient operating 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, 2007 and 2006, we incurred a net loss of $104,373,921 and $55,817,767, respectively. As of December 31, 2008, we had an accumulated deficit of $175,212,969. 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. Recent declines in commodity prices have 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 bank credit facility and through the capital markets. The amount available for borrowing under our revolving bank 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. The recent 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 continue to decline in 2009, 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.

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 have previously announced a reduced 2009 capital expenditures budget 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 2008, the previous oil and gas reserves quantities decreased by approximately 42% primarily due to the decrease in oil and gas prices from $73.95 per barrel and $6.53 per mcf at December 31, 2007 to $15.33 per barrel and $4.63 per mcf at December 31, 2008. 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 2008 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 currently 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 obtain adequate financing to continue our operations.

We will require significant additional capital to fund our future activities and to service current and any future indebtedness. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to 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 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.

government. During the fourth quarter of 2008, 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 are expected to negatively impact our future liquidity. 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 our oil and gas exploration and production activities. We may also have less access to borrow capital if our borrowing base is reduced by our lenders. 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. Furthermore, we may be required to repay amounts outstanding under our revolving bank credit facility if we are unable to service our debt or if we default under our revolving bank credit facility for a failure to satisfy our required financial ratios or other covenants thereunder.

Lower oil and natural gas prices could negatively impact our ability to borrow. Additionally, availability under our revolving bank 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 bank credit facility.

Our revolving bank credit facility limits our borrowings to the borrowing base less our total outstanding letters of credit issued thereunder. Currently, our borrowing base is $45.0 million and our outstanding letter of credit sublimit is $10.0 million. Under the terms of our revolving bank 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 April 2009. If our borrowing base is reduced as a result of a redetermination, we may be required to repay a 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 bank 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 agreement, which could adversely affect our business, financial condition and results or operations. Please read “Item 7 — Management’s Discussion and Analysis of Financial Position and Results of Operations — Liquidity and Capital Resources — Credit Agreement.”

Financial difficulties encountered by lenders under our revolving bank credit facility, our partners or third-party operators could adversely affect our financial condition and results of operations.

In light of the current financial turmoil, we are exposed to some credit risk related to our revolving bank credit facility to the extent that our lenders may be unable to provide necessary funding to us under our revolving bank credit facility if they experience liquidity problems. If our lenders are unable to provide funding in accordance with their commitment, our ability to meet our current and long term needs could be adversely impacted and our operations could be negatively impacted.

Additionally, liquidity and cash flow problems encountered by our partners or the co-owners of our properties may prevent or delay the drilling of a well or the development of a project. Our partners and working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farm-out partner being unwilling or unable to share such costs, we would have to find a new farm-out partner or obtain alternative funding in order to complete the exploration and development of the prospects subject to the farm-out agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farm-out partner. If any of these circumstances were to occur, our ability to explore and develop our prospects, including unproved properties with a carrying value of approximately $39,000,000 as of December 31, 2008, could be adversely affected, which could have a material adverse effect on our business, financial condition and results of operations.

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

Our revolving bank 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 bank credit facility contains 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 1:1; 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 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, 2008, our current and senior debt to EBITDAX ratios were 1.7:1 and 1.4:1, respectively, and we were in compliance with each of the covenants as of December 31, 2008 through March 4, 2009. Any failure to be in compliance with any material provision or covenant of our revolving bank credit facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under our revolving bank credit facility. Additionally, should our obligation to repay indebtedness under our revolving bank 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. EBITDAX will be reduced for the four quarters beginning with the quarter ended March 31, 2009 by the expected payment of approximately $4.6 million (as calculated at $12,000/day from rig release through March 15, 2010, the expiration date of the contract) for early termination of our drilling contract (and rig release) in February 2009, resulting in a corresponding reduction in the levels of senior debt that we may have outstanding going forward without violating our senior debt to EBITDAX ratio. 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 bank 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.

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. During the fourth quarter of 2008, we curtailed a portion of its natural gas production due to the low price for natural gas that prevailed in the Rockies. These low prices were due in part to gas-on-gas sales competition resulting from the region’s capacity to produce natural gas exceeding the take-away capacity of interstate pipelines that move the natural gas to other consuming regions in the United States. 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 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. 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 eight years as of December 31, 2008, 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, 2008. 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.

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 prices and costs on the date of the 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 current 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.

Investments in unproved properties with a carrying value of approximately $39,000,000 as of December 31, 2008, 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.

We own a drilling rig which had a carrying value of approximately $5,500,000. In light of the current market conditions and the lower commodity prices, many oil and gas companies have cut back on their drilling plans for 2009. As a result, the demand for drilling rig services has also declined. Based upon an independent appraisal of our drilling rig, we believe that the market value of our drilling rig has decreased to approximately $2,000,000 as of December 31, 2008 and for that reason we have recorded impairment expense of $3,500,000.

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 18 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 15 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. As 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, 2008 was an asset of approximately $8,855,947. 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. Erickson, our Chief Executive Officer; Mr. Decker, our Executive Vice President and Chief Operating Officer; and Mr. Grant, our Executive Vice President and Chief Financial 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 officers and directors are engaged in other businesses which may result in conflicts of interest.

Certain of our officers and 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 Galaxy Energy Corporation (“Galaxy”) and Exxcel Energy. Mr. Bruner also serves as the Chairman and Chief Operating Officer of Falcon Oil and Gas, Ltd. (“Falcon”). Falcon’s current drilling activities include projects in Romania and Hungary. Carl Stadelhofer, one of our directors, is a director of Falcon. In addition, another of our directors and Audit Committee Chairman, C. Tony Lotito, currently serves as the Executive Vice President and a member of the Board of Directors of PetroHunter Corporation (“PetroHunter”), which is majority owned by Mr. Bruner. Charles Crowell, one of our directors, is the Chief Executive Officer and President and serves as the Chairman of the Board of Directors of PetroHunter. Mr. Crowell also serves on the Boards of Directors of Providence Resources, Inc. 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 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. We estimate that all of its directors spend approximately 10% of their time on our business. Mr. Erickson has direct private investments in certain Rocky Mountain and Mid-Continent oil and gas leases and has a majority interest in a private oil and gas company lease holdings in Colorado, Wyoming, North Dakota and Utah. Mr. Erickson is also a co-majority shareholder in a

private company engaged in the exploration of non-oil and gas mineral resources in the Republic of Guinea, Africa. Mr. Erickson spends 100% of his 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.

Two of our directors reside outside the United States and maintain a substantial portion of their 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.

Risks Related to Our Capital Stock

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; 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, 2008, we had 107,752,298 shares of common stock issued and outstanding and outstanding options to purchase an additional 11,124,788 shares of common stock. Additional options may be granted to purchase 2,251,442 shares of common stock under our stock option plan and an additional 292,150 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 124,002,298 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 outstanding revolving bank 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 123,568 gross acres in the Uinta Basin of northeastern Utah, of which we hold interests in approximately 83,915 net acres as of December 31, 2008. Historically, our engineering and geologic focus has been concentrated on three tight-sand formations in the Uinta basin: the Wasatch, Mesaverde 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 the second quarter of 2007, we spudded our first Mancos Shale test well and since then we have drilled and completed 18 wells in the Mancos Shale, two of which have tested the Dakota Formation.

in mid-2007. We currently have two Mancos shale wells awaiting initial completion. As of December 31, 2008, we operated 125 gross producing wells. We currently have an inventory of 30 operated wells with up-hole recompletion opportunities and two wells awaiting initial completion activities.

Given the decline in commodity prices and the weak global economic projections for 2009, we have revised our capital expenditure program to be in line with our expected internally generated cash flow from operations. The revised expenditure program includes the drilling and completion of two gross (0.84 net) wells and the performance of a limited number of re-completions during 2009. At year end, we were operating a single drilling rig. This rig was released in late February 2009. At rig release, we were obligated to make a cash payment of $4,600,000 to terminate the drilling lease prior to its original expiration date of March 15, 2010. As we plan to drill only two gross (0.84 net) new wells during 2009, we reclassified approximately $1,250,000 and $750,000 of expiring acreage primarily in Utah and California, respectively, into proved property. This acreage represents the leases that will expire during 2009 before we are able to develop it further.

Consistent with the our stated goal of divesting of certain non-core assets, during the third quarter 2008 we sold to the operator our interest in four gross producing wells (one net producing well), leasehold and proven reserves in the Prickly Pear Field in the West Tavaputs area of the Uinta Basin. Proceeds from the divestiture were $7.5 million with an effective date of August 21, 2008. The sale included, as of December 31, 2007, approximately 640 gross acres (160 net acres) with 6.0 Bcfe of proven reserves, of which approximately 1.7 Bcfe was developed. The sale represents approximately 1.0 million cubic feet per day of net production, or approximately 7% of our daily net production at the time of the sale. Prickly Pear field wells produce primarily from the Wasatch and Mesaverde formations.

During the third quarter of 2007 we entered into a definitive agreement with a subsidiary of NFR whereby the subsidiary of NFR (“NFR”) participated in a 30-well drilling program, of which 29 wells have been drilled, in our Riverbend Project through the second quarter of 2008. The terms of the agreement allowed for NFR to earn two-thirds of our interest in each 40-acre drilling location, 100 feet below total depth drilled, in exchange for paying its share of costs, including a per-well location fee paid to Gasco as the operator of the project. NFR participated in the drilling of an additional four wells beyond the initial 30 well program. All four wells were drilled as of December 31, 2008. Three of the four wells have been completed and are flowing to sales and one remains to be completed.

On December 14, 2007, we closed the previously announced purchase of Brek Energy Corporation (“Brek”). As a result of this acquisition, Gasco acquired approximately 17,000 net acres in the Uinta Basin of Utah, approximately 7,200 net acres in the Green River Basin of Wyoming and additional working interests in ten producing properties in which Gasco was already the operator and holds working interests. The acquisition simplified Gasco’s acreage portfolio by absorbing a working interest partner that previously owned approximately 14% of Gasco’s undeveloped acreage in Utah and Wyoming. Gasco did not incur any additional overhead expenses as a result of the acquisition. In connection with the acquisition, Gasco issued 10,999,868 shares of its common stock to Brek’s shareholders. The shares of common stock issued to Brek shareholders were valued at $2.76 per share, which was the average value of the

Company’s common stock for two days before and after the merger agreement was signed. The total purchase price of the Brek Acquisition was $30,749,300.

Greater Green River Basin Project

As of December 31, 2008, the Company has a leasehold interest in approximately 66,291 gross (40,474 net) acres in the Greater Green River Basin area of Wyoming. The acreage covers two prospects identified by Gasco.

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 approximately $6,230,000 of unproved leasehold costs related to our Wyoming acreage to proved property during the second quarter of 2007. We continue to pursue many options for this area such as farm-outs, acreage sales and partners to participate in any future drilling projects in this area.

Southern California Project

The Company has a leasehold interest in approximately 18,655 gross acres (14,750 net acres) in Kern and San Luis Obispo Counties of Southern California. During 2008, we reclassified approximately $750,000 of expiring acreage into proved property. This acreage may expire in 2009 before we are able to develop it further. We plan to continue to pay leasehold rentals and geological expenses to preserve our remaining acreage positions and are marketing these prospects to attract drilling partners for the development of this area.

Nevada Project

The Company has a leasehold interest in approximately 122,409 gross (75,344 net acres) in eleven prospects within White Pine and Elko Counties Nevada. Two wells were drilled in this area during 2007, both were dry holes. 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.

Company Reserve Estimates

The tables below set forth information as of December 31, 2008 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. All of the Company’s proved reserves are located within the state of Utah.


	Mcf of Gas		Bbls of Oil
Total Proved Reserve Quantities		50,509,308		361,185


	Proved		Proved
	Undeveloped		Undeveloped		Total
Present Value of Discounted Future Net Cash Flows (a)	$	0	$	69,482,800	$	69,482,800


(a)		Present value of discounted future net cash flows represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at December 31, 2008. The average prices weighted by production over the lives of the proved reserves used in the reserve report prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, were of $4.63 per Mcf of gas and $15.33 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, 2008 reserve estimates. These prices should not be interpreted as a prediction of future prices.

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, 2008, 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.


	OIL
Change in Price	10% decrease		$15.33/bbl		10% increase
GAS
10% increase	$	80,286,200	$	80,560,200	$	80,847,800
	53,978 mmcfe		54,085 mmcfe		54,181 mmcfe
$4.63/Mcf	$	69,213,700	$	69,482,800	$	69,776,100
	52,788 mmcfe		53,076 mmcfe		53,019 mmcfe
10% decrease	$	58,185,200	$	58,454,500	$	58,737,700
	50,976 mmcfe		51,104 mmcfe		51,230 mmcfe

Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. The following table summarizes the changes in the reserve quantities and in the PV 10 value of our reserves under different pricing scenarios.

No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission.

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,
	2008		2007		2006
Natural gas production (Mcf)		4,583,028		4,011,978		3,686,638
Average sales price per Mcf	$	7.05	$	4.19	$	5.38
Oil production (Bbl)		42,545		41,454		21,646
Average sales price per Bbl	$	77.71	$	56.38	$	54.86
Equivalent production (Mcfe)		4,838,298		4,260,702		3,816,514
Expenses per Mcfe:
Lease operating	$	1.38	$	0.92	$	0.92
General and administrative	$	1.90	$	2.12	$	2.47
Depreciation, depletion and amortization	$	1.96	$	2.29	$	2.86
Impairment	$	0.72	$	22.79	$	13.36

Development, Exploration and Acquisition Capital Expenditures

During the years ended December 31, 2008, 2007 and 2006, we incurred $36,990,196, $82,496,756 and $87,270,883 in development and exploration activities, respectively. We entered into a 30-well drilling program with NFR in our Riverbend Project through the second quarter of 2008, as discussed previously. Twenty-nine of the thirty wells have been drilled. The terms of the agreement allowed for NFR to earn two-thirds of our interest in each 40-acre drilling location, 100 feet below total depth drilled, in exchange for paying its share of costs, including a per-well location fee paid to Gasco as the operator of the project. NFR participated in the drilling of an additional four wells beyond the initial 30 well program. All four wells were drilled as of December 31, 2008. Three of the four wells have been completed and are flowing to sales and one remains to be completed.

During 2007, we completed the Brek Acquisition, as described previously, and as a result acquired approximately 17,000 net acres in the Uinta Basin of Utah, approximately 7,200 net acres in the Green River Basin of Wyoming and additional working interests in ten producing properties in which Gasco was already the operator and holds working interests.

During 2006, we completed a property acquisition of approximately 21 miles of mainline gathering pipelines and working interests in 24 oil and gas wells in the Uinta Basin of Utah for $4,875,000.

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,
	2008		2007		2006
Property acquisition costs:
Unproved	$	624,815	$	35,578,808	$	1,285,289
Proved		—		2,496,100		2,563,862
Exploration costs		24,607,162		44,421,848		75,523,006
Development costs		11,758,219		—		7,898,7262

Total	$	36,990,196	$	82,496,756	$	87,270,883

Productive Oil and Gas Wells

The following summarizes the Company’s productive and shut-in oil and gas wells as of December 31, 2008. Productive wells are producing wells and wells capable of production. Shut-in wells are wells that are capable of production but are currently not producing. Gross wells are the total number of wells in which the Company has an interest. Net wells are the sum of the Company’s fractional interests owned in the gross wells.


	Productive Oil and Gas
	Wells
	Gross		Net
Producing oil wells		13		12.8
Shut-in oil wells		2		2.0
Producing gas wells		113		64.5
Shut-in gas wells		3		3.0

		131		82.3

As of December 31, 2008, we operated 125 gross (77.3 net to Gasco’s interest) producing wells and 5 gross (5 net) shut-in wells located on these properties.

Oil and Gas Acreage

The following table sets forth the undeveloped and developed leasehold acreage, by area, held by the Company as of December 31, 2008. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. Developed acres are acres which are spaced or assignable to productive wells. Gross acres are the total number of acres in which Gasco has a working interest. Net acres are the sum of Gasco’s fractional interests owned in the gross acres. The table does not include acreage that the Company has a contractual right to acquire or to earn through drilling projects, or any other acreage for which the Company has not yet received leasehold assignments. In certain leases, the Company’s 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 Gasco’s ownership in the primary objective formation.


	Undeveloped Acres				Developed Acres
	Gross		Net		Gross		Net
Utah		118,568		80,006		5,000		3,909
Wyoming		66,211		40,414		80		60
Nevada		122,409		75,344		—		—
California		18,655		14,750		—		—


Total acres		325,843		210,514		5,080		3,969

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 2009				Expiring in 2010				Expiring in 2011
	Gross		Net		Gross		Net		Gross		Net
Utah		9,877		2,672		1,464		1,326		3,179		3,131
Wyoming		21,938		11,731		1,056		1,051		1,936		1,932
California		5,855		5,147		8,191		6,018		2,517		2,511
Nevada		1,440		288		—		—		—		—


Total		39,110		19,838		10,711		8,395		7,632		7,574

As of December 31, 2008, 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 15 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 the Company’s acreage located on federal lands is delayed significantly by the permitting process, the Company 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 $39,000,000 as of December 31, 2008.

Drilling Activity

The following table sets forth the Company’s drilling activity during the years ended December 31, 2008, 2007 and 2006. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by the Company’s working interest.


	For the Years Ended December 31,
	2008				2007				2006
	Gross		Net		Gross		Net		Gross		Net

Exploratory Wells:
Productive		6		2.5		23		10.1		22		22
Dry		—		—		—		—		1		1

Total wells		6		2.5		23		10.1		23		23


Development Wells:
Productive		8		2.8		—		—		4		4
Dry		—		—		—		—		—		—

Total wells		8		2.8		—		—		4		4

Office Space

The Company leases 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.

ITEM 3 — LEGAL PROCEEDINGS

In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), a wholly owned subsidiary of the Company, that was preparing air emission calculations for possible future capacity expansions, preliminarily determined that Riverbend may have not accurately calculated the amount of air pollutants that could be emitted from certain existing equipment at its Riverbend Compressor Station in Uintah County, Utah. Riverbend thereafter undertook a more detailed assessment, which confirmed that Riverbend had not obtained certain air permits nor complied with certain air pollution regulatory programs that were applicable to its operations at the Riverbend Compressor Station. On June 22, 2007, Riverbend sent a letter to the United States Environmental Protection Agency (“EPA”) Region 8 office in Denver, Colorado, which—because the Riverbend Compressor Station is located in Indian Country—is the agency that has jurisdiction over federal air permitting and air pollution regulatory programs. Riverbend’s June 22 letter voluntarily disclosed the potential violations to EPA and informed the agency of the steps that Riverbend had taken and planned to take to achieve compliance. In November 2007, Riverbend met with EPA Region 8 personnel and discussed the disclosed violations, its plans to bring the Riverbend Compressor Station into compliance, and possible resolution of the disclosed violations. In a letter to 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 EPA and the Department of Justice on a settlement of this matter, and it anticipates that such a resolution will be achieved during 2009. Riverbend believes 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 the

Company’s capital budget, and that any civil penalty that may be assessed in conjunction with a resolution of this matter will not materially affect the Company’s financial position.

On December 5, 2008, a lawsuit was filed in state court in Cook County, Illinois. The lawsuit alleges that Defendants Richard N. Jeffs, Marc Bruner and Gasco Energy, Inc. through its agency with Mr. 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 Gasco in December of 2007. Gasco 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. Gasco intends to vigorously defend the claims filed against it. The parties have not yet engaged in discovery. A scheduling conference has been set for March 25, 2009. Given the early stage of the proceedings, we have not yet formed an opinion as to the likelihood of an unfavorable outcome or any estimate of the amount or range of potential loss.

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 Alternext US LLC under the symbol “GSX.” As of March 4, 2009, the Company had 170 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 forseable future. Furthermore, Gasco’s revolving bank credit facility contains covenants that restrict the payment of dividends.

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 American Stock Exchange for the periods reflected.


	High		Low
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

2007
First Quarter	$	2.65	$	1.50
Second Quarter		2.75		1.73
Third Quarter		2.69		1.78
Fourth Quarter		2.60		1.62

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 Gasco’s financial position and results of operations as the dates indicated. 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,
	2008		2007			2006			2005			2004
Summary of Operations Gas revenue	$	32,328,579	$	16,818,623		$	19,851,663		$	13,462,977		$	2,928,689
Oil revenue		3,306,253		2,337,129			1,187,509			605,330			195,199
General & administrative expense		9,211,806		9,021,977			9,415,787			5,987,019			4,191,978
Impairment		3,500,000		97,090,000			51,000,000			—			—
Net income (loss)		12,513,945		(104,373,921	)		(55,817,767	)		(37,635	)		(4,205,830	)
Net income (loss) per share
Basic		0.14		(1.12	)		(0.65	)		(0.00	)		(0.07	)
Diluted		0.13		(1.12	)		(0.65	)		(0.00	)		(0.07	)


	As of December 31,
	2008		2007			2006		2005		2004
Balance Sheet
Working capital (deficit)	$	10,894,674	$	(9,330,209	)	$	11,129,942	$	86,078,958	$	52,719,245
Cash and cash equivalents		1,053,216		1,843,425			12,876,879		62,661,368		25,717,081
Property, plant and equipment, net		128,712,579		107,676,102			129,652,008		100,464,395		48,731,851
Total assets		153,885,508		122,511,789			165,454,418		201,199,972		117,368,168
Noncurrent liabilities		97,196,768		75,090,876			65,981,536		65,302,674		65,108,566
Stockholders’ equity		44,042,888		25,247,791			77,171,921		127,440,160		46,213,198

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

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

Gasco is 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. The operations of Brek are included in our results of operations for all periods subsequent to December 14, 2007.

Recent Developments

Impact of Current Credit Markets and Commodity Prices

The credit markets and the financial services industry have been experiencing a period of upheaval characterized by the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the United States federal government. During the fourth quarter of 2008, 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 are expected to negatively impact our future liquidity. The following discussion outlines the potential impacts that the current credit markets and 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 and continue to decline since the end of the year. Further, the decline in commodity prices has outpaced the decline in the prices of goods and services that we use to drill, complete and operate our wells, reducing our cash flow from operations. To mitigate the impact of lower commodity prices on our cash flows, we have entered into commodity derivative instruments for 2008 and 2009 (see Note 2 of the accompanying consolidated financial statements). 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 2009 and may not be sufficient when coupled with available capacity under our $250 million Credit Agreement (the “Credit Agreement”) to meet our working capital needs or fund our initial 2009 capital expenditure budget. This could cause us to alter our business plans, including reducing our exploration and development plans.

Given the decline in commodity prices and the weak global economic projections for 2009, the Board of Directors approved a revised capital budget of $10,000,000. 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. At year end we were operating a single drilling rig. This rig was released in late February 2009, which will significantly reduce our fixed commitments in 2009 and in subsequent periods. At rig release, we were obligated to pay the rig contractor approximately $4.6 million for early termination of the drilling contract (as calculated at $12,000/day from rig release through March 15, 2010, the expiration date of the contract).

Additionally, as we plan to drill only two gross (0.84 net) new wells during 2009, we reclassified approximately $1,250,000 and $750,000 of expiring acreage primarily in Utah and California, respectively into proved property. This reclassification represents the value of the leases that will expire during 2009 before we are able to develop them further. Our operational plans for 2009 will focus on those limited completion and recompletion projects that we believe will generate and lay the foundation for production growth.

Through our actions such as reducing our 2009 capital expenditure budget, investing our cash balances conservatively and releasing our single drilling rig from operation, we believe that we have adequate liquidity from our expected cash flow and available credit to continue our operations through 2009. Furthermore, we remain focused on our goal of divesting non-core assets, such as our sale of four gross producing wells (one net) during the third quarter of 2008. However, if we need additional liquidity for future activities, 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 Commodity Prices Could Impact the Borrowing Base under Our Credit Agreement

Our Credit Agreement limits our borrowings to the borrowing base less our total outstanding letters of credit issued thereunder. Currently, our borrowing base is $45.0 million and our outstanding letter of credit sublimit is $10.0 million. Under the terms of our Credit Agreement, 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 April 2009, and based on the decline of commodity prices, we believe it will be reduced. If our borrowing base is reduced as a result of a redetermination, we may be required to repay a 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 Credit Agreement, sell assets or additional shares of common stock or reduce our capital budget. 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 Credit Agreement, which would materially adversely affect our business, financial condition and results or operations.

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

Our Credit Agreement 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 Agreement), 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 Credit Agreement 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, 2008, our current and senior debt to EBITDAX ratios were 1.7:1 and 1.4:1, respectively, and we were in compliance with each of the covenants as of December 31, 2008 through March 4, 2009. 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. Additionally, at current commodity prices, EBITDAX will be reduced for the four quarters beginning with the quarter ended March 31, 2009 by the expected payment of approximately $4.6 million for early termination of our drilling contract in February 2009, resulting in a corresponding reduction in the levels of senior debt that we may have outstanding going forward without violating our senior debt to EBITDAX ratio.

Any failure to be in compliance with any material provision or covenant of our Credit Agreement could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under our Credit Agreement. Additionally, should our obligation to repay indebtedness under our Credit Agreement 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. 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.

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

We may be required to 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, including capitalized interest costs, are also assessed periodically to ascertain whether impairment has occurred.

We own a drilling rig that had a carrying value of approximately $5,500,000. In light of the current market conditions and the lower commodity prices, many oil and gas companies have cut back on their drilling plans for 2009. As a result, the demand for drilling rig services has also

declined. Based upon an independent appraisal of our drilling rig, we believe that the market value of our drilling rig has decreased to approximately $2,000,000 as of December 31, 2008 and for that reason we have recorded impairment expense of $3,500,000.

As discussed above, since we plan to drill only two (0.84 net) new wells during 2009, we reclassified approximately $1,250,000 and $750,000 of expiring acreage primarily in Utah and California, respectively into proved property. This reclassification represents the value of the leases that will expire during 2009 before we are able to develop them further.

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.

Drilling Activity

During 2008, we spudded 14 gross wells (approximately 5.3 net wells) and reached total depth on 13 gross wells (approximately 4.9 net wells) in the Riverbend area. Thirteen of the wells were drilled to the Upper Mancos shale and one well was drilled to the Upper Morrison Formation. We also conducted initial completion operations on 22 gross operated wells (7.3 net wells) and re-entered 13 gross operated wells (6.4 net wells) to complete pay zones that were behind pipe. We have completed 18 wells in the Mancos shale interval since we began targeting the Mancos in mid-2007. We currently have four Mancos shale wells awaiting initial completion. As of December 31, 2008, we operated 125 gross producing wells. We currently have an inventory of 30 operated wells with up-hole recompletion opportunities and four wells awaiting initial completion activities.

The following table summarizes our capital expenditures during 2008 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	$	44,250,250
Cash spent for 2007 property costs that were accrued at 12/31/07		(6,688,799	)

Capital expenditures for 2008 projects	$	37,561,451


Lease acquisitions and related costs	$	624,815
Gathering system, facilities and equipment costs		2,369,918
Drilling, completion and recompletion activity		34,566,718

Capital expenditures for 2008 projects	$	37,561,451

Production and Reserve Information

The following table presents certain of the Company’s production information for each of the three years ended December 31, 2008 and our estimated proved reserves as of December 31 of each year presented. The Mcfe calculations assume a conversion of 6 Mcf’s for each Bbl of oil.


	For the Years Ended December 31,
	2008		2007		2006
Natural gas production (Mcf)		4,583,028		4,011,978		3,686,638
Average sales price per Mcf	$	7.05	$	4.19	$	5.38
Year-end estimated proved gas reserves (Mcf)		50,909,308		104,338,338		39,975,964

Oil production (Bbl)		42,545		41,454		21,646
Average sales price per Bbl	$	77.71	$	56.38	$	54.86
Year-end estimated proved oil reserves (Bbl)		361,185		1,070,802		370,581

Production (Mcfe)		4,838,298		4,260,702		3,816,514
Year-end estimated proved reserves (Mcfe)		53,076,418		110,763,150		42,199,450

Our 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. The natural gas prices in the Rockies continued their lower trend into the fourth quarter of 2008 and for that reason we elected to shut-in or curtail a portion of our daily production during October and the first part of November. 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 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.

Our oil and gas production increased by approximately 12% during 2007 as compared with 2006 primarily due to our drilling and completion of 23 gross (10.1 net) wells during 2007. The production increase was partially offset by our decision to curtail production due to low gas prices during the third and fourth quarters of 2007. During 2007, the oil and gas reserve quantities increased by approximately 162% primarily due to the increase in oil and gas prices used to estimate the reserves from $45.53 per barrel and $4.47 per Mcf at December 31, 2006 to $73.95 per barrel and $6.53 per Mcf at December 31, 2007. Additionally, the completion of the merger with Brek Energy Corporation increased proved reserves by approximately 10.0 Bcfe. At December 31, 2007, our oil and gas reserves were 94% natural gas of which 50% are developed.

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.

Liquidity and Capital Resources

Please see “— Recent Developments — Impact of Credit Market and Commodity Prices” above for a discussion of our liquidity and the impact of current market conditions thereon.

Capital Budget

Our Board of Directors has approved a revised initial 2009 capital budget of $10,000,000. We have reduced our budget by $20,000,000 from our preliminary budget presented in November 2008. The change in plans is a direct result of the further weakening in commodity prices, high service costs for drilling and completing wells and limited capital markets. The revised program includes completing of one well, the drilling and completion of approximately two gross (0.84 net) wells and 12 recompletions (4 net) of up-hole zones on our Riverbend Project located in the Uinta Basin of Utah. The wells in the program will be drilled to develop the natural-gas-bearing upper Mancos shale intervals and associated up-hole pay zones in each wellbore. The budget does not include possible acquisitions, but may include installation of pipeline infrastructure, distribution facilities and certain geophysical operations.

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 and cash flow expectations. At year end we were operating a single drilling rig. This rig was released in late February 2009, which will significantly reduce our fixed commitments in 2009 and in subsequent periods. At rig release, we were obligated to pay the rig contractor approximately $4.6 million for early termination of the drilling contract (as calculated at $12,000/day from rig release through March 15, 2010, the expiration date of the contract).

Sources and Uses of Funds

The following table summarizes our sources and uses of cash for each of the three years ended December 31, 2008, 2007 and 2006.


	For the Years Ended December 31,
	2008			2007			2006
Net cash provided by operating activities	$	18,152,640		$	8,883,728		$	8,882,955
Net cash used in investing activities		(41,943,076	)		(48,096,453	)		(60,017,463	)
Net cash provided by financing activities		23,000,227			28,179,271			1,350,019
Net cash flow		(790,209	)		(11,033,454	)		(49,784,489	)

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 $21.33 per bbl and $2.86 per Mcf during 2008. Cash provided by operations during 2007 and 2006 remained fairly consistent primarily due to a 12% production increase offset by a 22% decline in gas prices from 2006 to 2007. The production increases in 2008 and 2007 were due to drilling activity.

Our investing activities during the three years ended December 31, 2008 related primarily to our development and exploration activities. 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 had no property sales during 2006. We sold $6,000,000 and $9,000,000 of our short-term investments during 2007 and 2006, respectively. The remaining investing activity during 2007 and 2006 consisted primarily of changes in our restricted investments.

During 2008 and 2007, our financing activity consisted primarily of borrowings and repayments under our Credit Agreement. 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. Our financing activities during 2006 were comprised mainly of proceeds from the exercise of common stock options partially offset by cash paid for offering costs and preferred dividends.

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, 2008.


			Payments due by Period
			Less than						More than
Contractual Obligations	Total		1 year		1-3 years		3-5 years		5 years
Convertible Notes
Principal	$	65,000,000	$	—	$	65,000,000	$	—	$	—
Interest		9,880,903		3,575,000		6,305,903		—		—
Credit Agreement Principal		31,000,000		—		31,000,000		—		—
Drilling rig contracts (a)		8,904,000		7,665,000		1,239,000		—		—
Operating leases		1,040,840		955,349		85,491		—		—
Employment & consulting contracts		839,282		839,282		—		—		—
Asset retirement obligations (b)		1,150,179		—		—		—		1,150,179

Total Contractual Cash Obligations	$	117,815,204	$	13,034,631	$	103,630,394	$	—	$	1,150,179


(a)		The three year drilling contract for the new-build rig contains a provision for the Company to terminate the contract prior to lease expiration for payments of $12,000 per day for the number days remaining in the original contract. Subsequent to December 31,


		2008, we expect to pay approximately $4,600,000 to terminate this contract prior to its expiration date.

(b)		The accuracy and timing of the asset retirement obligations cannot be precisely determined in advance. See further discussion in Note 2 of the accompanying consolidated financial statements.

Credit Agreement

On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered the Credit Agreement. Borrowings made under the Credit Agreement are guaranteed by our subsidiaries, and are secured by a pledge of the capital stock of such subsidiaries and mortgages on substantially all of our oil and gas properties.

The initial aggregate commitment of the lender under the Credit Agreement is $250,000,000, subject to a borrowing base which was increased from $40,000,000 as of December 31, 2007 to $45,000,000 during April 2008. The Credit Agreement also provides for a $10,000,000 sublimit for letters of credit which we may use for general corporate purposes. The Credit Agreement was amended in December 2008. The $45,000,000 borrowing base was maintained and the original maturity date was extended one year to March 29, 2011. The Credit Agreement provides for semi-annual evaluation of the borrowing base, which will be determined as a percentage of the discounted present value of the Company’s oil and natural gas reserves, and is subject to redetermination in April 2009. Additionally, the lenders thereunder may request an additional borrowing base redetermination between each semi-annual calculation.

As of December 31, 2008, there were loans of $31,000,000 outstanding at an average interest rate of 3.23% and letters of credit in the amount of $6,703,000 which are considered usage for purposes of calculating availability and commitment fees. As of March 4, 2009, there were loans of $31,000,000 outstanding and letters of credit in the amount of $6,703,000. Our aggregate borrowings and outstanding letters of credit under the Credit Agreement may not at any time exceed the borrowing base.

In connection with the December 2008 amendment, the interest rate pricing grid was increased 0.25% to the levels detailed below and the commitment fee was changed to 0.50% from a variable grid between 0.30% and 0.50%. Additionally, Guarantee Bank and Trust Company was added as a Lender to the Credit Agreement and is currently committed for $5.0 million of the $45.0 million borrowing base. The other commercial terms were substantially unchanged by the amendment. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2011. Interest on borrowings under the Credit Agreement accrues at variable interest rates at either, at our election, a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies from 1.50% (for periods in which we have utilized less than 50% of the borrowing base) to 2.25% (for periods in which we have utilized greater than 90% of the borrowing base). The alternate base rate is calculated as (1) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.50% or (c) the adjusted Libo Rate for a one month interest period on such day plus 1.00%, plus (2) an applicable margin that varies from 0.25% (for periods in which we have utilized less than 50% of the borrowing base) to 1.00% (for periods in which we have utilized greater than 90% of the borrowing base). We elect the basis of the interest rate at the time of each borrowing; however, under certain

circumstances, our lender may require us to use the non-elected basis in the event the elected basis does not adequately and fairly reflect the cost of making such loans. In addition, we are obligated to pay a commitment fee under the Credit Agreement quarterly in arrears based on 0.50% of unused commitments.

The Credit Agreement 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 Agreement divided by current liabilities excluding the current portion of the Credit Agreement), determined at the end of each quarter, of not less than 1:1; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Agreement) for the most recent four quarters not to be greater than 3.5:1 for each fiscal quarter. In addition, the Credit Agreement 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, 2008, our current and Senior Debt to EBITDAX ratios were 1.7:1 and 1.4:1, respectively, and we were in compliance with each of the covenants as of December 31, 2008 and March 4, 2009. Any failure to be in compliance with any material provision or covenant of the Credit Agreement could result in a default which, absent a waiver or amendment, would require immediate repayment of outstanding indebtedness under our Credit Agreement Additionally, should our obligation to repay indebtedness under our Credit Agreement 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. EBITDAX will be reduced for the four quarters beginning with the quarter ended March 31, 2009 by the payment of approximately $4.6 million for early termination of our drilling contract in February 2009, resulting in a corresponding reduction in the levels of senior debt that we may have outstanding going forward without violating our senior debt to EBITDAX ratio. 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 Agreement from the lenders thereunder, 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. 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. Any waiver or amendment may result in an increase in the interest rate pricing grid under the Credit Agreement. Please see “Item 1A — Risk Factors — Our revolving bank credit facility imposes restrictions on us that may affect our ability to successfully operate our business.”

Convertible Notes

On October 20, 2004 (the “Issue Date”), we closed the private placement of $65,000,000 in aggregate principal amount of its 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 a 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 is $39,081,250 as of December 31, 2008, based on market quotes.

Forward Sales Contract

For our 2008 and 2009 production, we entered into a firm sales and transportation agreement to sell 30,000 MMBtu per day of our gross production from the Uinta Basin. During the first quarter of 2008, 18,000 MMBTU per day of such amount was contracted at the CIG first of

month price and the remaining 12,000 MMBtu per day was priced at the NW Rockies first of month price. Beginning in the second quarter of 2008, the entire contracted amount was based on NW Rockies first of month price. We have elected the normal purchase and sale exemption under paragraph 10(b) of Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” because we anticipate that (1) we will produce the volumes required to be delivered under the terms of the contract, (2) it is probable the delivery will be made to the counterparty and (3) the counterparty will fulfill its contractual obligations under the terms of the contracts. As such, we believe we are not required to treat the contract as a derivative and the contract will not be marked to market under the provisions of SFAS No. 133.

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, 2008, natural gas derivative instruments were comprised of two swap agreements and one costless collar agreement for 2009 production. The fair market 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”.

Stock Offering

On April 13, 2007, Gasco issued 10,000,000 shares of common stock in a public offering for gross proceeds of $19,300,000. The offering costs associated with this transaction were $120,729. Gasco used the net proceeds from the offering for general corporate purposes.

Drilling Program

During 2007, we entered into a 30-well drilling program, of which 29 wells have been drilled, in our Riverbend Project through the second quarter of 2008, as discussed previously. The terms of the agreement allowed for NFR to earn two-thirds of our interest in each 40-acre drilling location, 100 feet below total depth drilled, in exchange for paying its share of costs, including a per-well location fee paid to Gasco as the operator of the project. During 2008, NFR participated in the drilling of an additional four wells beyond the initial 30 well program. All four wells were drilled as of December 31, 2008. Three of the four wells have been completed and are flowing to sales and one remains to be completed.

Acquisition

On December 14, 2007, we closed the previously announced purchase of Brek Energy Corporation (“Brek”). As a result of this acquisition (the “Brek Acquisition”), Gasco acquired approximately 17,000 net acres in the Uinta Basin of Utah, approximately 7,200 net acres in the Green River Basin of Wyoming and additional working interests in ten producing properties in which Gasco was already the operator and holds working interests. The acquisition simplified

Gasco’s acreage portfolio by absorbing a working interest partner that previously owned approximately 14% of Gasco’s undeveloped acreage in Utah and Wyoming. Gasco has not incurred any additional overhead expenses as a result of the acquisition.

In connection with the acquisition, Gasco issued 10,999,868 shares of its common stock to Brek’s shareholders. The shares of common stock issued to Brek shareholders were valued at $2.76 per share, which was the average value of the Company’s common stock for two days before and after the merger agreement was signed. The total purchase price of the Brek Acquisition was $30,749,300.

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.

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 price of $0.10 per Mcf for natural gas and $1.00 per barrel of oil would result in a decrease in our December 31, 2008 present value of future net cash flows of approximately $5,458,600. 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 Gasco. 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 Gasco, calculation of depletion expense and the ceiling test analysis. During 2008, we reclassified approximately $1,250,000 and $750,000 of expiring acreage primarily in Utah and California, respectively into proved property as we do not plan to drill any new wells during 2009. This reclassification represents the value of the leases that will expire during 2009 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.

We currently own a drilling rig that has a carrying value of approximately $5,500,000. In light of the current market conditions and the lower commodity prices, many oil and gas companies have cut back on their drilling plans for 2009. As a result, the demand for drilling rig services has also declined. Based upon an independent appraisal of our drilling rig, we believe that the market value of our drilling rig has decreased to approximately $2,000,000 as of December 31, 2008 and for that reason we have recorded impairment expense of $3,500,000.

Stock-Based Compensation

We account for stock option grants and restricted stock awards in accordance with SFAS No. 123(R), “Accounting for Stock-Based Compensation.” which requires companies to recognize 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 under SFAS 123(R). 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

During 2007 and 2008, we 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 account for our derivatives and hedging activities under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133, we are required to record our derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in current earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. Management has decided not to use cash flow hedge accounting for our derivatives. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair market value are recognized in earnings. We recorded an unrealized gain on derivative instruments of $9,199,706 during the year ended December 31, 2008.

As of December 31, 2008, we had a net derivative asset of $8,855,947, of which $2,644,534 was measured based upon our valuation model and, as such, is classified as a Level 3 fair value measurement. We value these Level 3 contracts using a model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors (d) notional quantities (e) current market and contractual prices for the underlying instruments and (f) the counterparty’s and the Company’s 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. Please see Note 10, “Fair Value Measurements.”

Results of Operations

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 in the average gas price of $2.86 per Mcf 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 the 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 the 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 revenue and expense represents the income earned from the third party working interest owners in the wells we operate (our share of gathering revenue is eliminated against the transportation expense included in our lease operating costs) and the expenses incurred from the Riverbend area pipeline that we constructed during 2004 and 2005. The 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 described above.

Rental Income

Rental income is 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.

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 is 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 is 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

Depletion, depreciation and amortization expense is comprised of depletion expense related to our oil and gas properties, depreciation expense of gathering assets, facilities and equipment, furniture, fixtures and equipment and accretion expense related to the asset retirement obligation. The decrease in depletion, depreciation and amortization expense of $303,823 during 2008 is primarily due to the $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 affected by the impairment of unproved properties and the lower quantities of reserves during 2008. However, the decline in depletion, depreciation, and amortization resulting from the impairment is partially offset by the 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 the reduction in the fair value of our drilling rig. In light of the current market conditions and the lower commodity prices, many oil and gas companies have cut back on their drilling plans for 2009. As a result, the demand for drilling rig services has also declined. Based upon an independent appraisal of our drilling rig, we believe that the market value of our drilling rig has decreased from its carrying value of $5,500,000 to approximately $2,000,000 as of December 31, 2008. Therefore we have 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 impairment 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 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 quarter end, oil and gas prices increased; and using these 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

Interest expense during 2008 and 2007 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 $876,322 is 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 is comprised of a realized net gain of $562,120 and an unrealized gain of $9,199,706. Realized derivative gains, net, represent the net settlement due to us from our counterparty based on each month’s settlement during the quarter. Unrealized gains represent the change in mark to market values for each active commodity hedge contract. 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.

2007 Compared to 2006

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,
	2007		2006
Natural gas production (Mcf)		4,011,978		3,686,638
Average sales price per Mcf	$	4.19	$	5.38
Natural gas revenue	$	16,818,623	$	19,851,663

Oil production (Bbl)		41,454		21,646
Average sales price per Bbl	$	56.38	$	54.86
Oil revenue	$	2,337,129	$	1,187,509

Production (Mcfe)		4,260,702		3,816,514
Total oil and gas revenue	$	19,155,752	$	21,039,172

The decrease in oil and gas revenue of $1,883,420 in 2007 compared to 2006 is comprised of a decrease in the average gas price of $1.19 per Mcf partially offset by an increase of $1.52 per Bbl in the average oil price during 2007 and a 12% increase in oil and gas production primarily due to the drilling and completion activity during 2007 and 2006. The production increase during 2007 was partially offset by our decision to curtail production on some of our existing wells due to the low natural gas prices as discussed previously as well as normal production declines on wells drilled during earlier periods. The $1,883,420 decrease in oil and gas revenue during 2007 represents a decrease of $4,367,423 related to the decrease in gas prices partially offset by the increase in oil prices and by an increase of $2,484,003 related to increased 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 eliminated 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 decreased by $3,274 in 2007 as compared to 2006 due to the decreased production on wells in which third parties had a working interest. The decrease in gathering expense of $246,712 during 2007 is primarily due to a revision in the methodology for calculating charges related to compressor fuel during 2006.

Rental Income

Rental income during 2007 represents the revenue from the rental of our drilling rig to outside operated wells in which we do not have an ownership interest.

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,
	2007		2006
Direct operating expenses and overhead	$	2,728,738	$	2,367,488
Workover expense		323,657		368,954

Total operating expenses	$	3,052,395	$	2,736,442

Operating expenses per Mcfe	$	0.72	$	0.72


Production and property taxes	$	880,529	$	777,126

Production and property taxes per Mcfe	$	0.20	$	0.20


Total lease operating expense per Mcfe	$	0.92	$	0.92

Lease operating expense increased $419,356 during 2007 compared with 2006. The increase is comprised of a $315,913 increase in operating expenses primarily due to the increase in producing wells from 81 gross wells in 2006 to 112 gross wells in 2007. The net increase in lease operating expense is due to a $103,403 increase in production and property taxes, partially offset by decreased workover expense of $45,297 due to a decrease in the number of workover projects during 2007.

Depletion, Depreciation and Amortization

Depletion, depreciation and amortization expense during 2007 is comprised of depletion expense related to our oil and gas properties, depreciation expense of gathering assets, facilities and equipment, furniture, fixtures and equipment and accretion expense related to the asset retirement obligation. The depletion, depreciation and amortization expense decrease of $1,104,930 is primarily due to the $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 results in a lower depletion base. However, the decline in depletion, depreciation, and amortization resulting from the impairment is partially offset by the increase in oil and gas production and related capital costs resulting from our increased drilling and completion activity discussed above.

Impairment

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,
	2007			2006
Total general and administrative costs	$	7,004,761		$	6,424,012
General and administrative costs attributable to drilling, completion and operating activities		(1,067,905	)		(1,159,734	)

General and administrative expense	$	5,936,856		$	5,264,278

General and administrative expenses per Mcfe	$	1.40		$	1.39


Total stock-based compensation costs	$	3,131,406		$	4,158,532
Stock-based compensation costs capitalized		(46,285	)		(7,023	)

Stock-based compensation	$	3,085,121		$	4,151,509

Stock-based compensation per Mcfe	$	0.72		$	1.08


Total general and administrative expense Including stock-based compensation	$	9,021,977		$	9,415,787


Total general and administrative expense per Mcfe	$	2.12		$	2.47

General and administrative expense decreased by $393,810 in 2007 as compared with 2006. The decrease is attributable to several factors including a $1,066,000 decrease in stock-based compensation primarily due to certain stock options and restricted stock becoming fully vested and to the cancellation or forfeiture of options and restricted stock during 2007. This decrease was partially offset by a net increase of approximately $725,000 in salary and office related expenses due to the hiring of additional employees during 2007.

Interest Expense

Interest expense during 2007 and 2006 consists primarily of interest expense related to our outstanding Convertible Senior Notes which were issued on October 20, 2004 and borrowings under our existing line of credit. The increase in interest expense of $315,506 is primarily due to borrowings under our existing line of credit.

Interest Income

Interest income decreased $2,275,385 in 2007 compared with 2006 primarily due to lower average cash and cash equivalent balances during 2007 resulting from our investment in oil and gas properties.

Recent Accounting Pronouncements

Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active”, which clarified the application of SFAS No. 157 as it relates to the valuation of financial assets in a market that is not active for those financial assets. On January 1, 2008, we adopted without material impact on our consolidated financial statements the provisions of SFAS No. 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis. On January 1, 2009, we adopted the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include, among others, those nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. We do not expect the provisions of SFAS No. 157 related to these items to have a material impact on our consolidated financial statements (see Note 10).

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 was effective for Gasco’s financial statements January 1, 2008 and the adoption had no material effect on our financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired, and establishes that acquisition costs will be generally expensed as incurred. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective for Gasco’s year beginning January 1, 2009. We do not expect the adoption of SFAS No. 141R to have a material impact on our consolidated financial statements.

In April 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1). FSP FIN 39-1 defines “right of setoff” and specifies what conditions must be met for a derivative contract to qualify for this right of setoff. It also addresses the applicability of a right of setoff to derivative instruments and clarifies the circumstances in which it is appropriate to offset amounts recognized for those instruments in the statement of financial position. In addition, this FSP permits offsetting of fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement and fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement as the derivative instruments. We adopted this interpretation on January 1, 2008 and the adoption of FSP FIN 39-1 had no material effect on our financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” which amends SFAS No. 133 by requiring expanded disclosures about an entity’s derivative instruments and hedging activities, but does not change SFAS No. 133’s scope or accounting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption permitted. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 161 on our future financial reporting.

In June 2008, the Emerging Issues Task Force (“Task Force”) issued EITF 07-5, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock.” The objective of this Issue is to provide guidance for determining whether an equity-linked financial instrument (or embedded feature) is indexed to an entity’s own stock. The Task Force reached a consensus that contingent and other adjustment features in equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a “plain vanilla” option or forward pricing model and they do not increase the contract’s exposure to those variables. Additionally, denomination of an equity contract’s strike price in a currency other than the entity’s functional currency is inconsistent with equity indexation and precludes equity treatment. We adopted EITF 07-5 on January 1, 2009 and the adoption had no material effect on our financial position or results of operations.

On December 31, 2008, the SEC adopted a final rule that amends its oil and gas reporting requirements. The revised rules change the way oil and gas companies report their reserves in the financial statements. The rules are intended to reflect changes in the oil and gas industry since the original disclosures were adopted in 1978. Definitions were updated to be consistent with Petroleum Resource Management System (PRMS). Other key revisions include a change in pricing used to prepare reserve estimates, the inclusion of non-traditional resources in reserves, the allowance for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and significant new disclosures. The revised rules will be effective for our annual report on Form 10-K for the fiscal year ending December 31, 2009. The SEC is precluding application of the new rules in quarterly reports prior to the first annual report in which the revised disclosures are required and early adoption is not permitted. We are currently evaluating the effect the new rules will have on our financial reporting and anticipate that the following rule changes could have a significant impact on our results of operations as follows:

	•		The price used in calculating reserves will change from a single-day closing price measured on the last day of the company’s fiscal year to a 12-month average price, and will affect our depletion and ceiling test calculations.

	•		Several reserve definitions have changed that could revise the types of reserves that will be included in our year-end reserve report.

	•		Many of our financial reporting disclosures could change as a result of the new rules.

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, 2008, the off-balance sheet arrangements and transactions that we have entered into include 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.

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 the exposure to adverse market changes, we have entered into various derivative instruments. As of December 31, 2008, our derivative instruments consisted of two swap agreements and one collar agreement for our 2009 production. The fair market value of these agreements was a current asset of $8,855,947 as of December 31, 2008. The derivative instruments as of December 31, 2007 consisted of a swap agreement which we entered into during December 2007 for the calendar year 2008. The fair market value of the agreement was a liability of $343,759 as of December 31, 2007. 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, Gasco receives 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 costless collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Gasco receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

Our swap agreements for 2009 are summarized in the table below:


			Fixed Price	Floating Price (a)
Agreement Type	Term	Quantity	Counterparty payer	Gasco payer
Swap	1/09 – 12/09	3,000 Mmbtu/day	$7.025/Mmbtu	NW Rockies
Swap	1/09 – 12/09	3,000 Mmbtu/day	$7.015/Mmbtu	NW Rockies

Our costless collar agreement 2009 is summarized in the table below:


Agreement			Index	Call Price	Put Price
Type	Term	Quantity	Price (b)	Counterparty buyer	Gasco buyer
Costless collar	1/09 – 12/09	3,000 Mmbtu/day	NW Rockies	$7.50/Mmbtu	$6.50/Mmbtu


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

The swap contracts will 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. The collar structures provide for participation in price increases and decreases to the extent of the ceiling and floors provided in our contracts. 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 bank credit facility, to the volatility in interest rates.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Gasco Energy, Inc.:

We have audited the accompanying consolidated balance sheet of Gasco Energy, Inc. and subsidiaries (the Company) as of December 31, 2008, and the related consolidated statements of operations, stockholders’ equity, 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 consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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 financial position of Gasco Energy, Inc. and subsidiaries as of December 31, 2008, and the results of their operations and their cash flows for the year 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, 2008, 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 4, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP
Denver, Colorado
March 4, 2009

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, and the related consolidated statements of income, retained earnings and cash flows for each of the two years in the period ended December 31, 2007. 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 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 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 two years in the period 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,
	2008			2007
ASSETS

CURRENT ASSETS

Cash and cash equivalents	$	1,053,216		$	1,843,425
Accounts receivable
Joint interest billings		5,436,636			5,639,174
Revenue		3,827,950			3,872,959
Inventory		4,177,967			1,160,325
Derivative instruments		8,855,947			—
Prepaid expenses		188,810			327,030

Total		23,540,526			12,842,913


PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved properties		247,976,854			215,273,593
Unproved properties		39,314,406			41,644,348
Wells in progress		644,688			1,058,727
Gathering assets		17,440,680			15,708,353
Facilities and equipment		8,549,928			9,680,010
Furniture, fixtures and other		371,605			284,791

Total		314,298,161			283,649,822
Less accumulated depletion, depreciation, amortization and impairment		(185,585,582	)		(175,973,720	)

Total		128,712,579			107,676,102


NON-CURRENT ASSETS
Deposit		139,500			139,500
Deferred financing costs		1,492,903			1,853,274

		1,632,403			1,992,774


TOTAL ASSETS	$	153,885,508		$	122,511,789

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

GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)


	December 31,
	2008			2007
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	5,879,150		$	13,206,767
Revenue payable		3,840,985			1,477,268
Advances from joint interest owners		612,222			5,718,234
Derivative instruments		—			343,759
Accrued interest		1,187,495			844,094
Accrued expenses		1,126,000			583,000

Total		12,645,852			22,173,122


NONCURRENT LIABILITIES
5.5% Convertible Senior Notes		65,000,000			65,000,000
Long-term debt		31,000,000			9,000,000
Asset retirement obligation		1,150,179			1,030,283
Deferred rent expense		46,589			60,593

Total		97,196,768			75,090,876


COMMITMENTS AND CONTINGENCIES (NOTE 15)

STOCKHOLDERS’ EQUITY
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; 107,825,998 shares issued and 107,752,298 shares outstanding as of December 31, 2008; 107,290,471 shares issued and 107,216,771 shares outstanding as of December 31, 2007		10,783			10,729
Additional paid-in-capital		219,375,369			215,094,271
Accumulated deficit		(175,212,969	)		(189,726,914	)
Less cost of treasury stock of 73,700 common shares		(130,295	)		(130,295	)

Total		44,042,888			25,247,791


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	153,885,508		$	122,511,789

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

GASCO ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Year Ended December 31,
	2008			2007			2006
REVENUES
Gas	$	32,328,579		$	16,818,623		$	19,851,663
Oil		3,306,253			2,337,129			1,187,509
Gathering		4,796,409			1,937,785			1,941,059
Rental income		1,426,932			1,029,094			—

Total		41,858,173			22,122,631			22,980,231


OPERATING EXPENSES
Lease operating		6,653,698			3,932,924			3,513,568
Gathering operations		3,457,593			2,471,645			2,718,357
Depletion, depreciation and amortization		9,476,944			9,780,767			10,885,697
Impairment		3,500,000			97,090,000			51,000,000
General and administrative		9,211,806			9,021,977			9,415,787

Total		32,300,041			122,297,313			77,533,409


OTHER INCOME (EXPENSE)
Interest expense		(5,151,136	)		(4,274,814	)		(3,959,308	)
Derivative gains (losses)		9,761,826			(343,759	)		—
Gain on sale of inventory		318,740			—			—
Interest income		26,383			419,334			2,694,719

Total		4,955,813			(4,199,239	)		(1,264,589	)


NET INCOME (LOSS)		14,513,945			(104,373,921	)		(55,817,767	)

Preferred stock dividends		—			—			(1,393	)


NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	14,513,945		$	(104,373,921	)	$	(55,819,160	)


NET INCOME (LOSS) PER COMMON SHARE
BASIC	$	0.14		$	(1.12	)	$	(0.65	)

DILUTED	$	0.13		$	(1.12	)	$	(0.65	)


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
BASIC		107,312,716			93,504,982			85,383,306

DILUTED		109,090,165			93,504,982			85,383,306

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

GASCO ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


													Additional
	Preferred Stock						Common Stock						Paid-in			Deferred			Accumulated			Treasury
	Shares			Value			Shares			Value			Capital			Compensation			Deficit			Stock			Total
Balance December 31, 2005		763		$	1			85,041,492		$	8,504		$	157,540,755		$	(443,579	)	$	(29,535,226	)	$	(130,295	)	$	127,440,160
Adoption of SFAS No. 123(R)														(443,579	)		443,579									—
Conversion of preferred shares to common shares		(763	)		(1	)		479,599			48			(47	)											—
Exercise of common stock options								604,161			60			1,591,614												1,591,674
Cancellation of common stock								(82,787	)		(8	)		(199,278	)											(199,286	)
Stock compensation								131,250			13			4,158,520												4,158,533
Dividends														(1,393	)											(1,393	)
Net loss		—			—			—			—			—			—			(55,817,767	)		—			(55,817,767	)


Balance December 31, 2006		—			—			86,173,715			8,617			162,646,592			—			(85,352,993	)		(130,295	)		77,171,921
Issuance of common stock		—			—			20,999,868			2,100			49,536,807			—			—			—			49,538,907
Cancellation of common stock		—			—			(88,462	)		(8	)		(220,514	)		—			—			—			(220,522	)
Stock compensation		—			—			205,350			20			3,131,386			—			—			—			3,131,406
Net loss		—			—			—			—			—			—			(104,373,921	)		—			(104,373,921	)


Balance December 31, 2007		—			—			107,290,471			10,729			215,094,271			—			(189,726,914	)		(130,295	)		25,247,791

Exercise of common stock options								566,566			56			1,161,228												1,161,284
Cancellation of common stock								(80,039	)		(7	)		(14,155	)											(14,162	)
Stock compensation								49,000			5			3,134,025												3,134,030
Net income		—			—			—			—			—			—			14,513,945			—			14,513,945


Balance December 31, 2008		—		$	—			107,825,998		$	10,783		$	219,375,369		$	—		$	(175,212,969	)	$	(130,295	)	$	44,042,888

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

GASCO ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Years Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	14,513,945		$	(104,373,921	)	$	(55,817,767	)
Adjustment to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, amortization and impairment expense		12,879,223			106,782,341			61,816,513
Accretion of asset retirement obligation		97,721			88,426			69,184
Stock-based compensation		3,102,998			3,085,121			4,151,509
Unrealized derivative (gain) loss		(9,199,706	)		343,759			—
Amortization of deferred rent expense		(14,004	)		(12,400	)		(5,734	)
Amortization of deferred financing costs		521,428			518,233			503,216
Gain on sale of inventory		(318,740	)		—			—
Changes in operating assets and liabilities:
Accounts receivable		247,547			(475,097	)		(4,129,844	)
Inventory		(2,698,902	)		137,173			(114,516	)
Prepaid expenses		138,220			177,960			1,064
Accounts payable		(4,367,208	)		2,825,300			2,376,327
Revenue payable		2,363,717			(201,159	)		20,286
Accrued interest		343,401			(8	)		4
Accrued expenses		543,000			(12,000	)		12,713

Net cash provided by operating activities		18,152,640			8,883,728			8,882,955


CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for acquisitions, development and exploration		(44,250,250	)		(63,508,879	)		(79,557,785	)
Brek acquisition transaction costs net of cash received		—			(356,803	)		—
Cash paid for furniture, fixtures and other		(86,814	)		(43,782	)		(67,994	)
Advances from joint interest owners		(5,106,012	)		2,762,858			479,296
Proceeds from property sales		7,500,000			3,475,153			—
Proceeds from the sale of short-term investments		—			6,000,000			9,000,000
Cash designated as restricted		—			—			(9,980	)
Cash undesignated as restricted		—			3,575,000			10,139,000

Net cash used in investing activities		(41,943,076	)		(48,096,453	)		(60,017,463	)


CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit		42,000,000			18,000,000			—
Repayment of borrowings		(20,000,000	)		(9,000,000	)		—
Cash paid for debt issuance costs		(161,057	)		(120,729	)		(240,262	)
Proceeds from sale of common stock		—			19,300,000			—
Exercise of options to purchase common stock		1,161,284			—			1,591,674
Preferred dividends		—			—			(1,393	)

Net cash provided by financing activities		23,000,227			28,179,271			1,350,019


NET DECREASE IN CASH AND CASH EQUIVALENTS		(790,209	)		(11,033,454	)		(49,784,489	)

CASH AND CASH EQUIVALENTS:

BEGINNING OF PERIOD		1,843,425			12,876,879			62,661,368


END OF PERIOD	$	1,053,216		$	1,843,425		$	12,876,879

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

GASCO ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

NOTE 1 — ORGANIZATION

Gasco Energy, Inc. (“Gasco,” “the Company,” “we,” “our” or “us”) was incorporated under the laws of the State of Nevada on April 21, 1997 and operated as a “shell” company until December 31, 1999. Gasco is a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. 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 drilling efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Wasatch, Mesaverde and Blackhawk, Mancos and Dakota/Morrison formations.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Cash and Cash Equivalents

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

Concentration of Credit Risk

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

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

Significant Customers

During the years ended December 31, 2008, 2007 and 2006, 21%, 80% and 94%, respectively, of the Company’s production was sold to ConocoPhillips Company and during 2008, 68% was sold to Anadarko Petroleum Corporation. Approximately 49% of the accounts
receivable – revenue as of December 31, 2008 is due from Anadarko Petroleum Corporation. However, Gasco does not believe that the loss of a single purchaser, including Anadarko Petroleum Corporation, would materially affect the Company’s business because there are numerous other purchasers in the areas in which Gasco sells its production.

Inventory

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

Oil and Gas Properties

The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, internal costs directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $329,627, $129,825 and $353,190 of internal costs during the years ended December 31, 2008, 2007 and 2006, respectively. Additionally we capitalized stock compensation expense related to our drilling consultants as further described in Note 3. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to a cost center. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development costs to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties of $39,314,406 as of December 31, 2008, are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. As we plan to drill only two gross (0.84 net) new wells during 2009, we reclassified approximately $1,250,000 and $750,000 of expiring acreage primarily in Utah and California, respectively into proved property during 2008. This acreage represents the leases that may expire during 2009 before we are able to develop them further. During 2007, approximately $6,230,000 of unproved lease costs related to our Wyoming acreage was reclassified to proved property and during 2006, approximately $3,786,000 of unproved lease costs related to expiring acreage in Wyoming was

also reclassified to proved property, as management believed that continued low commodity prices made this acreage uneconomic to drill. These costs were included in the ceiling test and depletion calculations during the quarter in which the reclassifications were made.

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

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion (full cost pool) 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 in the balance sheet plus the cost, or estimated fair value if lower of unproved properties and the costs of any properties not being amortized, if any, net of income taxes (ceiling limitation). Should the full cost pool exceed this ceiling limitation, an impairment is recognized. The present value of estimated future net revenues is computed by applying current oil and gas prices to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. However, subsequent commodity price increases may be utilized to calculate the ceiling value.

As of September 30, 2007, oil and gas prices were $62.29 per barrel and $0.345 per mcf. 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 quarter end, oil and gas prices increased; and using these prices our full cost pool would have exceeded the above described ceiling by $32,790,000. Additionally, as of June 30, 2007, based on oil and gas prices of $54.09 per barrel and $3.90 per mcf, the full cost pool exceeded the above described ceiling by $66,700,000. Subsequent to that quarter end, oil and gas prices increases reduced our impairment to $64,300,000. Therefore, impairment expense of $97,090,000 was recorded during the year ended December 31, 2007. No impairment expense related to our oil and gas properties was recorded during 2008.

As of December 31, 2006, based on oil and gas prices of $4.47 per mcf and $45.53 per barrel, the full cost pool would have exceeded the above described ceiling by $28,500,000. However, subsequent to year end, oil and gas prices increased; and using these prices, the Company’s full cost pool would not have exceeded the ceiling limitation. As a result of the increase in the ceiling amount using subsequent prices, the Company did not record an impairment of its oil and gas prices at December 31, 2006. As of June 30, 2006, the Company’s full cost pool exceeded the ceiling limitation based on oil and gas prices of $59.87 per barrel and $5.42 per mcf. Subsequent commodity price increases were not sufficient to eliminate the need for the impairment and therefore, impairment expense of $51,000,000 was recorded during the year ended December 31, 2006.

Capitalized Interest

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Interest costs capitalized in 2007 and 2006 were $548,047 and $231,500, respectively. No interest was capitalized during 2008.

Wells in Progress

Wells in progress at December 31, 2008 represent the costs associated with the drilling of one well in the Riverbend area of Utah. Since the well had not reached total depth as of December 31, 2008, it was classified as wells in progress and was withheld from the depletion calculation and the ceiling test. The costs for this well will be transferred into proved property when the well reaches total depth and is cased and will become subject to depletion and the ceiling test calculation in future periods. Wells in progress at December 31, 2007 represented the costs associated with the drilling of one wells in the Riverbend area of Utah. These costs were reclassified into proved properties during 2008 and became subject to the depletion calculation and the ceiling test.

Gathering Assets

Gathering assets are comprised of the costs associated with the construction of the Company’s pipeline and gathering system located in the Riverbend area of Utah. These assets are being depreciated on a units-of-production method based upon estimated proved oil and gas reserves of the wells that are expected to flow through the gathering system.

Facilities and Equipment

The Company constructed four evaporation pits in the Riverbend area of Utah to be used for the disposal of produced water from the wells that Gasco operates in the area. The pits are being depreciated using the straight-line method over their estimated useful life of twenty-five years. The costs of water disposal into the evaporation pits is charged to wells operated by Gasco and therefore, revenue, net of direct costs, attributable to the outside working interest owners from the evaporation pits of $260,846, $206,186 and $179,766 was recorded as a credit to proved properties during 2008, 2007 and 2006, respectively.

The Company’s other oil and gas equipment is depreciated using the straight-line method over the estimated useful life of the equipment of five to ten years. The rental of the equipment owned by Gasco is charged to the wells that are operated by Gasco and therefore, net revenue attributable to the outside working interest owners from the rig and equipment rental of $688,174, $887,080 and $748,690 was recorded as a credit to proved properties during 2008, 2007 and 2006, respectively.

Impairment of Long-lived Assets

The Company’s unproved properties are evaluated quarterly for the possibility of potential impairment. During 2008 approximately $1,750,000 and $250,000 of unproved lease costs related

to our Utah and California acreage, respectively, was reclassified to proved property and was included in the ceiling test and depletion calculations. During 2007 and 2006, approximately $6,230,000 and $3,786,000 of unproved lease costs related to our Wyoming acreage, respectively, was reclassified to proved property and was included in the ceiling test and depletion calculations.

We currently own a drilling rig that has a carrying value of approximately $5,500,000. In light of the current market conditions and the lower commodity prices, many oil and gas companies have cut back on their drilling plans for 2009. As a result, the demand for drilling rig services has also declined. Based upon an independent appraisal of our drilling rig, we believe that the market value of our drilling rig has decreased to approximately $2,000,000 as of December 31, 2008 and therefore, we have recorded impairment expense of $3,500,000 to bring the carrying value down to the market value.

Deferred Financing Costs

Deferred financing costs include the costs associated with the Company’s issuance of $65,000,000 of Convertible Notes during October 2004, the debt issuance costs incurred in connection with the Company’s credit facility and the additional debt issuance costs associated with the amendment of our credit facility during 2008 (see Note 8). The Company recorded amortization expense of $521,428, $518,233 and $503,216 related to these costs during the years ended December 31, 2008, 2007 and 2006, respectively.

Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Company’s derivative instruments are recorded at fair value, as discussed below. The Company’s borrowings under its credit facility, as further described in Note 8, approximate the fair value due to its floating rate structure. The Company’s Convertible Notes are recorded at cost, and the fair value is disclosed in Note 9. As considerable judgment is required to develop estimates of fair value, the estimates provided are not necessarily indicative of the amounts the Company could realize upon the purchase or refinancing of such instruments.

Derivatives

The Company uses 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 account for our derivatives and hedging activities under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133, we are required to record our derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in current earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings.

Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. The Company has decided not to use hedge accounting for our derivatives. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair market value are recognized in earnings.

As of December 31, 2008, natural gas derivative instruments consisted of two swap agreements and a costless collar for the calendar year 2009 production. The fair market value of the agreements was a current asset of $8,855,947 as of December 31, 2008 and a current liability of $343,759 as of December 31, 2007. These fair values include a measure of counterparty risk based on the relevant credit default swap prices. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our hedged production. Although these derivative instruments expose us to credit risk, we monitor the credit worthiness of our counterparty, and we are not currently aware of any inability on the part of our counterparty to perform under our contracts. However, we are not able to predict sudden changes in the creditworthiness of our counterparty.

Our derivative contracts are described below:

	•		For our swap instruments, Gasco receives 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 costless collar contains a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Gasco receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

The table below summarizes the realized and unrealized gains and losses related to our derivative instruments for the year ended December 31, 2008. We had no derivative transactions during 2007.


Realized gains on derivative instruments	$	562,120
Unrealized gains on derivative instruments		9,199,706


Total realized and unrealized gains recorded	$	9,761,826

Derivative gains are included in cash flows from operating activities in the accompanying consolidated statements of cash flows.

Our swap agreements for 2009 are summarized in the table below:

Fixed Price

Floating Price (a)

Agreement Type

Term

Quantity

Counterparty payer

Gasco payer

Swap

1/09 — 12/09

3,000 Mmbtu/day

$7.025/Mmbtu

NW Rockies

Swap

1/09 — 12/09

3,000 Mmbtu/day

$7.015/Mmbtu

NW Rockies

Our costless collar agreement for 2009 is summarized in the table below:

Index

Call Price

Put Price

Agreement Type

Term

Quantity

Price (b)

Counterparty buyer

Gasco buyer

Costless collar

1/09 — 12/09

3,000 Mmbtu/day

NW Rockies

$7.50/Mmbtu

$6.50/Mmbtu


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

Asset Retirement Obligation

The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations, “ which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs using the units-of-production method. Gasco’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties and gathering assets. The asset retirement liability is allocated to operating expense using a systematic and rational method. The information below reconciles the value of the asset retirement obligation for the periods presented.


	Year Ended December 31,
	2008			2007
Balance beginning of period	$	1,030,283		$	908,543
Liabilities incurred		52,430			126,145
Liabilities settled		(21,674	)		—
Revisions (a)		2,526			(64,568	)
Property dispositions		(11,107	)		(28,263	)
Accretion expense		97,721			88,426

Balance end of period	$	1,150,179		$	1,030,283


(a)		Revisions represent our periodic reassessment of the expected cash flows and assumptions inherent in the calculation of the asset retirement liability.

Off Balance Sheet Arrangements

Revenue Recognition

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

The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2008 and 2007 were not significant.

Computation of Net Loss per Share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of the options to acquire common stock computed using the treasury stock method which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period).

The table below sets forth the computations of basic and diluted net income per share for the year ended December 31, 2008. Basic and diluted net loss per share were the same in each of the years ended December 31, 2007 and 2006.


	Year Ended
	December 31, 2008
Numerator:
Basic net income	$	14,513,945


Denominator:
Basic weighted average common shares outstanding		107,312,716
Effect of dilutive securities:
Options to purchase common stock		4,673,627
Assumed treasury shares purchased		(3,127,788	)
Unvested restricted stock		233,300
Diluted weighted average common shares outstanding		109,091,855

Basic net income per share	$	0.14
Diluted net income per share	$	0.13

The 16,250,000 shares of common stock that would have been issued upon conversion of the Convertible Notes have been excluded from the diluted weighted average shares outstanding during the year ended December 31, 2008 because the inclusion of such shares would have been antidilutive. For the year ended December 31, 2008, 4,602,937 options to purchase common stock, respectively, were not included in the diluted weighted average shares outstanding because the exercise of these options would have been anti-dilutive. During the year ended December 31, 2007 and 2006 potential common stock of equivalents of 26,979,138 and 26,128,502, respectively, were excluded from the computation of net income (loss) per share.

Use of Estimates

The preparation of the financial statements for the Company in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

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

Other Comprehensive Income

The Company does not have any items of other comprehensive income for the years ended December 31, 2008, 2007 and 2006. Therefore, total comprehensive income (loss) is the same as net income (loss) for these periods.

Income Taxes

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

The Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”) on January 1, 2007. FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. The adoption of FIN 48 had an immaterial impact on the Company’s consolidated financial position and did not result in unrecognized tax benefits being recorded. Subsequent to adoption, there have been no changes to the Company’s assessment of uncertain tax positions. Accordingly, no corresponding interest and penalties have been accrued. The Company’s policy is to recognize penalties and interest, if any, related to uncertain tax positions as general and administrative expense. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2005 and for state and local tax authorities for years before 2004.

Stock Compensation

Effective January 1, 2006, the Company adopted SFAS No. 123(R), “Accounting for Stock-Based Compensation” using the modified prospective transition method. SFAS No. 123R requires companies to recognize compensation cost for stock-based awards based on estimated fair value of the award, effective January 1, 2006. See Note 3 for further discussion.

Reclassifications

Advances from joint interest owners, net in 2007 and 2006 and have been reclassified to investing activities and derivative gains (losses) and interest income in 2007 and 2006 have been reclassified from revenue to other income (expense) to be consistent with the 2008 presentation. The following table summarizes the reclassification of these items within the consolidated statement of statements of operations and cash flows for the year ended December 31, 2007:


	Year Ended
	December 31,						Year Ended
	2007						December 31,
	(Previously						2007
	Reported)			Reclassification			(As Reclassified)
Total revenues	$	22,198,206		$	(75,575	)	$	22,122,631
Total operating expenses		126,572,127			4,274,814			122,297,313
Other income (expense)		—			(4,199,239	)		(4,199,239	)
Net cash provided by operating activities		11,646,586			(2,762,858	)		8,883,728
Net cash (used in) provided by investing activities		(50,859,311	)		2,762,858			(48,096,453	)

Recently Issued Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements.” This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure related to the use of fair value measures in financial statements. In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active”, which clarified the application of SFAS No. 157 as it relates to the valuation of financial assets in a market that is not active for those financial assets. On January 1, 2008, we adopted without material impact on our consolidated financial statements the provisions of SFAS No. 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis. On January 1, 2009, we adopted the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include, among others, those nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. We do not expect the provisions of SFAS No. 157 related to these items to have a material impact on our consolidated financial statements (see Note 10).

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R establishes

principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired, and establishes that acquisition costs will be generally expensed as incurred. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective for Gasco’s year beginning January 1, 2009. We do not expect the adoption of SFAS No. 141R to have a material impact on our consolidated financial statements.

the allowance for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and significant new disclosures. The revised rules will be effective for our annual report on Form 10-K for the fiscal year ending December 31, 2009. The SEC is precluding application of the new rules in quarterly reports prior to the first annual report in which the revised disclosures are required and early adoption is not permitted. We are currently evaluating the effect the new rules will have on our financial reporting and anticipate that the following rule changes could have a significant impact on our results of operations as follows:

	•		The price used in calculating reserves will change from a single-day closing price measured on the last day of the company’s fiscal year to a 12-month average price, and will affect our depletion and ceiling test calculations.

	•		Several reserve definitions have changed that could revise the types of reserves that will be included in our year-end reserve report.

	•		Many of our financial reporting disclosures could change as a result of the new rules.

NOTE 3 — STOCK-BASED COMPENSATION

On January 1, 2006, Gasco adopted SFAS No. 123(R), “Accounting for Stock-Based Compensation,” using the modified prospective method. Under the modified prospective method, the adoption of SFAS No. 123(R) applies to new awards and to awards modified, repurchased, or cancelled after December 31, 2005, as well as to the unvested portion of awards outstanding as of January 1, 2006. SFAS No. 123(R) requires companies to recognize share-based payments to employees as compensation expense using a fair value method. Under the fair value recognition provisions of SFAS No. 123(R), stock-based 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 on a straight-line basis, which generally represents the vesting period. The expense recognized over the service period is required to include an estimate of the awards that will be forfeited. Gasco is assuming no forfeitures for employee awards going forward based on the Company’s historical forfeiture experience. For non-employee awards, Gasco is assuming a 3% forfeiture rate for the years ending December 31, 2008, 2007 and 2006. The fair value of stock options is calculated using the Black-Scholes option-pricing model and the fair value of restricted stock is based on the fair market value of the stock on the date of grant.

The Company accounts for stock compensation arrangements with non-employees in accordance with SFAS No. 123(R) and Emerging Issues Task Force, or EITF, No. 96-18, “Accounting of Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services,” using a fair value approach. Under this approach, the stock compensation related to the unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair market value on that date. Stock-based non-employee compensation expense was $86,363, $56,370 and $6,264 during the years ended December 31, 2008, 2007 and 2006, respectively. Of these amounts, $31,026, $45,285 and $7,024 of compensation expense relating to drilling consultants was capitalized during the years ended December 31, 2008, 2007 and 2006, respectively.

As of December 31, 2008, options to purchase an aggregate of 11,124,788 shares of the Company’s common stock and 233,300 shares of restricted stock were outstanding. These awards were granted during the years from 2001 through 2008 to the Company’s employees, directors and consultants. The options have exercise prices ranging from $0.50 to $6.69 per share. The options vest at varying schedules within five years of their grant date and expire within ten years from the grant date. Stock-based employee compensation expense was $3,047,661, $3,075,037 and $4,152,268 before taxes for the years ending December 31, 2008, 2007, and 2006, respectively.

During the years ended December 31, 2008, 2007 and 2006, the Company recognized stock-based compensation as follows:


	2008			2007			2006
Stock-based compensation	$	3,134,024		$	3,131,406		$	4,158,533
Consultant compensation capitalized as proved property		(31,026	)		(46,285	)		(7,024	)

Total stock-based compensation expense	$	3,102,998		$	3,085,121		$	4,151,509

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

The Company uses the Black-Scholes option-pricing model to estimate the fair value of the options at the grant date. The fair value of options granted to the Company’s employees and directors during 2008, 2007, and 2006 was calculated using the following assumptions:


	Employee and Director Options
	2008			2007			2006
Expected dividend yield		—			—			—
Expected price volatility		70-74	%		81-84	%		85-88	%
Risk-free interest rate		1.4 – 4.0	%		3.58 – 4.8	%		4.64 – 5.08	%
Expected life of options	5-6 years			6 years			6 years

The weighted average grant-date fair value of options granted to employees and directors during 2008, 2007, and 2006 was $1.02, $1.38, and $3.76, respectively.

The expected stock price volatility assumption was determined using the historical volatility of the Company’s common stock over the expected life of the option. The expected life of the option has been calculated based upon the average historical time between when options were issued and when they were exercised.

Stock Options

The following table summarizes the stock option activity in the equity incentive plans during the years ended December 31, 2008, 2007 and 2006:


	2008					2007					2006
				Weighted					Weighted					Weighted
				Average					Average					Average
	Stock			Exercise		Stock			Exercise		Options			Exercise
	Options			Price		Options			Price		Stock			Price
Outstanding at beginning of year		10,729,138		$	2.58		9,878,502		$	2.74		8,812,667		$	2.29
Granted		2,938,750		$	1.76		1,540,000		$	1.91		1,925,000		$	4.97
Exercised		(566,566	)	$	2.05		—			—		(604,161	)	$	2.63
Forfeited		(686,573	)	$	3.14		(276,867	)	$	3.00		(186,671	)	$	4.63
Cancelled		(1,289,961	)	$	5.18		(412,497	)	$	3.49		(68,333	)	$	3.84
Outstanding at the end of year		11,124,788		$	2.06		10,729,138		$	2.58		9,878,502		$	2.74
Exercisable at December 31,		7,461,351		$	2.17		8,333,472		$	2.44		7,543,463		$	2.14

The following table summarizes information related to the outstanding and vested options as of December 31, 2008:


	Outstanding Options		Vested options
Number of shares		11,124,788		7,461,351
Weighted Average Remaining Contractual Life in years		5.18		4.69
Weighted Average Exercise Price	$	2.06	$	2.17
Aggregate intrinsic value		—		—

Based on the Company’s closing common stock price of $0.39 as of December 31, 2008, which would have been received by the option holders had all option holders exercised their options as of that date, the options outstanding had no intrinsic value.

The total intrinsic value of options exercised during the years ending December 31, 2008 and 2006 was $983,238 and $1,256,450, respectively. There were no options exercised during the year ending December 31, 2007.

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

As of December 31, 2008, there was $3,246,141 of total unrecognized compensation cost related to non-vested options granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 3.74 years.

During the year ended December 31, 2008, the Company cancelled 1,255,000 stock options with exercise prices ranging from $3.10 to $5.69. In exchange, the Company granted to the optionees 316,250 stock options with an exercise price of $1.00. This resulted in a modification of the original award under SFAS No. 123(R). However, because the fair value of the issued options

did not exceed the fair value of the cancelled options on the date of the exchange, no incremental compensation expense was recognized.

The following table summarizes the stock options outstanding at December 31, 2008.


					Weighted
					Average
	Number of		Number of		Remaining
Range of exercise	Shares		Shares		Contractual Life
Prices per Share	Outstanding		Exercisable		(years)
$0.00 – $0.99		184,000		—		5.0
$1.00 – $1.99		6,252,194		3,206,097		4.9
$2.00 – $2.99		2,046,000		1,899,328		4.5
$3.00 – $3.99		2,480,933		2,227,599		6.4
$4.00 – $4.99		40,000		6,666		9.5
$5.00 – $5.99		121,661		121,661		7.3

Total		11,124,788		7,461,351		5.2

Restricted Stock

The following table summarizes the restricted stock activity for the years ending December 31, 2008, 2007 and 2006:


	2008					2007					2006
				Weighted					Weighted					Weighted
				Average					Average					Average
	Restricted			Fair		Restricted			Fair		Restricted			Fair
	Stock			Value		Stock			Value		Stock			Value
Outstanding at the beginning of the year		308,820		$	2.36		365,920		$	2.39		565,380		$	1.58
Granted		49,000		$	3.20		234,500		$	2.02		131,250		$	3.02
Vested		(56,020	)	$	2.97		(262,450	)	$	2.03		(305,710	)	$	0.96
Forfeited		(68,500	)	$	2.31		(29,150	)	$	2.41		(25,000	)	$	2.59
Outstanding at the end of the year		233,300		$	2.35		308,820		$	2.36		365,920		$	2.39

The total grant date fair value of the shares vested during the years ending December 31, 2008, 2007, and 2006 was $166,400, $533,362 and $293,608, respectively.

As of December 31, 2008, there was $433,398 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a weighted-average period of 2.48 years.

NOTE 4 — OIL AND GAS PROPERTY

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


	As of December 31,
	2008			2007
Proved properties	$	247,976,854			215,273,593
Unproved properties		39,314,406			41,644,348
Wells in progress		644,688			1,058,727
Gathering assets		17,440,680			15,708,353
Facilities and equipment		8,549,928			9,680,010

Total		313,926,556			283,365,031
Less accumulated depletion, depreciation, amortization and impairment		(185,356,264	)		(175,809,007	)

	$	128,570,292		$	107,556,024

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,
	2008		2007		2006
Property acquisition costs:
Unproved	$	624,815	$	35,578,808	$	1,285,289
Proved		—		2,496,100		2,563,862
Exploration costs		24,607,162		44,421,848		75,523,006
Development costs		11,758,219		— 7		,898,7262

Total	$	36,990,196	$	82,496,756	$	87,270,883

Depletion and impairment expense related to proved properties per equivalent Mcf of production for the years ended December 31, 2008, 2007 and 2006 was $1.96, $25.08 and $16.22, respectively.

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


	2008		2007
Utah	$	37,546,914	$	39,842,505
California		1,357,886		1,639,794
Nevada		409,606		162,049

	$	39,314,406	$	41,644,348

During 2008, we reclassified approximately $1,250,000 and $750,000 of expiring acreage primarily in Utah and California, respectively, into proved property and included these amounts in the ceiling test and depletion calculations. This acreage represents the leases that will expire during 2009 before we are able to develop them further.

During the year ended December 31, 2007, approximately $6,230,000 of acreage costs in Wyoming, representing our remaining carrying value for this area, was reclassified into proved properties and was included in the ceiling test and depletion calculations. Management believed that the continued low prices that we received in the Rockies caused Wyoming acreage to become uneconomic.

The following table sets forth a summary of oil and gas property costs not being amortized as of December 31, 2008, by the year in which such costs were incurred.


			Costs Incurred During Years Ended
	Balance		December 31,
	12/31/08		2008		2007		2006
Acquisition costs	$	31,953,340	$	251,649	$	30,975,234	$	726,457
Exploration costs		7,361,066		869,763		4,603,573		1,887,730

Total	$	39,314,406	$	1,121,412	$	35,578,807	$	2,614,187

NOTE 5 — PROPERTY ACQUISITION

The purchase price of $30,749,300 consisted of the following:


	Purchase
	Price
	Components
Fair value of common stock issued	$	30,359,636
Acquisition costs		389,664

Total purchase price	$	30,749,300

The purchase price allocation was as follows:


	Purchase
	Price
	Allocation
Cash	$	32,807
Unproved properties		29,183,125
Proved properties		1,552,836
Asset retirement obligation		(19,468	)

Total purchase price	$	30,749,300

The results of Brek’s operations were included in the consolidated operations from the date of acquisition, December 14, 2007. The following table reflects unaudited pro forma results of operations for the year ended December 31, 2007 and 2006 as though the Brek acquisition had occurred on January 1 of each year presented. The pro forma results are not necessarily indicative of the results that would have been obtained had the acquisition occurred as of an earlier date or results which may be reported in the future.


	For the Year Ended December 31,
	2007			2006
Net revenue	$	22,467,277		$	26,061,003
Net loss		(104,385,718	)		(55,797,507	)
Net loss per share	$	(1.00	)	$	(0.58	)

NOTE 6 — PROPERTY SALE

During the third quarter of 2008, Gasco sold its interest in four gross producing wells (one net producing well), leasehold interests and proven reserves in the Prickly Pear Field in the West Tavaputs area in the Uinta Basin to the operator of these wells. The effective date of the sale was August 21, 2008 and the sales proceeds of $7,500,000 were credited to the full cost pool.

NOTE 7 — DRILLING PROGRAM

NOTE 8 — CREDIT AGREEMENT

On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered into a $250 million Credit Agreement (the “Credit Agreement”) with JPMorgan Chase Bank, N.A., (“JP Morgan”) as Administrative Agent. Borrowings made under the Credit Agreement are guaranteed by our subsidiaries, and are secured by a pledge of the capital stock of such subsidiaries and mortgages on substantially all of our oil and gas properties.

The initial aggregate commitment of the lender under the Credit Agreement was $250,000,000, subject to a borrowing base which was increased from $40,000,000 as of December 31, 2007 to $45,000,000 during April 2008. The Credit Agreement also provides for a $10,000,000 sublimit for letters of credit which we may use for general corporate purposes. The Credit Agreement was amended in December 2008. The $45,000,000 borrowing base was maintained and the original maturity date was extended one year to March 29, 2011. The interest rate pricing grid was increased 0.25% to the levels detailed below and the commitment fee was changed to 0.50% from a variable grid between 0.30% and 0.50%. Additionally, Guarantee Bank and Trust Company was added as a Lender to the Credit Agreement and is currently committed for $5.0 million of the $45.0 million borrowing base. The other commercial terms are substantially unchanged. As of December 31, 2008, there were loans of $31,000,000 outstanding at an average interest rate of 3.23% and letters of credit in the amount of $6,703,000 which are considered usage for purposes of calculating availability and commitment fees. Our aggregate borrowings and outstanding letters of credit under the Credit Agreement may not at any time exceed the borrowing base. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2011.

Interest on borrowings under the Credit Agreement accrues at variable interest rates at either, at our election, a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies from 1.50% (for periods in which we have utilized less than 50% of the borrowing base) to 2.25% (for periods in which we have utilized greater than 90% of the borrowing base). The alternate base rate is calculated as (1) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.50% or (c) the adjusted Libo Rate for a one month interest period on such day plus 1.00%, plus (2) an applicable margin that varies from 0.25% (for periods in which we have utilized less than 50% of the borrowing base) to 1.00% (for periods in which we have utilized greater than 90% of the borrowing base). We elect the basis of the interest rate at the time of each borrowing; however, under certain circumstances, our lender may require us to use the non-elected basis in the event the elected basis does not adequately and fairly reflect the cost of making such loans. In addition, we are obligated to pay a commitment fee under the Credit Agreement quarterly in arrears based on 0.50% of unused commitments.

that restrict our ability to incur other indebtedness, create liens or sell our assets, pay dividends on our common stock and make certain investments. Additionally, at current commodity prices, EBITDAX will be reduced for the four quarters beginning with the quarter ended March 31, 2009 by the expected payment of approximately $4.6 million for early termination of the Company’s drilling contract in February 2009, resulting in a corresponding reduction in the levels of senior debt that the Company may have outstanding going forward without violating its senior debt to EBITDAX ratio. As of December 31, 2008, we were in compliance with each of the covenants contained in the Credit Agreement.

The Credit Agreement provides for semi-annual evaluation of the borrowing base, which will be determined as a percentage of the discounted present value of the Company’s oil and natural gas reserves. The Company’s next borrowing base redetermination is scheduled for April 2009, and base on the decline in commodity prices, the Company believes that it will be reduced. If the Company’s borrowing base is reduced as a result of a redetermination, it may be required to repay a portion of its outstanding borrowings and will have less access to borrowed capital going forward. If the Company does not have sufficient funds on hand for repayment, it may be required to seek a wavier or amendment from its lenders, refinance its Credit Agreement, sell assets or additional shares of common stock or reduce its capital budget. The Company 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 Credit Agreement, which would materially adversely affect its business, financial condition and results or operations. Through the Company’s actions such as reducing the 2009 capital expenditure budget, investing cash balances conservatively and releasing the single drilling rig, the Company believes it has adequate liquidity from expected cash flow to continue operations through 2009.

The Company incurred $401,301 in debt issuance costs associated with this facility. These costs have been recorded as deferred financing costs in the accompanying financial statements and are being amortized over the four year term of the Credit Agreement. The Credit Agreement 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. The Credit Agreement provides for semi-annual evaluation of the borrowing base, which will be determined as a percentage of the discounted present value of the Company’s oil and natural gas reserves. In addition to such semi-annual determinations, the Company’s lenders may request one additional borrowing base redetermination between each semi-annual calculation.

NOTE 9 — CONVERTIBLE SENIOR NOTES

On October 20, 2004 (the “Issue Date”), the Company closed the private placement of $65,000,000 in aggregate principal amount of its 5.50% Convertible Senior Notes due 2011 (the “Convertible Notes”) pursuant to an Indenture dated as of October 20, 2004 (the “Indenture”), between the Company 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 Company 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.

The Company, at its option, may 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 the Company to repurchase all of that holder’s notes 45 days after the Company gives 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 of the Company and rank on a parity (except as described above) in right of payment with all of the Company’s existing and future unsecured and unsubordinated indebtedness. The Convertible Notes effectively rank junior to any future secured indebtedness and junior to the Company’s subsidiaries’ liabilities. The Indenture does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of the Company’s 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 the Company’s 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 is $39,081,250 as of December 31, 2008, based upon market quotes.

NOTE 10 — FAIR VALUE MEASUREMENTS

On January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The Statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

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

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

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

SFAS No. 157 requires financial assets and liabilities to be classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008 by level within the fair value hierarchy:


	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Assets:
Derivative instruments	$	—	$	6,211,413	$	2,644,534

Liabilities:
	$	—	$	—	$	—

Our derivative financial instruments are comprised of natural gas swap and costless collar agreements. The fair values of the swap agreements are determined based primarily on inputs that are derived from observable data at commonly quoted intervals for the full term of the derivatives and are therefore considered level 2 in the fair value hierarchy. The fair values of the costless collar agreements are determined based on both observable and unobservable pricing inputs and therefore, the data sources utilized in these valuation models are considered level 3 inputs in the fair value hierarchy. The counterparty in all of our derivative financial instruments is the lender in our Credit Agreement (Note 8).

The following table sets forth a reconciliation of changes in the fair value of financial liabilities classified as level 3 in the fair value hierarchy:


	Derivatives
Balance as of January 1, 2008	$	—
Total gains (realized or unrealized):
Included in earnings		2,941,534
Included in other comprehensive income		—
Purchases, issuances and settlements		(297,000	)
Transfers in and out of level 3		—


Balance as of December 31, 2008	$	2,644,534


Change in unrealized gains included in earnings relating to derivatives still held as of December 31, 2008	$	2,644,534

NOTE 11 — STOCKHOLDERS’ EQUITY

The Company’s capital stock as of December 31, 2008 and 2007 consists of 300,000,000 authorized shares of common stock, par value $0.0001 per share, and 20,000 authorized shares of Series B Convertible Preferred stock, par value $0.001 per share.

Series B Convertible Preferred Stock — As of December 31, 2008 and 2007, Gasco had no shares of Series B Preferred Stock (“Preferred Stock”) issued and outstanding. All of the Preferred stock outstanding as of December 31, 2005 was converted by the holders thereof into 479,599 shares of common stock during January 2006. During the year ended December 31, 2006, the Company paid $1,393 of cash dividends to the holders of its Preferred Stock.

Common Stock — Gasco has 107,825,998 shares of common stock issued and outstanding and 73,700 shares held in treasury as of December 31, 2008. The common shareholders are entitled to one vote per share on all matters to be voted on by the shareholders; however, there are no cumulative voting rights. The common shareholders are entitled to dividends and other distributions as may be declared by the board of directors. Upon liquidation or dissolution, the common shareholders will be entitled to share ratably in the distribution of all assets remaining available for distribution after satisfaction of all liabilities and payment of the liquidation preference of any outstanding preferred stock.

As of December 31, 2008, we had 11,124,788 shares of common stock issuable upon exercise of outstanding options. Additional options may be granted to purchase 2,251,442 shares of common stock under our stock option plan and an additional 292,150 shares of common stock are issuable under our restricted stock plan. As of December 31, 2008, and as of December 31 of each succeeding year, the number of shares of common stock issuable under our stock option plan automatically increases 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 the Convertible Notes 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 124,002,298 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).

The Company’s common stock equity transactions during 2008 and 2007 are described as follows:

In December 2007 we closed the purchase of Brek for equity consideration of 10,999,868 shares of common stock of the Company valued at approximately $30,749,300 using $2.76 per share which was the average value of the Company’s common stock for two days before and after the agreement was signed. See further discussion in Note 5.

During the years ended December 31, 2008 and 2007, the Company’s Board of Directors approved the issuance of 49,000 and 234,500 shares of common stock, respectively, under the Gasco Energy, Inc. Amended and Restated 2003 Restricted Stock Plan, (“Restricted Stock Plan”) to certain of the Company’s employees and consultants. The restricted shares vest at varying schedules within three to five years. The shares fully vest upon certain events, such as a change in control of the Company, expiration of the individual’s employment agreement and termination by the Company of the individual’s employment without cause. Any unvested shares are forfeited upon termination of employment for any other reason. The compensation expense related to the restricted stock was measured on the issuance date using the trading price of the Company’s common stock on that date and is amortized over the vesting period. The shares of restricted stock are considered issued and outstanding at the date of grant and are included in shares outstanding upon vesting for the purposes of computing diluted earnings per share. During 2008 and 2007, 11,521 and 88,462 shares of the Company’s common stock were cancelled in satisfaction of the income tax liability of $18,036 and $220,522, respectively, associated with the vesting of restricted stock.

NOTE 12 — STATEMENT OF CASH FLOWS

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

•

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

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

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

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

During the year ended December 31, 2007, the Company’s non-cash investing and financing activities consisted of the following transactions:

	•		Issuance of 10,999,868 shares of common stock valued at approximately $30,749,300 for the acquisition of Brek, as further described in Note 5.

	•		Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $126,145. Reduction in asset retirement obligation of $64,568 due to periodic reassessment of the expected cash flows and assumptions inherent in the calculation of the liability.

	•		Stock-based compensation of $46,285 capitalized as proved property.

	•		Additions to oil and gas properties included in accounts payable of $6,688,799.

	•		Capitalization of interest expense of $548,047.

	•		Cancellation of 88,462 shares of common stock in satisfaction of income taxes of $220,522 related to the vesting of restricted stock.

During the year ended December 31, 2006, the Company’s non-cash investing and financing activities consisted of the following transactions:

	•		Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $545,879. Increase in asset retirement obligation of $69,533 due to periodic reassessment of the expected cash flows and assumptions inherent in the calculation of the liability.

	•		Stock-based compensation of $7,024 capitalized as proved property.

	•		Additions to oil and gas properties included in accounts payable of $10,755,910.

	•		Capitalization of interest expense of $231,500.

	•		Conversion of 763 shares of Preferred Stock into 479,599 shares of common stock.

	•		Cancellation of 82,787 shares of common stock in satisfaction of the income tax liability of $199,286 associated with the vesting of restricted stock.

	•		Write-off of fully depreciated furniture and fixtures of $2,592.

NOTE 13 — INCOME TAXES

The provision (benefit) for income taxes for the years ended December 31, 2008, 2007 and 2006 consists of the following:


	2008			2007			2006
Current taxes:
Federal	$	—		$	—		$	—
State		—			—			—
Deferred taxes:
Deferred provision (benefit)		6,261,035			(38,75,921	)		(20,681,594	)
Less: valuation allowance		(6,261,035	)		38,756,921			20,681,594

Net income tax provision (benefit)	$	—		$	—		$	—

A reconciliation of the provision (benefit) for income taxes computed at the statutory rate to the provision for income taxes as shown in the financial statements of operations for the years ended December 31, 2008, 2007 and 2006 is summarized below:


	2008			2007			2006
Tax provision (benefit) at federal statutory rate	$	5,079,881		$	(36,530,872	)	$	(19,536,218	)
State taxes, net of federal tax effects		320,637			(2,659,481	)		(1,726,051	)
Change in Tax Rate from Prior Year		185,057			—			—
Permanent items and other		675,460			433,432			580,675
Valuation allowance		(6,261,035	)		38,756,921			20,681,594

Net income tax provision (benefit)	$	—		$	—		$	—

The components of the deferred tax assets and liabilities as of December 31, 2008 and 2007 are as follows:


	2008			2007
Deferred tax assets:
Federal and state net operating loss carryovers	$	52,031,562		$	43,425,200
Oil and gas property impairment		—			65,332,715
Oil and gas property and other property, plant & equipment		15,123,145			—
Deferred rent		17,335			23,819
Deferred compensation		2,210,496			1,999,499
Accrued salaries and bonus		286,882			—
Asset retirement obligation		428,173			—
Other		7,019			—

Total deferred tax assets		70,104,612			110,781,233
Less: valuation allowance		(66,809,388	)		(86,176,357	)

		3,295,224			24,604,876
Deferred tax liabilities:
Oil and gas property		—			12,876,955
Other property, plant & equipment		—			8,872,435
Derivatives		3,295,224			—

Other		—			2,855,486

Total deferred tax liabilities		3,295,224			24,604,876


Net deferred tax asset	$	—		$	—

The Company has approximately $140,870,187 of net operating loss carryover for federal income tax purposes as of December 31, 2008, of which $5,022,203 is not benefited for financial statement purposes as it relates to tax deductions that deviate from compensation expense for financial statement purposes. The benefit of these excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce taxes payable. The Company has approximately $94,645,059 of net operating loss carryover for state income tax purposes as of December 31, 2008, of which the above excess tax deductions have similarly not been benefited for financial statement purposes. The net operating losses may offset against taxable income through the year ended December 31, 2028. A portion of the net operating loss carryovers begins expiring in 2019. The Company provided a valuation allowance against its net deferred tax asset of $66,809,388 and $86,176,357 as of December 31, 2008 and 2007 respectively, since it believes that it is more likely than not that the net deferred tax assets will not be fully utilized on future income tax returns. The decrease and increase in the valuation allowance for 2008 and 2007 is $(19,366,969) and $57,385,972, respectively. Both the decrease in 2008 and the increase in 2007 were due in part to the acquired deferred tax assets and associated valuation allowance related to the Brek Acquisition.

NOTE 14 — RELATED PARTY TRANSACTIONS

During the year ended December 31, 2007, the Company paid $120,000 in consulting fees to a company owned by a director of Gasco. This consulting agreement was terminated effective January 1, 2008.

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

NOTE 15 — COMMITMENTS

The Company leases approximately 11,840 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.

The following table shows the annual rental per year for the life of the lease.


Year Ending December 31,	Annual Rentals
2009	$	201,134
2010		85,491

Total	$	286,625

Rent expense for the years ended December 31, 2008, 2007 and 2006 was $169,549, $137,512 and $126,352, respectively.

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

The Company entered into employment agreements with three key officers through January 31, 2010. Total minimum compensation under these agreements is $470,000 per annum. The agreements contain clauses regarding termination and demotion of the officer that would require payment of an amount ranging from one times annual compensation to up to approximately five times annual compensation plus a cash payment from $250,000 to $500,000. Included in the employment agreements is a bonus calculation for each of the covered officers totaling 2.125% of a defined cash flow figure based on net after tax earnings adjusted for certain expenses. These employment agreements were amended on January 1, 2009 and on January 22, 2009 to among other things, (i) provide for the forfeit of any right to the annual incentive bonus compensation due to the executive if such executive does not remain employed by the Company through receipt of the signed audit letter relating to such year and (ii) provide for a cash payment, upon termination of such executive’s employment without cause or a change in control of the Company, to the executive in an amount equal to twice the amount paid to such executive as annual bonus compensation for the previous fiscal year.

The future contractual obligations under the rig contracts as of December 31, 2008 are summarized below:


Year Ending December 31,	Annual Drilling Obligations
2009	$	7,665,000
2010		1,239,000

Total	$	8,904,000

During February 2009, the Company released this rig and expects to pay the rig contractor $4,600,000 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.

The Company leases five compressors that are used in the Riverbend area. Two of these compressors are leased on a month to month basis and the remaining three compressors are leased under contracts that expire at various dates during 2009. The Company’s future obligations under the compressor contracts are $754,214 during the year ended December 31, 2009.

During April 2007, we entered into a sales and transportation agreement for 18,000 MMBTU per day, at the first of the month IFERC CIG index price, net of transportation, marketing and fuel expenses for our 2007 production. For our 2008 and 2009 production, we entered into a firm commitment to sell 30,000 MMBtu per day of our gross production from the Uinta Basin. During the first quarter of 2008, 18,000 MMBTU per day of such amount was contracted at the CIG first of month price and the remaining 12,000 MMBtu per day was priced at the NW Rockies first of month price. Beginning in the second quarter of 2008, the entire contracted amount was based on NW Rockies first of month price. We have elected the normal purchase and sale exemption under paragraph 10(b) of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” because we anticipate that (1) we will produce the volumes required to be delivered under the terms of the contract, (2) it is probable the delivery will be made to the counterparty and (3) the counterparty will fulfill its contractual obligations under the terms of the contracts. As such, we believe we are not required to treat the contract as a derivative and the contract will not be marked to market under the provisions of SFAS No. 133.

As discussed in Note 2, we have entered into derivative contracts relating to a portion of our 2008 and 2009 natural gas production.

NOTE 16 — EMPLOYEE BENEFIT PLANS

The Company adopted a 401(k) profit sharing plan (the “Plan”) in October 2001, available to (employees who meet the Plan’s eligibility requirements. The Plan is a defined contribution plan. The Company may make discretionary contributions to the Plan and is required to contribute 3% of each participating employee’s compensation to the Plan. The contributions made by the Company totaled $150,617, $143,293 and $76,685 during the years ended December 31, 2008, 2007 and 2006, respectively.

NOTE 17 — SELECTED QUARTERLY INFORMATION (Unaudited)

The following represents selected quarterly financial information for the years ended December 31, 2008 and 2007.


	For the Quarter Ended
2008	March 31,			June 30,			September 30,		December 31,
Gross revenue (a)	$	9,755,723		$	14,092,926		$	11,228,854	$	6,780,670
Net revenue from oil and gas operations		7,470,247			10,695,833			8,688,033		3,465,837
Net income (loss)		(4,410,117	)		(788,608	)		21,039,898		(1,327,228	)
Net income (loss) per share
Basic		(0.04	)		(0.01	)		0.20		(0.01	)
Diluted		(0.04	)		(0.01	)		0.17		(0.01	)


(a)		The Form 10-Q’s for the first three quarters of 2008 reflected derivative gains (losses) and interest income as revenue. During the fourth quarter of 2008 the Company reclassified these amounts from revenue to other income (expense) in the accompanying consolidated statements of operations. The amounts in the table above reflect this reclassification for all periods presented.


	For the Quarter Ended
2007	March 31,			June 30,			September 30,			December 31,
Gross revenue (b)	$	6,339,371		$	5,940,463		$	3,926,379		$	5,916,418
Net revenue from oil and gas operations		5,388,389			4,241,645			2,089,513			2,969,421
Net loss		(176,174	)		(66,294,642	) (c)		(35,146,725	) (c)		(2,756,380	)
Net loss per share basic and diluted		(0.00	)		(0.70	)		(0.37	)		(0.03	)

(b)		During the fourth quarter of 2008 the Company reclassified derivative gains (losses) and interest income from revenue to other income (expense) in the accompanying consolidated statements of operations. The amounts in the table above reflect this reclassification for all periods presented.

(c)		The increase in the Company’s net loss during the second third quarters as compared with the other quarters is primarily due to the $64,300,000 impairment recorded at June 30, 2006 and the $32,790,000 impairment recorded at September 30, 2007 as further discussed in Note 2.

NOTE 18 — LEGAL PROCEEDINGS

In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), a wholly owned subsidiary of the Company, that was preparing air emission calculations for possible future capacity expansions, preliminarily determined that Riverbend may have not accurately calculated the amount of air pollutants that could be emitted from certain existing equipment at its Riverbend Compressor Station in Uintah County, Utah. Riverbend thereafter undertook a more detailed assessment, which confirmed that Riverbend had not obtained certain air permits nor complied with certain air pollution regulatory programs that were applicable to its operations at the Riverbend Compressor Station. On June 22, 2007, Riverbend sent a letter to the United States Environmental Protection Agency (“EPA”) Region 8 office in Denver, Colorado, which—because the Riverbend Compressor Station is located in Indian Country—is the agency that has jurisdiction over federal air permitting and air pollution regulatory programs. Riverbend’s June 22 letter voluntarily disclosed the potential violations to EPA and informed the agency of the steps that Riverbend had taken and planned to take to achieve compliance. In November 2007, Riverbend met with EPA Region 8 personnel and discussed the disclosed violations, its plans to bring the Riverbend Compressor Station into compliance, and possible resolution of the disclosed violations. In a letter to 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 EPA and the Department of Justice on a settlement of this matter, and it anticipates that such a resolution will be achieved during 2009. Riverbend believes 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 the Company’s capital budget, and that any civil penalty that may be assessed in conjunction with a resolution of this matter will not materially affect the Company’s financial position.

NOTE 19 — CONSOLIDATING FINANCIAL STATEMENTS

On August 22, 2008, Gasco filed a Form S-3 shelf registration statement with the Securities Exchange Commission. Under this registration statement, which was declared effective on

100

September 8, 2008, we may from time to time offer and sell securities including common stock, preferred stock, depositary shares and debt securities that may be fully, irrevocably and unconditionally guaranteed by all of our subsidiaries: Gasco Production Company, San Joaquin Oil & Gas, Ltd., Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (“Guarantor Subsidiaries”). Set forth below are the condensed consolidating financial statements of Gasco, which is referred to as the Parent, and the Guarantor Subidiaries. In accordance with generally accepted accounting principles the financial statements of the parent would include an investment in its subsidiaries. These condensed statements are presented for information purposes only and do not purport the parent’s balance sheet or statement of operations are prepared under generally accepted accounting principles.

101

Condensed Consolidating Balance Sheet
As of December 31, 2008
(Unaudited)


				Guarantor
	Parent			Subsidiaries			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	501,511		$	551,705		$	1,053,216
Accounts receivable		451,050			8,813,536			9,264,586
Inventory		—			4,177,967			4,177,967
Derivative instruments		8,855,947			—			8,855,947
Prepaid expenses		188,485			325			188,810

Total		9,996,993			13,543,533			23,540,526

PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests		71,021			247,905,833			247,976,854
Unproved mineral interests		1,054,096			38,260,310			39,314,406
Wells in progress		—			644,688			644,688
Gathering assets		—			17,440,680			17,440,680
Facilities and equipment		—			8,549,928			8,549,928
Furniture, fixtures and other		371,605			—			371,605

Total		1,496,722			312,801,439			314,298,161
Less accumulated depreciation, depletion and amortization		(229,318	)		(185,356,264	)		(185,585,582	)

Total		1,267,404			127,445,175			128,712,579

OTHER ASSETS
Deposit		139,500			—			139,500
Deferred financing costs		1,492,903			—			1,492,903
Intercompany		244,524,964			(244,524,964	)		—

Total		246,157,367			(244,524,964	)		1,632,403

TOTAL ASSETS	$	257,421,764		$	(103,536,256	)	$	153,885,508


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	212,172		$	5,666,978		$	5,879,150
Revenue payable		—			3,840,985			3,840,985
Advances from joint interest owners		—			612,222			612,222
Accrued interest		1,187,495			—			1,187,495
Accrued expenses		1,126,000			—			1,126,000

Total		2,525,667			10,120,185			12,645,852

NONCURRENT LIABILITIES
5.5% Convertible Senior Notes		65,000,000			—			65,000,000
Long-term debt		31,000,000			—			31,000,000
Asset retirement obligation		—			1,150,179			1,150,179
Deferred rent expense		46,589			—			46,589

Total		96,046,589			1,150,179			97,196,768

STOCKHOLDERS’ EQUITY
Common stock		10,783			—			10,783
Other		158,838,725			(114,806,620	)		44,032,105

Total		158,849,508			(114,806,620	)		44,042,888

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	257,421,764		$	(103,536,256	)	$	153,885,508

102

Condensed Consolidating Balance Sheet
As of December 31, 2008
(Unaudited)


				Guarantor
	Parent			Subsidiaries			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,843,425		$	—		$	1,843,425
Accounts receivable		—			9,512,133			9,512,133
Inventory		—			1,160,325			1,160,325
Prepaid expenses		326,705			325			327,030

Total		2,170,130			10,672,783			12,842,913

PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests		39,994			215,233,599			215,273,593
Unproved mineral interests		1,504,096			40,140,252			41,644,348
Wells in progress		—			1,058,727			1,058,727
Gathering assets		—			15,708,353			15,708,353
Facilities and equipment		—			9,680,010			9,680,010
Furniture, fixtures and other		284,791			—			284,791

Total		1,828,881			281,820,941			283,649,822
Less accumulated depreciation, depletion and amortization		(164,713	)		(175,809,007	)		(175,973,720	)

Total		1,664,168			106,011,934			107,676,102

OTHER ASSETS
Deposit		139,500			—			139,500
Deferred financing costs		1,853,274			—			1,853,274
Intercompany		230,850,204			(230,850,204	)		—

Total		232,842,978			(230,850,204	)		1,992,774

TOTAL ASSETS	$	236,677,276		$	(114,165,487	)	$	122,511,789


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	230,737		$	12,976,030		$	13,206,767
Revenue payable		—			1,477,268			1,477,268
Advances from joint interest owners		—			5,718,234			5,718,234
Derivative instruments		343,759			—			343,759
Accrued interest		844,094			—			844,094
Accrued expenses		583,000			—			583,000

Total		2,001,590			20,171,532			22,173,122

NONCURRENT LIABILITIES
5.5% Convertible Senior Notes		65,000,000			—			65,000,000
Long-term debt		9,000,000			—			9,000,000
Asset retirement obligation		—			1,030,283			1,030,283
Deferred rent expense		60,593			—			60,593

Total		74,060,593			1,030,283			75,090,876

STOCKHOLDERS’ EQUITY
Common stock		10,729			—			10,729
Other		160,604,364			(135,367,302	)		25,237,062

Total		160,615,093			(135,367,302	)		25,247,791

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	236,677,276		$	(114,165,487	)	$	122,511,789

Consolidating Statements of Operations
(Unaudited)

For the Year Ended December 31, 2008


				Guarantor
	Parent			Subsidiaries		Consolidated
REVENUES
Oil and gas	$	—		$	35,634,832	$	35,634,832
Gathering		—			4,796,409		4,796,409
Rental income		—			1,426,932		1,426,932

Total		—			41,858,173		41,858,173


OPERATING EXPENSES
Lease operating		—			6,653,698		6,653,698
Gathering operations		—			3,457,593		3,457,593
Depletion, depreciation, amortization and accretion		64,605			9,412,339		9,476,944
Impairment					3,500,000		3,500,000
General and administrative		9,211,806			—		9,211,806

Total		9,276,411			23,023,630		32,300,041


OTHER INCOME (EXPENSE)
Interest expense		(5,151,136	)		—		(5,151,136	)
Derivative gains (losses)		9,761,826			—		9,761,826
Gain on sale of inventory		—			318,740		318,740
Interest income		26,369			14		26,383

Total		4,637,059			318,754		4,955,813


NET INCOME (LOSS)	$	(4,639,352	)	$	19,153,297	$	14,513,945

For the Year Ended December 31, 2007


				Guarantor
	Parent			Subsidiaries			Consolidated
REVENUES
Oil and gas	$	—		$	19,155,752		$	19,155,752
Gathering		—			1,937,785			1,937,785
Rental income		—			1,029,094			1,029,094

Total		—			22,122,631			22,122,631


OPERATING EXPENSES
Lease operating		—			3,932,924			3,932,924
Gathering operations		—			2,471,645			2,471,645
Depletion, depreciation, amortization and accretion		62,729			9,718,038			9,780,767
Impairment		—			97,090,000			97,090,000
General and administrative		9,021,977			—			9,021977

Total		9,084,706			113,212,607			122,297,313


OTHER INCOME (EXPENSE)
Interest expense		(4,274,814	)		—			(4,274,814	)
Derivative losses		(343,759	)		—			(343,759	)
Interest income		418,854			480			419,334

Total		(4,199,719	)		480			(4,199,239	)


NET LOSS	$	(13,284,425	)	$	(91,089,496	)	$	(104,373,921	)

104

Consolidating Statements of Operations
(Unaudited)

For the Year Ended December 31, 2006


				Guarantor
	Parent			Subsidiaries			Consolidated
REVENUES
Oil and gas	$	—		$	21,039,172		$	21,039,172
Gathering		—			1,941,059			1,941,059

Total		—			22,980,231			22,980,231


OPERATING EXPENSES
Lease operating		—			3,513,568			3,513,568
Gathering operations		—			2,718,357			2,718,357
Depletion, depreciation and amortization		58,513			10,827,184			10,885,697
Impairment		—			51,000,000			51,000,000
General and administrative		9,415,787			—			9,415,787

Total		9,474,300			68,059,109			77,533,409


OTHER INCOME (EXPENSE)
Interest expense		(3,959,308	)		—			(3,959,308	)
Interest income		2,693,955			764			2,694,719

Total		(1,265,353	)		764			(1,264,589	)


NET LOSS		(10,739,653	)		(45,078,114	)		(55,817,767	)
Preferred stock dividends		(1,393	)		—			(1,393	)


NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(10,741,046	)	$	(45,078,114	)	$	(55,819,160	)

105

Consolidating Statements of Cash Flows
(Unaudited)

For the Year Ended December 31, 2008


				Guarantor
	Parent			Subsidiaries			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(10,580,567	)	$	28,733,207		$	18,152,640

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(86,814	)		—			(86,814	)
Cash paid for acquisitions, development and exploration		—			(44,250,250	)		(44,250,250	)
Advances from joint interest owners		—			(5,106,012	)		(5,106,012	)
Proceeds from property sales		—			7,500,000			7,500,000

Net cash used in investing activities		(86,814	)		(41,856,262	)		(41,943,076	)


CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit		42,000,000			—			42,000,000
Repayment of borrowings		(20,000,000	)		—			(20,000,000	)
Cash paid for debt issuance costs		(161,057	)		—			(161,057	)
Exercise of options to purchase common stock		1,161,284			—			1,161,284
Intercompany		(13,674,760	)		13,674,760			—

Net cash provided by financing activities		9,325,467			13,674,760			23,000,227


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,341,914	)		551,705			(790,209	)
CASH AND CASH EQUIVALENTS:

BEGINNING OF PERIOD		1,843,425			—			1,843,425


END OF PERIOD	$	501,511		$	551,705		$	1,053,216

106

Consolidating Statements of Cash Flows
(Unaudited)

For the Year Ended December 31, 2007


				Guarantor
	Parent			Subsidiaries			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	29,191,369		$	(20,370,083	)	$	8,821,286

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(43,782	)		—			(43,782	)
Cash paid for acquisitions, development and exploration		—			(63,508,825	)		(63,508,825	)
Advances from joint interest owners		—			2,825,300			2,825,300
Brek acquisition costs net of cash received		—			(356,857	)		(356,857	)
Proceeds from property sales		—			3,475,153			3,475,153
Proceeds from sale of short-term investments		6,000,000			—			6,000,000
Cash undesignated as restricted		3,575,000			—			3,575,000

Net cash provided by (used) in investing activities		9,531,218			(57,565,229	)		(48,034,011	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the sale of common stock		19,300,000			—			19,300,000
Cash paid for offering costs		(120,729	)		—			(120,729	)
Borrowings under line of credit		18,000,000			—			18,000,000
Repayment of borrowings		(9,000,000	)		—			(9,000,000	)
Intercompany		(75,889,515	)		75,889,515			—

Net cash provided by (used in) financing activities		(47,710,244	)		75,889,515			28,179,271


NET DECREASE IN CASH AND CASH EQUIVALENTS		(8,987,657	)		(2,045,797	)		(11,033,454	)
CASH AND CASH EQUIVALENTS:

BEGINNING OF PERIOD		10,831,082			2,045,797			12,876,879


END OF PERIOD	$	1,843,425		$	—		$	1,843,425

107

Consolidating Statements of Cash Flows
(Unaudited)

For the Year Ended December 31, 2006


				Guarantor
	Parent			Subsidiaries			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(7,015,061	)	$	15,898,016		$	8,882,955

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(67,994	)		—			(67,994	)
Cash paid for acquisitions, development and exploration		—			(79,557,785	)		(79,557,785	)
Proceeds from sale of short-term investments		9,000,000			—			9,000,000
Advances from joint interest owners		—			479,296			479,296
Cash designated as restricted		(9,980	)		—			(9,980	)
Cash undesignated as restricted		10,139,000			—			10,139,000

Net cash provided by (used) in investing activities		19,061,026			(79,078,489	)		(60,017,463	)


CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends		(1,393	)		—			(1,393	)
Cash paid for offering costs		(240,262	)		—			(240,262	)
Exercise of options to purchase common stock		1,591,674			—			1,591,674
Intercompany		(61,879,245	)		61,879,245			—

Net cash provided by (used in) financing activities		(60,529,226	)		61,879,245			1,350,019


NET DECREASE IN CASH AND CASH EQUIVALENTS		(48,483,261	)		(1,301,228	)		(49,784,489	)
CASH AND CASH EQUIVALENTS:

BEGINNING OF PERIOD		59,314,343			3,347,025			62,661,368


END OF PERIOD	$	10,831,082		$	2,045,797		$	12,876,879

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

The following reserve quantity and future net cash flow information for the Company represents estimated proved reserves located in the United States. The reserves as of December 31, 2008, 2007 and 2006 have been estimated by Netherland, Sewell and Associates, Inc., independent petroleum engineers. The determination of oil and gas reserves is based on estimates, which are highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available.

The standardized measure of discounted future net cash flows is prepared under the guidelines set forth by the Securities and Exchange Commission (SEC) that require the calculation to be performed using year-end oil and gas prices. The average oil and gas prices weighted by production over the lives of the proved reserves used as of December 31, 2008, 2007 and 2006 were $15.33 per bbl of oil and $4.63 per Mcf of gas, $73.95 per bbl of oil and $6.53 per Mcf and $45.53 per bbl of oil and $4.47 per Mcf, respectively. Future production costs are based on year-end costs and include severance taxes. Each property that is operated by the Company is also charged with field-level overhead in the reserve calculation. The present value of future cash inflows is based on a 10% discount rate.


	Gas			Oil
Reserve Quantities	Mcf			Bbls
Proved Reserves:
Balance, December 31, 2005		74,455,128			377,288
Extensions and discoveries		16,006,692			97,529
Revisions of previous estimates (a)		(47,010,172	)		(212,400	)
Sales of reserves in place		—			—
Purchases of reserves in place		210,954			129,810
Production		(3,686,638	)		(21,646	)


Balance, December 31, 2006		39,975,964			370,581
Extensions and discoveries		23,854,007			160,302
Revisions of previous estimates (b)		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 (c)		(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

109


	Gas		Oil
	Mcf		Bbls
Proved Developed Reserves
Balance, December 31, 2008		50,909,308		361,185

Balance, December 31, 2007		50,820,623		695,019

Balance, December 31, 2006		38,817,964		370,581

(a)

The majority of the revisions of previous estimates during 2006 were a result of the following:

	•		Fifty gross locations previously classified as proved undeveloped were omitted from the 2006 reserve report because these locations did not yield a positive net present value at a discount rate of 10% at the then current estimated capital investment based on historical data to drill and complete wells in this area.

	•		Four gross locations previously classified as proved undeveloped were developed in 2006 and two gross proved undeveloped locations were added.

	(b)		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.

	(c)		The majority of the revisions of previous estimates during 2008 were primarily due to the decrease in oil and gas prices from $73.95 per barrel and $6.53 per Mcf at December 31, 2007 to $15.33 per barrel and $4.63 per Mcf at December 31, 2008.

Standardized Measure of Discounted Future Net Cash Flows


	December 31,
	2008			2007			2006
Future cash flows	$	241,343,700		$	760,539,800		$	195,545,000
Future production and development costs		(108,727,900	)		(339,452,900	)		(69,135,000	)
Future income taxes		—			(9,765,200	)		—

Future net cash flows before discount		132,615,800			411,321,700			126,410,000
10% discount to present value		(63,133,000	)		(250,857,700	)		(63,242,800	)

Standardized measure of discounted future net cash flows	$	69,482,800		$	160,464,000		$	63,167,200

110

Changes in the Standardized Measure of Discounted Future Net Cash Flows


	For the Years Ended December 31,
	2008			2007			2006
Standardized measure of discounted future net cash flows at the beginning of year	$	160,464,000		$	63,167,200		$	104,621,000
Sales of oil and gas produced, net of production costs		(28,981,134	)		(15,322,828	)		(17,525,604	)
Net changes in prices and production costs		(34,529,372	)		26,226,507			(110,791,730	)
Extensions and discoveries, net of future production and development costs		2,311,000			40,839,394			26,686,765
Previously estimated development costs incurred		5,393,989			4,489,959			9,571,134
Changes in estimated future development costs		(2,981,737	)		(3,882,200	)		127,888,117
Revisions of previous quantity estimates		(44,761,342	)		43,121,203			(77,662,093	)
Purchases of reserves in place		—			11,097,303			1,592,041
Sales of reserves in place		(7,703,000	)		(1,798,971	)		—
Net change in income taxes		1,378,483			(1,378,483	)		3,225,000
Accretion of discount		17,711,306			4,502,716			13,773,265
Other		1,180,242			(10,597,800	)		(18,210,695	)

Standardized measure of discounted future net cash flows at the end of year	$	69,482,800		$	160,464,000		$	63,167,200

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

None.

ITEM 9A — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management has evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2008. Our disclosure controls and procedures are designed to provide us with a reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management as appropriate to allow such persons to make timely decisions regarding required disclosures.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and our CEO and CFO have concluded, as of December 31, 2008, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

Internal control over financial reporting

Our internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with GAAP. These internal controls over financial reporting were designed under the supervision of our management and include policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

112

Changes in internal control over financial reporting during the fourth quarter of 2008. There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) or in other factors that occurred during the fiscal quarter ended December 31, 2008, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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

Management’s Report on Internal Control Over Financial Reporting

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

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

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria set for by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on our assessment and those criteria, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2008.

113

Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended, this Annual Report on Internal Control Over Financial Reporting has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on March 4, 2009.

/s/ Mark A. Erickson
Mark A. Erickson
President & Chief Executive Officer

/s/ W. King Grant
W. King Grant
Chief Financial Officer

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Gasco Energy, Inc.:

We have audited Gasco Energy, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and

114

procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

In our opinion, Gasco Energy, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Gasco Energy, Inc. and subsidiaries as of December 31, 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended, and our report dated March 4, 2009 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Denver, Colorado
March 4, 2009

ITEM 9B — OTHER INFORMATION

None.

PART III

ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2009 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

115

ITEM 11 — EXECUTIVE COMPENSATION

ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14 — PRINCIPAL ACCOUNTING FEES AND SERVICES

ITEM 15 — EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

1. See “Index to Financial Statements” under Item 8 on page 61.
2. Financial Statement Schedules — none.
3. Exhibits — See Index to Exhibits, below.

INDEX TO EXHIBITS

2.1		Agreement and Plan of Reorganization dated January 31, 2001 among San Joaquin Resources Inc., Nampa Oil & Gas, Ltd., and Pannonian Energy, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated January 31, 2001, filed on February 2, 2001, File No. 000-26321).

2.2		Agreement and Plan of Reorganization dated December 15, 1999 by and between LEK International, Inc. and San Joaquin Oil & Gas Ltd. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).

2.3		Property Purchase Agreement dated as of April 23, 2002, between the Company and Shama Zoe Limited Partnership (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated May 1, 2002, filed on May 7, 2002, File No. 000-26321).

116

2.4		Purchase Agreement dated as of July 16, 2002, among Gasco, Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek, Brek Petroleum Inc., Brek Petroleum (California), Inc. and certain stockholders of Gasco. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated July 16, 2002, filed on July 31, 2002, File No. 000-26321).

2.5		Purchase and Sale Agreement between ConocoPhillips and the Company relating to the Riverbend Field, Uintah and Duchesne Counties, Utah, Effective January 1, 2004 (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 9, 2004, filed on March 15, 2004, File No. 000-26321).

2.6		Net Profits Purchase Agreement between Gasco Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 6, 2004 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed September 7, 2004, File No. 000-26321).

2.7		Purchase Supplement to Net Profits Purchase Agreement between Gasco Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 20, 2004 (incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K filed September 7, 2004, File No. 000-26321).

2.8		Agreement and Plan of Merger dated January 31, 2007, by and among Gasco Energy, Inc., Gasco Acquisition, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).

2.9		First Amendment to Agreement and Plan of Merger dated January 31, 2007, by and between Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated January 31, 2007, filed February 2, 2007, File No. 001-32369).

2.10		Second Amendment to Agreement and Plan of Merger dated January 31, 2007, by and among Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated May 29, 2007, filed May 30, 2007, File No. 001-32369).

2.11		Third Amendment to Agreement and Plan of Merger dated October 22, 2007, by and between Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated October 22, 2007, filed October 23, 2007, File No. 001-32369).

3.1		Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).

3.2		Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).

3.3		Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).

3.4		Amended and Restated Bylaws of Gasco Energy, Inc., dated June 26, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated June 26, 2007, filed on June 27, 2007, File No. 001-32369).

3.5		Certificate of Designation for Series B Convertible Preferred Stock (incorporated by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement dated April 16, 2003, filed April 17, 2003, File No. 333-104592).

117

4.1		Form of Subscription and Registration Rights Agreement, dated as of August 14, 2002 between the Company and certain investors Purchasing Common Stock in August, 2002. (Filed as Exhibit 10.21 to the Company’s Form S-1 Registration Statement dated August 26, 2002, filed on August 27, 2002, File No. 333-98759).

4.2		Form of Gasco Energy, Inc. 8.00% Convertible Debenture, dated October 15, 2003 between each of The Frost National Bank, Custodian FBO Renaissance US Growth & Investment Trust PLC Trust No. W00740100, HSBC Global Custody Nominee (U.K.) Limited Designation No. 896414 and The Frost National Bank, Custodian FBO Renaissance Capital Growth & Income Fund III, Inc. Trust No. W00740000 (incorporated by reference to Exhibit 4.6 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.3		Deed of Trust and Security Agreement, dated October 15, 2003 between Pannonian and BFSUS Special Opportunities Trust PLC, Renaissance Capital Growth & Income Fund III, Inc. and Renaissance US Growth & Income Trust PLC (incorporated by reference to Exhibit 4.7 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.4		Subsidiary Guaranty Agreement, dated October 15, 2003 between Pannonian and Renn Capital Group, Inc (incorporated by reference to Exhibit 4.8 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.5		Subsidiary Guaranty Agreement, dated October 15, 2003 between San Joaquin Oil and Gas, Ltd. And Renn Capital Group, Inc (incorporated by reference to Exhibit 4.9 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.6		Form of Subscription and Registration Rights Agreement between the Company and investors purchasing Common Stock in October 2003 (incorporated by reference to Exhibit 4.10 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.7		Form of Subscription and Registration Rights Agreement between the Company and investors purchasing Common Stock in February, 2004 (incorporated by reference to Exhibit 4.7 to the Company’s Form 10-K for the year ended December 31, 2003, filed on March 26, 2004, File No. 000-26321).

4.8		Indenture dated as of October 20, 2004, between Gasco Energy, Inc. and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).

4.9		Form of Global Note representing $65 million principal amount of 5.5% Convertible Senior Notes due 2011 (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).

4.10		Registration Rights Agreement dated October 20, 2004, among Gasco Energy, Inc., J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporate by reference to Exhibit 4.10 to the Company’s Form 10-Q for the quarter ended September 30, 2004 filed on November 12, 2004, File No. 000-26321).

4.11		Pledge and Security Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K dated March 29, 2006, filed March 31, 2006, File No. 001-32369).

118

4.12		Credit Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated March 29, 2006, filed March 31, 2006, File No. 001-32369).

4.13		First Amendment to the Credit Agreement dated April 22, 2008 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 4.13 to the Company’s Form 10-Q dated March 31, 2008, filed May 6, 2008, File No. 001-32369).

4.14		Second Amendment to the Credit Agreement, dated as of December 10, 2008, by and among by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated December 12, 2008, filed on December 12, 2008, File No. 001-32369).

4.15		Voting Agreement dated September 20, 2006 by and among Gasco Energy, Inc., Richard N. Jeffs, Gregory Pek, Ian Robinson, Michael L. Nazmack, Eugene Sweeney and Shawne Malone (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).

4.16		Underwriting Agreement dated April 13, 2007, between Gasco Energy, Inc. and JP Morgan Securities Inc. (incorporated by reference to Exhibit 1.1 to the Company’s Form 8-K dated April 9, 2007, filed April 13, 2007, File No. 001-32369).

#10.1		1999 Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-KSB for the fiscal year ended December 31, 1999, filed on April 14, 2000, File No. 000-26321).

#10.2		Form of Stock Option Agreement under the 1999 Stock Option Plan (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

#10.3		Stock Option Agreement dated January 2, 2001 between Gasco and Mark A. Erickson (Filed as Exhibit 10.9 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

#10.4		Form of Stock Option Agreement between Gasco and each of the individuals named therein (incorporated by reference to Exhibit 4.6 to the Company’s Form S-8 Registration Statement (Reg. No. 333-122716), filed on February 10, 2005).

#10.5		Michael Decker Amended and Restated Employment Contract dated February 14, 2003 (Filed as Exhibit 10.11 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).

#10.6		Mark A. Erickson Amended and Restated Employment Contract dated February 14, 2003 (Filed as Exhibit 10.12 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).

#10.7		Amended and Restated Consulting Agreement dated February 14, 2003, between Gasco and Marc Bruner (Filed as Exhibit 10.13 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).

#10.8		2003 Restricted Stock Plan (Filed as Appendix B to the Company’s Proxy Statement dated August 25, 2003 for its 2003 Annual Meeting of Stockholders, filed on August 25, 2003, File No. 000-26321).

119

#10.9		Termination and Settlement Agreement, dated as of December 23, 2004, among Gasco Energy, Inc., Marc A. Bruner and Mark A. Erickson (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2005, File No. 001-32369).

#10.10		Employment Agreement dated February 14, 2005 by and between Gasco Energy, Inc. and W. King Grant (incorporated by reference to Exhibit 4.2 to the Company’s Form 10-Q for the quarter ended March 31, 2006, filed May 5, 2006, File No. 001-32369).

#10.11		Form of Amendment to Gasco Energy, Inc. Employment Agreement, dated as of December 31, 2008, and effective as of January 1, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated January 7, 2009, filed January 7, 2009, File No. 001-32369).

*#10.12		Form of Second Amendment to Gasco Energy, Inc. Employment Agreement, dated as of January 22, 2009, by and among Gasco Energy, Inc. and certain of its Executives.

10.13		Participation Agreement dated August 1, 2007 by and between Gasco Production Company and NFR Uinta Basin LLC (incorporated by reference to Exhibit 10.11 to the Company’s Form 10-Q for the quarter ended June 30, 2007, filed August 1, 2007, File No. 001-32369).

10.14		Muddy Creek Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.15 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

10.15		CD Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.16 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

10.16		Gamma Ray Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.17 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

10.17		Sublette County, WY AMI Agreement dated August 22, 2001 between Gasco, Alpine Gas Company and Burlington Oil and Gas Company (Filed as Exhibit 10.18 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

10.18		Lead Contractor Agreement dated January 24, 2002, between Gasco and Halliburton Energy Services, Inc. (Filed as Exhibit 10.19 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

10.19		Property Purchase Agreement, dated as of April 23, 2002, between the Company and Shama Zoe Limited Partnership (Filed as Exhibit 2.1 to the Company’s Form 8-K dated May 1, 2002, filed on May 9, 2002, File No. 000-26321).

10.20		Purchase Agreement, dated as of July 16, 2002, among the Company, Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek Energy Corporation, Brek Petroleum Inc., Brek Petroleum (California), Inc. and certain stockholders (Filed as Exhibit 2.1 to the Company’s Form 8-K dated July 16, 2002, filed on July 31, 2002, File No. 000-26321).

10.21		Amendment No. 1 to Property Purchase Agreement dated as of August 9, 2002 between the Company and Shama Zoe Limited Partnership. (Filed as Exhibit 10.22 to the Company’s Form S-1 dated August 15, 2002, filed on August 17, 2002, File No. 333-98759).

120

10.22		Financial Advisory Services Agreement dated August 22, 2002, between the Company and Energy Capital Solutions LLC. (Filed as Exhibit 10.23 to the Company’s Form S-1 dated August 16, 2002, filed on August 17, 2002 File No. 333-98759).

10.23		Termination and Settlement Agreement, dated as of December 23, 2004, among Gasco Energy, Inc., Marc A. Bruner and Mark A. Erickson (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2005, File No. 001-32369).

10.24		Joint Value Enhancement Agreement by and among Pannonian Energy Inc., M-I, LLC, Nabors Drilling USA, LP, Pool Well Services Co., Red Oak Capital Management LLC and Schlumberger Technology Corporation dated January 16, 2004 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 21, 2004, File No. 000-26321).

*23.1		Consent of Netherland, Sewell & Associates, Inc.

*23.2		Consent of KPMG

*31		Rule 13a-14(a)/15d-14(a) Certifications

*32		Section 1350 Certifications


*		Filed herewith.

#		Identifies management contracts and compensatory plans or arrangements.

121

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


GASCO ENERGY, INC.						Dated: March 4, 2009


By:		/s/ Mark A. Erickson

		Mark A. Erickson, President and CEO

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ Mark A. Erickson Mark A. Erickson	Director and President and Chief Executive Officer	March 4, 2009

/s/ Marc A. Bruner Marc A. Bruner	Director	March 4, 2009

/s/ Carl Stadelhofer Carl Stadelhofer	Director	March 4, 2009

/s/ W. King Grant W. King Grant	Executive Vice President and Chief Financial Officer	March 4, 2009

/s/ Carmen Lotito Carmen (“Tony”) Lotito	Director	March 4, 2009

/s/ Charles B. Crowell Charles B. Crowell	Director	March 4, 2009

/s/ Richard S. Langdon Richard S. Langdon	Director	March 4, 2009

/s/ R. J. Burgess R.J. Burgess	Director	March 4, 2009

/s/ John A. Schmit John A. Schmit	Director	March 4, 2009

/s/ Peggy A. Herald Peggy A. Herald	Vice President and Chief Accounting Officer	March 4, 2009

122

INDEX TO EXHIBITS

2.1		Agreement and Plan of Reorganization dated January 31, 2001 among San Joaquin Resources Inc., Nampa Oil & Gas, Ltd., and Pannonian Energy, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated January 31, 2001, filed on February 2, 2001, File No. 000-26321).

2.2		Agreement and Plan of Reorganization dated December 15, 1999 by and between LEK International, Inc. and San Joaquin Oil & Gas Ltd. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).

2.3		Property Purchase Agreement dated as of April 23, 2002, between the Company and Shama Zoe Limited Partnership (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated May 1, 2002, filed on May 7, 2002, File No. 000-26321).

2.4		Purchase Agreement dated as of July 16, 2002, among Gasco, Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek, Brek Petroleum Inc., Brek Petroleum (California), Inc. and certain stockholders of Gasco. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated July 16, 2002, filed on July 31, 2002, File No. 000-26321).

2.5		Purchase and Sale Agreement between ConocoPhillips and the Company relating to the Riverbend Field, Uintah and Duchesne Counties, Utah, Effective January 1, 2004 (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 9, 2004, filed on March 15, 2004, File No. 000-26321).

2.6		Net Profits Purchase Agreement between Gasco Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 6, 2004 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed September 7, 2004, File No. 000-26321).

2.7		Purchase Supplement to Net Profits Purchase Agreement between Gasco Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 20, 2004 (incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K filed September 7, 2004, File No. 000-26321).

2.8		Agreement and Plan of Merger dated January 31, 2007, by and among Gasco Energy, Inc., Gasco Acquisition, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).

2.9		First Amendment to Agreement and Plan of Merger dated January 31, 2007, by and between Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated January 31, 2007, filed February 2, 2007, File No. 001-32369).

2.10		Second Amendment to Agreement and Plan of Merger dated January 31, 2007, by and among Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated May 29, 2007, filed May 30, 2007, File No. 001-32369).

2.11		Third Amendment to Agreement and Plan of Merger dated October 22, 2007, by and between Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated October 22, 2007, filed October 23, 2007, File No. 001-32369).

123

3.1		Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).

3.2		Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).

3.3		Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).

3.4		Amended and Restated Bylaws of Gasco Energy, Inc., dated June 26, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated June 26, 2007, filed on June 27, 2007, File No. 001-32369).

3.5		Certificate of Designation for Series B Convertible Preferred Stock (incorporated by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement dated April 16, 2003, filed April 17, 2003, File No. 333-104592).

4.1		Form of Subscription and Registration Rights Agreement, dated as of August 14, 2002 between the Company and certain investors Purchasing Common Stock in August, 2002. (Filed as Exhibit 10.21 to the Company’s Form S-1 Registration Statement dated August 26, 2002, filed on August 27, 2002, File No. 333-98759).

4.2		Form of Gasco Energy, Inc. 8.00% Convertible Debenture, dated October 15, 2003 between each of The Frost National Bank, Custodian FBO Renaissance US Growth & Investment Trust PLC Trust No. W00740100, HSBC Global Custody Nominee (U.K.) Limited Designation No. 896414 and The Frost National Bank, Custodian FBO Renaissance Capital Growth & Income Fund III, Inc. Trust No. W00740000 (incorporated by reference to Exhibit 4.6 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.3		Deed of Trust and Security Agreement, dated October 15, 2003 between Pannonian and BFSUS Special Opportunities Trust PLC, Renaissance Capital Growth & Income Fund III, Inc. and Renaissance US Growth & Income Trust PLC (incorporated by reference to Exhibit 4.7 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.4		Subsidiary Guaranty Agreement, dated October 15, 2003 between Pannonian and Renn Capital Group, Inc (incorporated by reference to Exhibit 4.8 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.5		Subsidiary Guaranty Agreement, dated October 15, 2003 between San Joaquin Oil and Gas, Ltd. And Renn Capital Group, Inc (incorporated by reference to Exhibit 4.9 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.6		Form of Subscription and Registration Rights Agreement between the Company and investors purchasing Common Stock in October 2003 (incorporated by reference to Exhibit 4.10 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.7		Form of Subscription and Registration Rights Agreement between the Company and investors purchasing Common Stock in February, 2004 (incorporated by reference to Exhibit 4.7 to the Company’s Form 10-K for the year ended December 31, 2003, filed on March 26, 2004, File No. 000-26321).

124

4.8		Indenture dated as of October 20, 2004, between Gasco Energy, Inc. and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).

4.9		Form of Global Note representing $65 million principal amount of 5.5% Convertible Senior Notes due 2011 (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).

4.10		Registration Rights Agreement dated October 20, 2004, among Gasco Energy, Inc., J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporate by reference to Exhibit 4.10 to the Company’s Form 10-Q for the quarter ended September 30, 2004 filed on November 12, 2004, File No. 000-26321).

4.11		Pledge and Security Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K dated March 29, 2006, filed March 31, 2006, File No. 001-32369).

4.12		Credit Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated March 29, 2006, filed March 31, 2006, File No. 001-32369).

4.13		First Amendment to the Credit Agreement dated April 22, 2008 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 4.13 to the Company’s Form 10-Q dated March 31, 2008, filed May 6, 2008, File No. 001-32369).

4.14		Second Amendment to the Credit Agreement, dated as of December 10, 2008, by and among by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated December 12, 2008, filed on December 12, 2008, File No. 001-32369).

4.15		Voting Agreement dated September 20, 2006 by and among Gasco Energy, Inc., Richard N. Jeffs, Gregory Pek, Ian Robinson, Michael L. Nazmack, Eugene Sweeney and Shawne Malone (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).

4.16		Underwriting Agreement dated April 13, 2007, between Gasco Energy, Inc. and JP Morgan Securities Inc. (incorporated by reference to Exhibit 1.1 to the Company’s Form 8-K dated April 9, 2007, filed April 13, 2007, File No. 001-32369).

#10.1		1999 Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-KSB for the fiscal year ended December 31, 1999, filed on April 14, 2000, File No. 000-26321).

#10.2		Form of Stock Option Agreement under the 1999 Stock Option Plan (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

#10.3		Stock Option Agreement dated January 2, 2001 between Gasco and Mark A. Erickson (Filed as Exhibit 10.9 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

125

#10.4		Form of Stock Option Agreement between Gasco and each of the individuals named therein (incorporated by reference to Exhibit 4.6 to the Company’s Form S-8 Registration Statement (Reg. No. 333-122716), filed on February 10, 2005).

#10.5		Michael Decker Amended and Restated Employment Contract dated February 14, 2003 (Filed as Exhibit 10.11 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).

#10.6		Mark A. Erickson Amended and Restated Employment Contract dated February 14, 2003 (Filed as Exhibit 10.12 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).

#10.7		Amended and Restated Consulting Agreement dated February 14, 2003, between Gasco and Marc Bruner (Filed as Exhibit 10.13 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).

#10.8		2003 Restricted Stock Plan (Filed as Appendix B to the Company’s Proxy Statement dated August 25, 2003 for its 2003 Annual Meeting of Stockholders, filed on August 25, 2003, File No. 000-26321).

#10.9		Termination and Settlement Agreement, dated as of December 23, 2004, among Gasco Energy, Inc., Marc A. Bruner and Mark A. Erickson (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2005, File No. 001-32369).

#10.10		Employment Agreement dated February 14, 2005 by and between Gasco Energy, Inc. and W. King Grant (incorporated by reference to Exhibit 4.2 to the Company’s Form 10-Q for the quarter ended March 31, 2006, filed May 5, 2006, File No. 001-32369).

#10.11		Form of Amendment to Gasco Energy, Inc. Employment Agreement, dated as of December 31, 2008, and effective as of January 1, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated January 7, 2009, filed January 7, 2009, File No. 001-32369).

*#10.12		Form of Second Amendment to Gasco Energy, Inc. Employment Agreement, dated as of January 22, 2009, by and among Gasco Energy, Inc. and certain of its Executives.

10.13		Participation Agreement dated August 1, 2007 by and between Gasco Production Company and NFR Uinta Basin LLC (incorporated by reference to Exhibit 10.11 to the Company’s Form 10-Q for the quarter ended June 30, 2007, filed August 1, 2007, File No. 001-32369).

10.14		Muddy Creek Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.15 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

10.15		CD Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.16 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

10.16		Gamma Ray Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.17 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

10.17		Sublette County, WY AMI Agreement dated August 22, 2001 between Gasco, Alpine Gas Company and Burlington Oil and Gas Company (Filed as Exhibit 10.18 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

126

10.18		Lead Contractor Agreement dated January 24, 2002, between Gasco and Halliburton Energy Services, Inc. (Filed as Exhibit 10.19 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

10.19		Property Purchase Agreement, dated as of April 23, 2002, between the Company and Shama Zoe Limited Partnership (Filed as Exhibit 2.1 to the Company’s Form 8-K dated May 1, 2002, filed on May 9, 2002, File No. 000-26321).

10.20		Purchase Agreement, dated as of July 16, 2002, among the Company, Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek Energy Corporation, Brek Petroleum Inc., Brek Petroleum (California), Inc. and certain stockholders (Filed as Exhibit 2.1 to the Company’s Form 8-K dated July 16, 2002, filed on July 31, 2002, File No. 000-26321).

10.21		Amendment No. 1 to Property Purchase Agreement dated as of August 9, 2002 between the Company and Shama Zoe Limited Partnership. (Filed as Exhibit 10.22 to the Company’s Form S-1 dated August 15, 2002, filed on August 17, 2002, File No. 333-98759).

10.22		Financial Advisory Services Agreement dated August 22, 2002, between the Company and Energy Capital Solutions LLC. (Filed as Exhibit 10.23 to the Company’s Form S-1 dated August 16, 2002, filed on August 17, 2002 File No. 333-98759).

10.23		Termination and Settlement Agreement, dated as of December 23, 2004, among Gasco Energy, Inc., Marc A. Bruner and Mark A. Erickson (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2005, File No. 001-32369).

10.24		Joint Value Enhancement Agreement by and among Pannonian Energy Inc., M-I, LLC, Nabors Drilling USA, LP, Pool Well Services Co., Red Oak Capital Management LLC and Schlumberger Technology Corporation dated January 16, 2004 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 21, 2004, File No. 000-26321).

*23.1		Consent of Netherland, Sewell & Associates, Inc.

*23.2		Consent of KPMG

*31		Rule 13a-14(a)/15d-14(a) Certifications

*32		Section 1350 Certifications


*		Filed herewith.

#		Identifies management contracts and compensatory plans or arrangements.

127


Report of Independent Registered Public Accounting Firm			62-63

Consolidated Balance Sheets at December 31, 2008 and 2007			64-65

Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006			66

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006			67

Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006			68

Notes to Consolidated Financial Statements			69-111


Part I

Item 1. Business			1
Business of Gasco			1
Principal Products or Services and Markets			1
Competitive Business Conditions, Competitive Position in the Industry and Methods of Competition			2
Governmental Regulations and Environmental Laws			2
Number of Full-time Employees			5
Available Information			5
Cautionary Statement About Forward-Looking Statements			6
Glossary of Natural Gas and Oil Terms			7

Item 1 A. Risk Factors			11

Item 1 B. Unresolved Staff Comments			26

Item 2. Properties			26
Petroleum and Natural Gas Properties			26
Company Reserve Estimates			28
Volumes, Prices and Operating Expenses			29
Development, Exploration and Acquisition Capital Expenditures			30
Productive Oil and Gas Wells			31
Oil and Gas Acreage			31
Drilling Activity			32
Office Space			33

Item 3. Legal Proceedings			33

Item 4. Submission of Matters to a Vote of Security Holders			34

Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			34
Securities Authorized for Issuance Under Equity Compensation Plans			35

Item 6. Selected Financial Data			35

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			35
Forward Looking Statements			35
Overview			36
Recent Developments			36
Drilling Activity			39
Production and Reserve Information			40
Liquidity and Capital Resources			41
Capital Budget			41


Sources and Uses of Funds			41
Schedule of Contractual Obligations			42
Credit Agreement			43
Convertible Notes			44
Forward Sales Contract			45
Derivatives			46
Stock Offering			46
Drilling Program			46
Acquisition			46
Critical Accounting Policies and Estimates			47
Results of Operations			50
Recent Accounting Pronouncements			56

Item 7A. Quantitative and Qualitative Disclosures about Market Risk			59

Item 8. Financial Statements and Supplementary Data			61

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			112

Item 9A. Controls and Procedures			112

Item 9B. Other Information			115

Part III

Item 10. Directors, Executive Officers and Corporate Governance			115

Item 11. Executive Compensation			116

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			116

Item 13. Certain Relationships and Related Transactions and Director Independence			116

Item 14. Principal Accounting Fees and Services			116

Item 15. Exhibits, Financial Statement Schedules			116
EX-10.12
EX-23.1
EX-23.2
EX-31
EX-32


	NETHERLAND, SEWELL & ASSOCIATES, INC.
	By:	/s/ C.H. (Scott) Rees III, P.E.
		C.H. (Scott) Rees III, P.E.
		Chairman and Chief Executive Officer

	1.		I have reviewed this annual report on Form 10-K of Gasco Energy, Inc.;

	2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

	3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

	4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	(c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	(a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	(b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date: March 4, 2009	/s/ Mark A. Erickson
	Mark A. Erickson, President and
	Chief Executive Officer



Date: March 4, 2009	/s/ W. King Grant
	W. King Grant, Executive Vice President and
	Chief Financial Officer