Gasco Energy (GSXN) 10-K/A 2006 FY Annual report (amended)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

Amendment No. 1

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

For the fiscal Year Ended December 31, 2006

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

Commission file number: 0-26321

GASCO ENERGY, INC.

(Exact name of registrant as specified in its charter)

NEVADA	98-0204105
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
8 Inverness Drive East, Suite 100, Englewood, CO	80112
(Address of principal executive offices)	(Zip Code)

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

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

Title of each class	Name of each exchange on which registered
COMMON STOCK, $0.0001 PAR VALUE	AMERICAN STOCK EXCHANGE

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. Yeso Noþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ

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. Yesþ Noo

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero     Accelerated filerþ      Non-accelerated filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso Noþ

As of June 30, 2006, approximately 85,894,802 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 $341,847,947 based on a closing price of $4.34 per share, which was the closing price per share on June 30, 2006. As of February 27, 2007, 86,100,015 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 2007 annual meeting of stockholders to be filed within 120 days after December 31, 2006.

Table of Contents

Explanatory Note	1
Part I
Item 1. Business	2
Business of Gasco	2
History	2
Acquisition, Exploration and Development Expenses	3
Principal Products or Services and Markets	4
Competitive Business Conditions, Competitive Position in the Industry and Methods of Competition	4
Governmental Regulations and Environmental Laws	5
Number of Total Employees and Number of Full-Time Employees	7
Available Information	7
Cautionary Statement Regarding Forward-Looking Statements	7
Glossary of Natural Gas and Oil Terms	9
Item 1 A. Risk Factors	12
Item 1 B. Unresolved Staff Comments	25
Item 2. Properties	26
Petroleum and Natural Gas Properties	26
Company Reserve Estimates	29
Volumes, Prices and Operating Expenses	30
Development, Exploration and Acquisition Capital Expenditures	30
Productive 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	33
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Securities Transactions	34
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
Liquidity and Capital Resources	42

Capital Budget	43
Schedule of Contractual Obligations	43
Critical Accounting Policies and Estimates	44
Results of Operations	47
Recent Accounting Pronouncements	50
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	51
Item 8. Financial Statements and Supplementary Data	52
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	95
Item 9A. Controls and Procedures	95
Item 9B. Other Information	98
Part III
Item 10. Directors, Executive Officers and Corporate Governance	98
Item 11. Executive Compensation	98
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	99
Item 13. Certain Relationships and Related Transactions and Director Independence	99
Item 14. Principal Accounting Fees and Services	99
Item 15. Exhibits, Financial Statement Schedules	99
Consent of Netherland, Sewell & Associates, Inc.
Consent of Hein & Associates, Inc.
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications

EXPLANATORY NOTE

     The Company is filing this Amendment No. 1 to its Annual Report on Form 10-K (the “Amendment”) in response to a routine Securities and Exchange Commission comment letter. Changes have been made to Item 1- Business, Item 1A. — Risk Factors, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operation and to Note 2 — Significant Accounting Policies and the Report of Independent Registered Public Accounting Firm of Item 8 — Financial Statements and Supplementary Data. These are the only items that have been amended, but for convenience, the Form 10-K is being amended and restated in this Amendment. No other information is being amended by the Amendment and the Company has not updated disclosures in this Amendment to reflect any event subsequent to the Company’s filing of the original report.

1

PART I

ITEM 1 — BUSINESS

Business of Gasco

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 formations. As of December 31, 2006, we held interests in 256,429 gross acres (121,440 net acres) located in Utah, Wyoming, California and Nevada. As of December 31, 2006, we held an interest in 81 gross producing wells (50.8 wells, net to our interest) and 16 shut-in wells (15.4 net) located on these properties.

During 2006 we spudded 30 gross wells (18.5 net) and reached total depth on 29 gross wells (18.0 net) in the Riverbend Project. Initial completion operations were conducted on 26 wells (16.5 net) and 16 well bores (8.0 net) were re-entered to complete behind-pipe pay. During 2006, we also spudded two wells in Gasco’s Wyoming projects. As of December 31, 2006, Gasco operated 77 gross wells with two additional wells awaiting completion activities. All 77 gross wells are currently producing. Currently, we are operating three drilling rigs in the Riverbend Project and expect delivery of a fourth rig at the end of March 2007.

History

Gasco (formerly known as San Joaquin Resources Inc. (“SJRI”)) was incorporated on April 21, 1997 under the laws of the State of Nevada, as “LEK International, Inc.” The Company operated as a “shell” company until December 31, 1999, when the Company combined with San Joaquin Oil & Gas Ltd., a Nevada corporation (“Oil & Gas”). As a result of that transaction, Oil & Gas became a wholly owned subsidiary of Gasco.

In February 2001, a subsidiary of the Company merged with Gasco Production Company (formerly known as Pannonian Energy, Inc.) (“GPC”), a private corporation incorporated under the laws of the State of Delaware. GPC was an independent energy company engaged in the exploration, development and acquisition of crude oil and natural gas reserves in the western United States. Prior to closing of the merger GPC divested itself of all assets not associated with its “Riverbend” area of interest (the “non-Riverbend assets”). The “spin-offs” were accounted for at the recorded amounts. The net book value of the non-Riverbend assets in the United States transferred, including cash of $1,000,000 and liabilities of $555,185, was approximately $1,850,000. The non-Riverbend assets located outside of the United States were held by

2

Pannonian International Ltd. (“PIL”), the shares of which were distributed to the GPC stockholders. The net book value of PIL as of the date of distribution was approximately $174,000.

Certain shareholders of SJRI surrendered for cancellation 2,438,930 common shares of the Company’s capital stock on completion of the transaction contemplated by the GPC Agreement.

Upon completion of the transaction, GPC became a wholly owned subsidiary of the Company. However, since this transaction resulted in the existing shareholders of GPC acquiring control of the Company, for financial reporting purposes the business combination is accounted for as a reverse acquisition with GPC as the accounting acquirer.

Acquisition, Exploration and Development Expenses

During the years ended December 31, 2006 and 2005, the Company spent $87,270,883 and $50,069,968, respectively for acquisitions, development and exploration activities. During 2006, the Company 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, which is included in the total expenditures for 2006.

On September 20, 2006, Gasco entered into an agreement to purchase Brek Energy Corporation (“Brek”) for equity consideration of 11,000,000 shares of common stock of the Company valued at approximately $30,000,000 based on the closing price of Gasco’s stock on September 20, 2006. As a result of this acquisition (“Brek Acquisition”), Gasco will acquire approximately 17,095 net acres in the Uinta Basin of Utah and approximately 12,495 net acres in the Green River Basin of Wyoming. The acquisition is expected to simplify 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 does not expect to incur any additional overhead expenses as a result of the acquisition. The boards of directors of both Brek and Gasco have each approved the terms of the transaction, which is expected to close during the second quarter of 2007. The completion of the transaction is subject to the approval of the stockholders of Brek and the completion of a distribution of certain subsidiaries of Brek to its stockholders.

Under the terms of the transaction, a wholly-owned subsidiary of Gasco will merge with and into Brek. As a result of the merger, Brek will become a wholly-owned subsidiary of Gasco and each stockholder of Brek will receive a number of shares of common stock of Gasco equal to 11,000,000 divided by the total number of shares of common stock of Brek outstanding on the date of the merger, calculated on a fully diluted basis. As part of the transaction, the directors of Brek, who collectively own approximately 24% of Brek’s outstanding stock, have entered into an agreement to vote their shares in favor of the transaction. In addition, Brek’s President and CEO, who owns approximately 18% of the outstanding common stock of Brek, has agreed to deposit 550,000 shares of Gasco common stock acquired in the transaction in escrow to satisfy any claims with respect to breaches of representations and warranties of Brek.

3

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. During the years ended December 31, 2006, 2005 and 2004, over 90% of our production was sold to one customer, ConocoPhillips. However, Gasco does not believe that the loss of a single purchaser, including 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, 2006, 2005 and 2004, purchases by the following company exceeded 10% of the total oil and gas revenues of the Company.

	Percent of Production Purchased
	For the Years Ended December 31,
	2006			2005			2004
ConocoPhillips		94	%		96	%		93	%
Revenues associated with these purchases	$	19,777,000		$	13,506,000		$	2,905,000

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

The Company’s natural gas and petroleum exploration 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. Management does not believe that Gasco’s competitive position in the petroleum and natural gas industry will be significant.

Management anticipates a competitive market for hiring field and technical personnel and obtaining drilling rigs and services. The current high level of drilling activity in Gasco’s areas of exploration may have a significant adverse impact on the timing and profitability of Gasco’s operations. In addition, 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 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 ventures in which it participates, are relatively small compared to other petroleum and natural gas exploration 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.

4

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, also known as “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, also known as 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.

5

The discharge of pollutants into regulated waters is prohibited, except in accord with the terms of a permit issued by 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 (“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 response to increasing levels of concern that emissions of certain gases, including carbon dioxide resulting from combustion of hydrocarbons, may be contributing to warming of the Earth’s atmosphere, many foreign nations have agreed to limit emissions of these gases, generally referred to as “greenhouse gases,” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol”. Although the United States is not participating in the Kyoto Protocol, the Congress is considering numerous proposals for climate control legislation, including bills that could restrict greenhouse gas emissions. In addition, several states have already adopted legislation, regulations and/or regulatory initiatives to reduce emissions of greenhouse gases. Also, on November 29, 2006, the U.S. Supreme Court heard arguments on a case appealed from the U.S. Circuit Court of Appeals for the District Columbia,Massachusetts, et al. v. EPA, in which the appellate court held that the U.S. Environmental Protection Agency had discretion under the federal Clean Air Act to refuse to regulate carbon dioxide emissions from mobile sources. Passage of climate control legislation by Congress or a Supreme Court reversal of the appellate decision could result in federal regulation of carbon dioxide emissions and other greenhouse gases. Any federal or state restrictions on emissions of greenhouse gases that may be imposed in the United States could adversely affect our operations and the demand for our products.

Under the National Environmental Policy Act (“NEPA”), a federal agency, in conjunction with a permit holder, may be required to prepare an environmental assessment or a detailed environmental impact statement, also known as an “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 or “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 take approximately 18 to 24 months to complete, at an estimated cost to us of about $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. To add further assurance that we will not experience a significant curtailment, we signed a Memorandum of Understanding with the BLM during the first half of 2005 that allows us to continue drilling while the EIS is being completed. 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.

6

Number of Total Employees and Number of Full-Time Employees

As of February 27, 2007, Gasco had 21 full-time employees.

Available Information

Our Internet website ishttp://www.gascoenergy.com and you may access, free of charge, through the Investor Relations portion of our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our website is not part of this report.

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Some of the information in this annual report 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. 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. They include statements regarding our:

• financial position;

• business strategy;

• budgets;

• 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;

• 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;

7

• competition and regulation; and

• plans, objectives and expectations.

Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” and include:

• delays in obtaining drilling permits;

• uncertainties in the availability of distribution facilities for our natural gas;

• general economic conditions;

• natural gas and oil price volatility;

• the fluctuation in the demand for natural gas and oil;

• uncertainties in the projection of future rates of production and timing of development expenditures;

• operating hazards attendant to the natural gas and oil business;

• climatic conditions;

• the risks associated with exploration;

• our ability to generate sufficient cash flow to operate;

• availability of capital;

• the strength and financial resources of our competitors;

• downhole drilling and completion risks that are generally not recoverable from third parties or insurance;

• actions or inactions of third-party operators of our properties;

• environmental risks;

• regulatory developments;

• potential mechanical failure or under-performance of significant wells;

• availability and cost of services, material and equipment;

8

• our ability to find and retain skilled personnel;

• the lack of liquidity of our common stock; and

• our ability to eliminate any material weaknesses in our internal controls over financial reporting.

Any of the factors listed above and other factors contained in this annual report 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 risk factors and the other cautionary statements in this annual report. Our forward-looking statements speak only as of the date made.

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.

9

     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.

10

     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;

11

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.

     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

Due to the nature of the Company’s business and the present stage of exploration on its oil and gas prospects, the following risk factors apply to Gasco’s operations:

12

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

To date 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. Without adequate financing, we may not be able to successfully develop any prospects that we have or acquire and we may not achieve profitability from operations in the near future or at all.

During the years ended December 31, 2006, 2005 and 2004, we incurred a net loss of $55,817,767, $37,635 and $4,205,830, respectively. As of December 31, 2006, we had an accumulated deficit of $85,352,993. 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 financial condition and results of operations.

The volatility of natural gas and oil prices could have a material adverse effect on our business.

Our revenue, profitability and cash flow depend upon the prices and demand for natural gas and oil. Moreover, changes in natural gas and oil prices have a significant impact on the value of our reserves. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Prices for natural gas and oil may fluctuate widely 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;

• 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 on a per share basis, 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 2006, the previous oil and gas reserves quantities decreased by approximately 63% primarily due to the decrease in oil and gas prices from $59.87 per barrel and

13

$8.01 per mcf at December 31, 2005 to $45.53 per barrel and $4.47 per mcf at December 31, 2006. The price per barrel of oil reflects our blend of oil and condensate. If the estimated capital investment based on recent historical data to drill and complete wells in this area is not reduced materially or if the prices for oil and gas do not increase materially from year end 2006 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. 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.

In addition, because of our size we do not own or lease firm capacity on any interstate pipelines. As a result, our transportation costs are particularly subject to short-term fluctuations in the availability of transportation facilities. Our management believes that the steep discount in the prices it receives may be due to pipeline constraints out of the region, but there is no assurance that increased capacity will improve the prices to levels seen in other parts of the country in the future. Even if we acquire additional pipeline capacity, conditions may not improve due to other factors listed above.

It is impossible to predict natural gas and oil price movements with certainty. Lower natural gas and oil prices may not only decrease our revenues on a per unit basis but also may reduce the amount of natural gas and oil that we can produce economically. 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. Further, oil prices and natural gas prices do not necessarily move together.

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

Gasco’s production is transported through a single intrastate pipeline and therefore any constraints on the capacity of this pipeline could adversely affect our ability to sell our production. Additionally, many pipelines, particularly those connecting to higher — priced eastern markets, are operating at or near capacity. Management believes that this situation could continue, at least, into early 2008. In certain circumstances this may limit our ability to sell any,

14

or all, of our natural gas production in a given period. As producers vie one with another to sell their gas, this situation may also serve to reduce the price at which we are able to sell the gas that does flow. A reduction in the amount of natural gas that we can sell or the price at which such natural gas can be sold could materially adversely affect our financial position and results of operation.

Our oil and gas reserve information is estimated and may not reflect our actual reserves.

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

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

The estimated proved reserve information as of December 31, 2006, included herein is based on estimates prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers.

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 six years as of December 31, 2006, 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 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. We have revised our reserves downward by 36%, 32% and 63% in each of the previous three years.

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

It should not be assumed that the present value of future net cash flows included herein is the current market value of our estimated proved gas and oil reserves. In accordance with SEC

15

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.

Future changes in commodity prices or our estimates and operational developments may result in impairment charges.

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 is 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.

Should capitalized costs exceed this ceiling, an impairment would be 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. 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 quarter ended June 30, 2006.

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.

16

We may not be able to obtain adequate financing to continue our operations.

We have relied in the past primarily on the sale of equity capital and farm-out and other similar types of transactions to fund working capital and the acquisition of our prospects and related leases. Failure to generate operating cash flow or to obtain additional financing 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.

We will require significant additional capital to fund our future activities and to service current and any future indebtedness. 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 and our obligations under various agreements with third parties relating to exploration and development of certain prospects. 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.

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 14 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 will shift more of our drilling in Utah to our state leases, the permits for which require an average processing time of approximately two months. 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 my already have been attributed.

We may have difficulty managing 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.

We compete with larger companies in acquiring properties and operating and drilling services.

Our natural gas and petroleum exploration activities take place in a highly competitive and speculative business atmosphere. In seeking suitable natural gas and petroleum properties for acquisition, we compete with a number of other companies operating in our areas of interest, including large oil and gas companies and other independent operators with greater financial and

17

other resources. We do not believe that our competitive position in the petroleum and natural gas industry is significant.

We anticipate a competitive market for obtaining drilling rigs and services, and the manpower to operate them. The current high level of drilling activity in our areas of exploration may have a significant adverse impact on the timing and profitability of our operations. 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 may suffer losses or incur liability for events that we or the operator of a property have chosen not to insure against.

Insurance against every operational risk is not available at economic rates. We may suffer losses from uninsurable hazards or from hazards, which we or the operator have 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

18

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, as we increase our production through our drilling program or acquisitions.

We could become subject to certain Questar Pipeline Company Gas requirements which, if such requirements are too strict, could result in our production being severely curtailed or shut-in.

We currently deliver all of our gathered gas into a Questar Pipeline Company (“Questar”) main line transportation system. Questar is currently evaluating their gas quality requirements to transport gas on their system. These requirements could and most likely, would be imposed on all companies delivering gas into their main line. If Questar should require companies to meet more strict quality requirements, there is no assurance that we could meet the new requirements in the short term future. It is possible that we would need to make significant capital expenditures to retain these short term arrangements that allow a majority of our current gas production to access firm transportation or meet the new gas quality requirements and/or to transport our gas. During this process and/or adding new transportation facilities, our production could be severely curtailed or even shut -in completely.

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.

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, consequently, adversely affect our profitability. A major

19

risk inherent in drilling is the need to obtain drilling and right of way permits from local authorities. Delays in obtaining drilling and/or right of way permits, the failure to obtain a drilling and/or right of way permit for a well or a permit with unreasonable conditions or costs could have a materially adverse effect on our ability to effectively develop our properties.

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, which have 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.

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 or other events including weather 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.

Financial difficulties encountered by our partners or third-party operators could adversely affect the exploration and development of our prospects.

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, 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 could be adversely affected which could have a material adverse effect on our business, financial condition and results of operations.

20

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.

We currently have no hedging agreements in place. However, we may in the future enter into arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas. We may enter into oil and gas hedging contracts in order to increase credit availability. Hedging will expose us to risk of financial loss in some circumstances, including if:

– production is less than expected;

– the other party 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, hedging may limit the benefit we would otherwise receive from increases in the prices of oil and gas. Further, if we do not engage in hedging, we may be more adversely affected by changes in oil and gas prices than our competitors who engage in hedging.

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

Our credit facility imposes certain operational and financial restrictions on us. These restrictions, among other things, limit our ability to:

– incur additional indebtedness;

– create liens;

– sell our assets or consolidate or merge with or into other companies;

– make investments and other restricted payments, including dividends;

– and engage in transactions with affiliates.

These limitations are subject to a number of important qualifications and exceptions. In addition, our credit facility requires us to maintain certain financial ratios to satisfy certain financial

21

conditions. These restrictions 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. Our credit facility and restrictions there under are described in greater detail in “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Credit Facility.”

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 could have a material adverse effect on our business. We have not obtained “key man” insurance for any of our management. Mr. Erickson is the Chief Executive Officer, Mr. Decker is an Executive Vice President and Chief Operating Officer and Mr. Grant is an Executive Vice President and Chief Financial Officer. The loss of their services may adversely affect our business and prospects.

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. 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, C. Tony Lotito, currently serves as the Executive Vice President, Chief Financial Officer, Secretary-Treasurer 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 also serves on the Boards’ of Directors of PetroHunter and 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 E&P 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. Another one of our directors, Richard Burgess is a director of ROC Oil Company (“ROC”), a Limited Liability Corporation incorporated in Australia. ROC has oil and gas activities in China, Australia, UK North Sea, and West Africa. ROC has no activities in North or South America. The Company estimates that all of its directors except Mr. Crowell spend approximately 10% of their time on Company business and Mr. Crowell spends approximately 25% of his time on Company business. Mark Erickson, our CEO, President and director has direct private investments in certain Rocky Mountain oil and gas leases and has a majority interest in a private oil and gas company with core assets in Oklahoma and additional lease holdings in Colorado, Wyoming and Utah. Mr. Erickson spends 100% of his time on Gasco business.

To the extent that such other companies participate in ventures in which we may participate, or compete for prospects or financial resources with us, these officers and directors will have a

22

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 the best interests of Gasco. 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 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;

23

• the operating and stock price performance of other companies that investors may deem comparable; and

• 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. 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, 2006 we had 86,100,015 shares of common stock issued and outstanding. Additional options may be granted to purchase 1,895,000 shares of common stock under our stock option plan and an additional 474,200 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 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 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 101,217,792 shares (this number assumes no exercise of the options or rights described above). In addition, we expect to issue an additional 11,000,000 shares of our common stock to former holders of Brek common stock in connection with the Brek Acquisition as well as additional shares of our common stock upon exercise of certain Brek options and warrants that we intend to assume in connection with the Brek Acquisition.

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 because our outstanding 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.

24

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 could not 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 governed by 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 might result in a premium over the market price for the shares of our common stock.

ITEM 1 B. UNRESOLVED STAFF COMMENTS

None.

25

ITEM 2 — PROPERTIES

Petroleum and Natural Gas Properties

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. Gasco’s principal business strategy is to enhance stockholder value by using technologies new to a specific area to generate and develop high-potential exploitation prospects 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 the properties subject to these leases.

The Company’s corporate strategy is to grow through drilling projects. We have been focusing our drilling efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah. The increased drilling activity in the Company’s areas of operations resulting from the higher oil and gas prices during 2005 and through the first quarter of 2006 has also decreased the availability of drilling rigs and experienced personnel in this area and may continue to do so. The Company also continues to incur higher drilling and operating costs resulting from the increased fuel and steel costs and from the increased drilling activity in this area.

     Riverbend Project

The Riverbend Project comprises approximately 124,041 gross acres in the Uinta Basin of northeastern Utah, of which we hold interests in approximately 74,657 net acres as of December 31, 2006. Our engineering and geologic focus is concentrated on three tight-sand formations in the Uinta basin: the Wasatch, Mesaverde and Blackhawk formations. A typical well 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 2006 we spudded 30 gross wells (18.5 net) and reached total depth on 29 gross wells (18.0 net). Initial completion operations were conducted on 26 wells and 16 well bores were re-entered to complete behind-pipe pay. As of December 31, 2006, Gasco had 81 gross wells on production. We currently have three drilling rigs operating in the Uinta Basin Riverbend project, and are expecting delivery of our fourth rig at the end of March 2007.

During August 2006, Gasco acquired certain gathering assets and producing properties associated with the Riverbend Project in the Uinta Basin of Utah for a cash purchase price of $4,875,000, plus settlement for production from effective date. The gathering assets and properties are located entirely within Gasco’s existing Riverbend leasehold allowing the Company to further capitalize on economies of scale and operating efficiencies. The transaction closed on August 14, 2006, with an effective date of July 1, 2006.

During 2006, Gasco linked the Wilkin Ridge and West Desert gathering systems to its existing 50 MMcfd gas processing facility which began operations in June 2006. Now, up to 95% of produced volumes are processed in the plant, ensuring that production will meet pipeline specifications reducing the likelihood of any future curtailments due to gas quality. The

26

Company currently operates nearly 100 miles of gathering system along with the processing facility.

Gasco recently received approval of its Riverbend Environmental Assessment (EA). The approved EA includes 45 proposed wells within the Spring Canyon marine trend of the Blackhawk Formation. The EA should provide for accelerated permitting approvals from the Bureau of Land Management as the environmental and cultural studies of the 45 proposed well sites have already been completed.

During 2004 we entered into an agreement with a group of industry providers (together, the “Service Parties”) to accelerate the development of Gasco’s oil and gas properties by drilling up to 50 wells in Gasco’s Riverbend Project in Utah’s Uinta Basin. The development of this project typically occurred in increments of 10-well bundles. Under this agreement, we drilled 12 wells during 2004, 10 wells during 2005 and 10 wells during 2006. In February 2007, the Service Parties did not approve the fourth bundle as proposed by Gasco. As a result, Gasco and the Service Parties are currently in discussions on a fourth bundle.

We utilize the full cost method of accounting, under which capitalized oil and gas property costs less accumulated depletion, net of deferred income taxes (full cost pool) 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. Should the full cost pool exceed this ceiling, an impairment is recognized. This impairment is recorded as non-cash expense and is not permitted to be reversed in future periods in the event that oil and gas prices subsequently increase resulting in a higher ceiling. The present value of estimated future net revenues is computed by applying current prices of oil and gas 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 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 has not recorded 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 quarter ended June 30, 2006.

     Greater Green River Basin Project

As of December 31, 2006, the Company has a leasehold interest in approximately 64,683 gross acres and 29,380 net acres in the Greater Green River Basin area of Wyoming. The acreage

27

covers two prospects identified by Gasco. During 2006, Gasco entered into a farmout agreement with an industry partner that drilled to earn acreage in our Daniel Anticline Prospect in Wyoming. The agreement allows our industry partner to earn 50% of our Daniel Anticline Prospect to all depths. We will retain operations of the wells in the project. We have also established an area of mutual interest (AMI) covering this prospect. The AMI will allow both parties to jointly test the productive potential in the core area and to later implement a plan of development. Under the terms of the farmout agreement, we paid 25% of the well costs and earned 25% of the first well which was a Hilliard Shale test. The well was drilled to approximately 16,600 feet and was intended to test the natural gas potential in five formations. Although gas quantities were present, the well was determined to be uneconomic and was plugged during January 2007. The total costs for this well were approximately $8,300,000 ($2,075,000 net to Gasco).

Gasco is also currently drilling a well in the Muddy Creek Prospect in Wyoming to test natural gas potential in five formations to a revised proposed depth of 14,400 feet. Intermediate casing was set at approximately 9,600 feet, and the rig was released and drilling operations have been suspended due to winter lease stipulations. Drilling operations on this well are expected to resume in July 2007. The costs to drill and complete this well are estimated to be approximately $7,800,000 and Gasco has a 100% working interest.

During 2006, approximately $3,786,000 of unproved lease costs related primarily to expiring acreage in Wyoming were reclassified to proved property.

On September 20, 2006, Gasco entered into an agreement to purchase Brek Energy Corporation (“Brek”) for equity consideration of 11,000,000 shares of the Company common stock valued at approximately $30,000,000 based on the closing price of Gasco’s stock on September 20, 2006. As a result of this acquisition (“Brek Acquisition”), Gasco will acquire approximately 17,095 net acres in the Uinta Basin of Utah and approximately 12,495 net acres in the Green River Basin of Wyoming. The acquisition is expected to simplify 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 does not expect to incur any additional overhead expenses as a result of the acquisition. The boards of directors of both Brek and Gasco have each approved the terms of the transaction, which is expected to close during the second quarter of 2007. The completion of the transaction is subject to the approval of the stockholders of Brek and the completion of a distribution of certain subsidiaries of Brek to its stockholders.

Under the terms of the transaction, a wholly-owned subsidiary of Gasco will merge with and into Brek. As a result of the merger, Brek will become a wholly-owned subsidiary of Gasco and stockholders of Brek in the aggregate will receive a number of shares of common stock of Gasco equal to 11,000,000 divided by the total number of shares of common stock of Brek outstanding on the date of the merger, calculated on a fully diluted basis. Gasco may issue additional shares of our common stock upon exercise of certain Brek options and warrants that we intend to assume in connection with the Brek acquisition. As part of the transaction, the directors of Brek, who collectively own approximately 24% of Brek’s outstanding stock, have entered into an agreement to vote their shares in favor of the transaction. In addition, Brek’s President and CEO, who owns approximately 18% of the outstanding common stock of Brek, has agreed to deposit

28

550,000 shares of Gasco common stock acquired in the transaction in escrow to satisfy any claims with respect to breaches of representations and warranties of Brek.

     Southern California Project

The Company has a leasehold interest in approximately 10,403 gross acres (6,171 net acres) in Kern and San Luis Obispo Counties of Southern California. During 2006, the Company entered into a farm-out agreement under which an unrelated entity has committed to drill one well on our acreage in San Luis Obispo and Kern Counties, California. Under this agreement, Gasco contributed the acreage and the unrelated entity drilled one well which was temporarily abandoned in July 2006. Gasco is also continuing to pay leasehold rentals and geological expenses to preserve its acreage positions and develop its remaining California prospects.

     Nevada Project

The Company has a leasehold interest in approximately 57,302 gross (11,232 net acres) in six prospects within White Pine County Nevada. We have farmed out our acreage to an industry partner for the development of these prospects. Under the terms of the agreement, the industry partner has the right to earn up to 80% of the Company’s interest in these properties. The drilling of the first well is anticipated to begin during the second quarter of 2007.

Company Reserve Estimates

The following table summarizes the Company’s estimated proved reserve data as of December 31, 2006, as estimated by Netherland, Sewell & Associates, Inc., independent petroleum engineers. The present value of discounted future net cash flows is based on prices at December 31, 2006 of $4.47 per Mcf of gas and $45.53 per bbl of oil. All of the Company’s proved reserves are located within the state of Utah.

	Proved Reserve Quantities				Present Value of Discounted Future Net Cash Flows
					Proved		Proved
	Mcf of Gas		Bbls of Oil		Undeveloped		Developed		Total
Total		39,975,964		370,581	$	569,500	$	62,597,700	$	63,167,200

29

Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. An increase/decrease in price of $0.10 per Mcf for natural gas and $1.00 per barrel of oil from the actual December 31, 2006 prices would result in an increase/decrease in the Company’s December 31, 2006 present value of discounted future net cash flows of approximately $2,180,900.

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,
	2006		2005		2004
Natural gas production (Mcf)		3,686,638		1,648,870		505,967
Average sales price per Mcf	$	5.38	$	8.16	$	5.79
Oil production (Bbl)		21,646		10,636		5,080
Average sales price per Bbl	$	54.86	$	56.91	$	38.43
Expenses per Mcfe:
Lease operating	$	0.92	$	0.51	$	1.19
General and administrative	$	2.47	$	3.50	$	7.81
Depreciation, depletion and amortization	$	2.85	$	2.83	$	2.06
Impairment	$	13.36	$	—	$	—

Development, Exploration and Acquisition Capital Expenditures

During the years ended December 31, 2006 and 2005, we spent $87,270,883 and $50,069,968 in development and exploration activities, respectively. During 2006, the Company 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. Additionally during 2005 we purchased a drilling rig for approximately $5,000,000. As of December 31, 2006, the Company held an interest in 81 gross (50.8 net to Gasco’s interest) producing gas wells and 16 gross (15.4 net) shut-in gas wells located on these properties.

The Company believes that its drilling activity in the Riverbend area is developmental. 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:

30

	For the Years Ended December 31,
	2006		2005		2004
Property acquisition costs:
Unproved	$	1,285,289	$	410,062	$	5,021,126
Proved		2,563,862		—		723,9012
Exploration costs		8,543,803		1,064,874		216,165
Development costs		74,877,9292		48,595,0322		17,501,7162
Total	$	87,270,883	$	50,069,968	$	23,462,908

Productive Gas Wells

The following summarizes the Company’s productive and shut-in gas wells as of December 31, 2006. 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		4		3.9
Shut-in oil wells		10		10.0
Producing gas wells		77		46.9
Shut-in gas wells		6		5.4
		97		66.2

The Company operates 77 of the above producing wells and all but one of the shut-in wells.

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, 2006. 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.

31

	Undeveloped Acres				Developed Acres
	Gross		Net		Gross		Net
Utah		120,881		72,657		3,160		2,000
Wyoming		64,603		29,320		80		60
Nevada		57,302		11,232		—		—
California		10,403		6,171		—		—
Total acres		253,189		119,380		3,240		2,060

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 2007				Expiring in 2008				Expiring in 2009
	Gross		Net		Gross		Net		Gross		Net
Utah		4,199		1,378		640		120		3,713		1,527
Wyoming		1,720		1,161		939		202		1,280		960
California		360		67		440		166		3,201		2,756
Total		6,279		2,606		2,019		488		8,195		5,244

As of December 31, 2006, approximately 82% of the gross acreage that Gasco holds is located on federal lands and approximately 17% of the acreage is located on state lands. It has been Gasco’s 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. The Company has generally been able to obtain state permits within 60 days, while obtaining federal permits has taken approximately 14 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.

Drilling Activity

The following table sets forth the Company’s drilling activity during the years ended December 31, 2006, 2005 and 2004. 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.

32

	For the Year Ended December 31,
	2006				2005				2004
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive		—		—		—		—		—		—
Dry		1		.25		—		—		—		—
Total wells		1		.25		—		—		—		—
Development Wells:
Productive		26		16.5		21		14.9		11		3.0
Dry		—		—		—		—		—		—
Total wells		26		16.5		21		14.9		11		3.0

Office Space

The Company leases approximately 8,776 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 $129,300 per year. The Company is currently in negotiations to lease additional space in its current location.

ITEM 3 — LEGAL PROCEEDINGS

None.

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

None.

33

PART II

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

The Company’s common stock commenced trading on the OTC bulletin board on March 30, 2001, under the symbol “GASE.OB.” On December 6, 2004, Gasco’s common stock commenced trading as a listed security on the American Stock Exchange under the symbol “GSX.” As of February 27, 2007, the Company had 110 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 near future as Gasco’s credit facility further discussed Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operation, 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
2005
First Quarter	$	4.25	$	2.95
Second Quarter		3.88		2.85
Third Quarter		6.91		3.57
Fourth Quarter		7.95		5.60
2006
First Quarter		7.49		4.23
Second Quarter		6.18		3.55
Third Quarter		4.74		2.35
Fourth Quarter		3.44		2.10

Securities Transactions

The Company’s securities transactions during the year ended December 31, 2006 that were not registered under the Securities Act of 1933 are described as follows:

During 2006, certain holders of the Company’s Series B Convertible Preferred Stock (“Preferred Stock”) converted 763 shares of Preferred Stock into 479,599 shares of common stock in accordance with the terms of such Preferred Stock. The issuance of these shares of common stock was exempt from registration under the Securities Act of 1933 pursuant to Section 3(a)(9) thereof.

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

34

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. 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 Year Ended December 31,
	2006			2005			2004			2003			2002
Summary of Operations
Oil, gas and gathering revenue	$	22,980,231		$	15,479,566		$	3,267,214		$	1,263,443		$	164,508
General & administrative expense		9,415,787			5,987,019			4,191,978			2,819,675			5,080,287
Net loss		(55,817,767	)		(37,635	)		(4,205,830	)		(2,526,525	)		(5,649,682	)
Net loss per share		(0.65	)		(0.00	)		(0.07	)		(0.07	)		(0.16	)

	As of December 31,
	2006		2005		2004		2003		2002
Balance Sheet
Working capital (deficit)	$	11,129,942	$	86,078,958	$	52,719,245	$	1,192,246	$	(2,857,539	)
Cash and cash equivalents		12,876,879		62,661,368		25,717,081		3,081,109		2,089,062
Oil and gas properties, net		109,281,419		100,334,852		50,820,383		28,470,917		24,760,149
Total assets		165,454,418		201,199,972		117,368,168		33,059,179		27,505,501
Long-term obligations		65,981,536		65,302,674		65,108,566		2,483,084		—
Stockholders’ equity		77,171,921		127,440,160		46,213,198		27,382,083		22,014,265

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 by the Company.

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. The Company’s 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. The Company’s principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to those leases. Gasco’s preliminary budget for our 2007 capital program reflects Gasco’s commitment to build upon its historical successes and continue its efforts to

35

demonstrate the economic viability of its resource in the Uinta Basin of Utah. Economic viability of this resource play is a function of the price of natural gas and oil, well investment, well operating cost and well performance. If the estimated capital investment based on recent historical data to drill and complete wells in this area is not reduced materially, if the estimated well performance based on recent historical performance data in this area is not increased materially or if the prices for oil and gas do not increase materially from year end 2006 prices we will be unable to economically develop most of our acreage in the Uinta Basin of Utah.

Gasco’s preliminary budget for our 2007 capital program is not contingent upon any material increases in the prices of oil and gas reflected at year end 2006. In 2007, we plan to continue to prove the geological model, delineate the resource and demonstrate additional operational efficiencies. During 2007 the Company believes, based on historical experience in 2006, that it will be able to demonstrate reduced well investment through operating efficiencies gained through improved drilling and completion practices, introduction of new technologies and economies of scale. In the last half of 2006 we experienced reduced well investment due to reduced drilling days and lower service costs. We believe well performance is likely to improve as knowledge increases with additional well development and introduction of new technologies. Historically, during periods of lower prices of natural gas and oil well investment has been much lower and the Company believes that any prolonged period of prices similar to those seen at year end 2006 would result in significantly lower well investment in the future. However, the Company believes that commodity prices reflected at the year end 2006 are not representative of the long term price for natural gas and oil.

The Company’s corporate strategy is to grow through drilling projects. The Company has been focusing its drilling efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah. The higher oil and gas prices during 2005 and through the first quarter of 2006 due to factors such as inventory levels of gas in storage, extreme weather in parts of the country and increasing demand in the United States, combined with the continued instability in the Middle East resulted in increased drilling activity in the Riverbend area. The increased drilling activity in the area decreased the availability of drilling rigs and experienced personnel in this area and may continue to do so in the future. The Company also continues to incur higher drilling and operating costs resulting from the increased fuel and steel costs and from the increased drilling activity in this area.

Recent Developments

Drilling Activity

During the year ended December 31, 2006, the Company spudded 30 gross wells (approximately 18.5 net wells) and reached total depth on 29 gross wells (approximately 18.0 net wells) in the Riverbend area. We also conducted initial completion operations on 26 wells (16.5 net wells) and re-entered 16 wells (8.0 net wells) to complete pay zones that were behind pipe. As of December 31, 2006, we operated 77 gross wells with two additional wells awaiting completion activities. We currently have three drilling rigs operating in the Uinta Basin Riverbend project, and are expecting delivery of our fourth rig at the end of March 2007.

36

During 2006, Gasco entered into a farmout agreement with an industry partner that drilled to earn acreage in our Daniel Anticline Prospect in Wyoming. The agreement allows our industry partner to earn 50% of our Daniel Anticline Prospect to all depths. We will retain operations of the wells in the project. We have also established an area of mutual interest (AMI) covering this prospect. The AMI will allow both parties to jointly test the productive potential in the core area and to later implement a plan of development. Under the terms of the farmout agreement, we paid 25% of the well costs and earned 25 % of the first well which was a Hilliard Shale test. The well was drilled to approximately 16,600 feet and was intended to test the natural gas potential in five formations. Although gas quantities were present, the well was determined to be uneconomic and was plugged during January 2007.

Gasco is also currently drilling a well in the Muddy Creek Prospect in Wyoming to test natural gas potential in five formations to a revised proposed depth of 14,400 feet. Intermediate casing was set at approximately 9,600 feet, and the rig has been released and drilling operations have been suspended due to winter lease stipulations. Drilling operations on this well are expected to resume in July 2007. The costs to drill and complete this well are estimated to be approximately $7,800,000 and Gasco has a 100% working interest.

During 2004 we entered into an agreement with a group of industry providers (together, the “Service Parties”) to accelerate the development of Gasco’s oil and gas properties by drilling up to 50 wells in Gasco’s Riverbend Project in Utah’s Uinta Basin. The development of this project typically occurred in increments of 10-well bundles. Under this agreement, we drilled 12 wells during 2004, 10 wells during 2005 and 10 wells during 2006. In February 2007, the Service Parties did not approve the fourth bundle as proposed by Gasco. As a result, Gasco and the Service Parties are currently in discussions on a fourth bundle.

Property Impairment

During 2006, approximately $3,786,000 of unproved lease costs related primarily to expiring acreage in Wyoming were reclassified to proved property.

We utilize the full cost method of accounting, under which capitalized oil and gas property costs less accumulated depletion, net of deferred income taxes (full cost pool) 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. Should the full cost pool exceed this ceiling, an impairment is recognized. This impairment is recorded as non-cash expense and is not permitted to be reversed in future periods in the event that oil and gas prices subsequently increase resulting in a higher ceiling. The present value of estimated future net revenues is computed by applying current prices of oil and gas 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.

37

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 $28,400,000. 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 has not recorded 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 quarter ended June 30, 2006.

Acquisition

Gasco acquired certain gathering assets and producing properties associated with the Riverbend Project in the Uinta Basin of Utah for a cash purchase price of $4,875,000, plus settlement for production from effective date. The gathering assets and properties are located entirely within Gasco’s existing Riverbend leasehold allowing the Company to further capitalize on economies of scale and operating efficiencies. The transaction closed on August 14, 2006, with an effective date of July 1, 2006. The Company assigned a value of approximately $2,500,000 to the gathering assets, which include 21 miles of 4” to 8” mainline gathering pipelines. The acquired gathering assets should provide more timely and cost-effective tie-in of the existing Wilkin Ridge and West Desert systems to Gasco’s Riverbend gas processing facility. Gasco now controls nearly 100 miles of mainline gathering and a 50 MMcf/d gas processing facility in the Riverbend Project.

This acquisition enabled Gasco to connect its Wilkin Ridge and West Desert gathering systems to its Riverbend gas processing plant. The gathering lines acquired in this transaction may be tied into these systems at an estimated cost of $1.5 million, allowing the Company to potentially realize a savings of $1 million versus amounts previously budgeted.

Also included in the acquisition are 24 oil and gas wells producing 400 thousand cubic feet equivalent per day (Mcfe/d) gross (320 Mcfe/d net). In the transaction, Gasco acquired approximately 1.6 billion cubic feet equivalent of proved reserves. The acquisition has no effect on gross acreage leasehold positions and a negligible effect on net acreage leasehold totals.

A number of the wells are producing oil and associated gas from the shallow Green River Formation. Some of the existing well pads will lend themselves to also be used as locations for deeper Spring Canyon (Blackhawk) wells which should yield savings on building a new drilling pad and access road of $50,000 to $100,000 per location.

Other Operations

During 2006, Gasco completed the linking of the Wilkin Ridge and West Desert gathering systems to its existing 50 MMcfd gas processing facility which began operations in June 2006. Now, up to 95% of produced volumes are processed in the facility, ensuring that production will meet pipeline specifications reducing the likelihood of any future curtailments. The Company currently operates nearly 100 miles of gathering system along with the processing facility.

38

Gasco recently received approval of its Riverbend Environmental Assessment (EA). The approved EA includes 45 proposed wells within the Spring Canyon marine trend of the Blackhawk Formation. The EA should provide for accelerated permitting approvals from the Bureau of Land Management as the environmental and cultural studies of the 45 proposed well sites have already been completed.

Proposed Acquisition

On September 20, 2006, Gasco entered into an agreement to purchase Brek Energy Corporation (“Brek”) for equity consideration of 11,000,000 shares of the Company common stock valued at approximately $30,000,000 based on the closing price of Gasco’s stock on September 20, 2006. As a result of the acquisition, Gasco will acquire approximately 17,095 net acres in the Uinta Basin of Utah and approximately 12,495 net acres in the Green River Basin of Wyoming. The acquisition is expected to simplify 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 does not expect to incur any additional overhead expenses as a result of the acquisition. The boards of directors of both Brek and Gasco have each approved the terms of the transaction, which is expected to close during the second quarter of 2007. The completion of the transaction is subject to the approval of the stockholders of Brek and the completion of a distribution of certain subsidiaries of Brek to its stockholders.

Under the terms of the transaction, a wholly-owned subsidiary of Gasco will merge with and into Brek. As a result of the merger, Brek will become a wholly-owned subsidiary of Gasco and stockholders of Brek in the aggregate will receive a number of shares of common stock of Gasco equal to 11,000,000 divided by the total number of shares of common stock of Brek outstanding on the date of the merger, calculated on a fully diluted basis. Gasco may issue additional shares of our common stock upon exercise of certain Brek options and warrants that we intend to assume in connection with the Brek acquisition. As part of the transaction, the directors of Brek, who collectively own approximately 24% of Brek’s outstanding stock, have entered into an agreement to vote their shares in favor of the transaction. In addition, Brek’s President and CEO, who owns approximately 18% of the outstanding common stock of Brek, has agreed to deposit 550,000 shares of Gasco common stock acquired in the transaction in escrow to satisfy any claims with respect to breaches of representations and warranties of Brek.

Credit Facility

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., as Administrative Agent and the other lenders named therein. Borrowings made under the Credit Agreement are guaranteed by our subsidiaries and secured by a pledge of the capital stock of our subsidiaries and mortgages on substantially all of our oil and gas properties. We have not borrowed any funds under the Credit Agreement since the time of its execution.

The initial aggregate commitment of the lenders under the Credit Agreement was $250,000,000, subject to a borrowing base which has initially set at $17,000,000. The borrowing base was subsequently increased to $25,000,000 during October 2006. The Credit Agreement also

39

provides for a $10,000,000 sublimit for letters of credit which we may use for general corporate purposes. As of December 31, 2006 there were no loans outstanding, however; a $6,564,000 letter of credit is 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, 2010.

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 1.25% (for periods in which we have utilized less than 50% of the borrowing base) to 2.00% (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 or (b) the Federal Funds Effective Rate plus¹/2%, plus (2) an applicable margin that varies from 0% (for periods in which we have utilized less than 50% of the borrowing base) to 0.75% (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. In addition, we are obligated to pay a commitment fee under the Credit Agreement quarterly in arrears based on a percentage multiplied by the daily amount that the aggregate commitments exceed borrowings under the agreement. The commitment fee percentage varies from 0.30% to 0.50% based on the percentage of the borrowing base utilized.

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 Facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Agreement) for the most recent quarter multiplied by four 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, 2006, we were in compliance with each of the covenants contained in the Credit Facility.

The Company incurred $240,262 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 facility. The credit facility is available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes. 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 following table presents certain of the Company’s production information for each of the three years ended December 31, 2006 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.

40

	For the Years Ended December 31,
	2006		2005		2004
Natural gas production (Mcf)		3,686,638		1,648,870		505,967
Average sales price per Mcf	$	5.36	$	8.16	$	5.79
Year-end estimated proved gas reserves (Mcf)		39,975,964		74,455,128		39,700,156
Oil production (Bbl)		21,646		10,636		5,080
Average sales price per Bbl	$	54.86	$	56.91	$	38.43
Year-end estimated proved oil reserves (Bbl)		370,581		377,288		274,074
Production (Mcfe)		3,816,514		1,712,686		536,447
Year-end estimated proved reserves (Mcfe)		42,199,450		76,718,856		41,344,600

The Company’s oil and gas production increased by approximately 124% during 2006 as compared with 2005 primarily due to the Company’s drilling and completion of 26 gross (16.5 net) wells during 2006. During 2006, the developed oil and gas reserve quantities increased by 109% to 41.0 Bcfe from 19.6 Bcfe in 2005. During 2006, on a combined basis, the oil and gas reserve quantities decreased by approximately 45% primarily due to negative reserve revisions of previous estimates of 63% primarily related to the decrease in oil and gas prices from $59.87 per barrel and $8.01 per mcf to $45.53 per barrel and $4.47 per mcf and production of 5%. The decrease in reserve quantities is partially offset by reserve additions of 22% and reserve purchases of 1%. The Company’s oil and gas reserves are 95% natural gas of which 97% are developed.

The majority of the revisions of previous estimates 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 current estimated capital investment based on recent 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.

The Company’s oil and gas production increased by approximately 219% during 2005 as compared with 2004 primarily due to the Company’s drilling of 21 gross (14.9 net) wells during 2005. During 2005, on a combined basis, the oil and gas reserve quantities increased by approximately 86% primarily due to reserve additions of 122% which were partially offset by annual production of 4% and revisions of previous estimates of 32%. The majority of the revisions of previous estimates were a result of the following:

– Four locations previously classified as proved undeveloped were omitted from the 2005 reserve report because these locations required a higher capital investment than originally estimated due to drilling and completion problems and due to the lack of historical data related to recent completions and recompletions in this area.

41

– Six locations previously classified as proved undeveloped were omitted from the 2005 reserve report because recent drilling activity indicates that these locations may be outside of or on the edge of a previously identified zone.

– Two proved developed non-producing completions significantly underperformed previous forecasts.

Liquidity and Capital Resources

The following table summarizes the Company’s sources and uses of cash for each of the three years ended December 31, 2006, 2005 and 2004.

	For the Year Ended December 31,
	2006			2005			2004
Net cash provided by (used in) operations	$	9,362,251		$	2,135,032		$	(905,369	)
Net cash used in investing activities		(60,496,759	)		(45,851,527	)		(58,400,053	)
Net cash provided by financing activities		1,350,019			80,660,782			81,941,394
Net cash flow		(49,784,489	)		36,944,287			22,635,972

The increase in cash provided by operations from 2005 to 2006 is primarily due to a 52% increase in gross revenue during 2006. The increase is comprised of a 124% increase in oil and gas production and a 94% increase in interest income due to a higher outstanding average balance in cash and short term investments, partially offset by a 34% decrease in gas prices during 2006. The increase in cash provided by operations during 2005 compared to 2004 is primarily due to a 219% increase in oil and gas production, a 41% increase in gas prices and a 48% increase in oil prices. The production increases in 2006 and 2005 were primarily due to drilling activity.

The Company’s investing activities during the three years ended December 31, 2006 related primarily to the Company’s development and exploration activities and the purchase of a drilling rig. During 2004, we also completed acquisitions of acreage and additional working interests in producing wells for approximately $5,800,000. We had sales proceeds of $828,102 during 2005 which represented the sale of acreage to an unrelated entity. Our sales proceeds during 2004 represented a disposition of net profits interests in 8 wells in the Riverbend area for $4,463,161. We also invested $27,000,000 in short-term investments during 2004 and sold $9,000,000 and $12,000,000 of these investments during 2006 and 2005, respectively. The remaining investing activity during 2006, 2005 and 2004 consisted primarily of changes in our restricted investments.

The Company’s financing activities during 2006 are comprised mainly of proceeds from the exercise of common stock options partially offset by cash paid for offering costs and preferred dividends. The financing activities in 2005 and 2004 are primarily comprised of the net proceeds from the sale of equity and convertible notes in the Company, as further described below.

On November 23, 2005, we closed a public offering of 12,500,000 shares of common stock at a price to the public of $6.50 per share. We also granted the underwriters a 30-day option to purchase up to 1,875,000 additional shares of our common stock solely to cover over-allotments.

42

Pursuant to this option, the underwriters purchased an additional 439,400 shares of common stock on December 6, 2005. The net proceeds from this offering, after underwriting discount and offering costs, were $79,418,386.

During 2005, 583,240 options to purchase Gasco common stock were exercised for proceeds of $1,275,743.

During 2004, the Company completed the sale through a private placement of 14,333,334 shares of its common stock to a group of accredited investors at a price of $1.50 per share, receiving net proceeds of $20,070,000 and closed the private placement of $65,000,000 in aggregate principal amount of its 5.50% Convertible Senior Notes due 2011, receiving net proceeds of $61,793,000.

During 2004, 33,336 options to purchase Gasco common stock were exercised for proceeds of $33,336.

Capital Budget

The preliminary budget for our 2007 capital expenditure program is $40 million, pending final board of director approval. The program will primarily cover the drilling and completion of at least 10 net wells on our Riverbend Project and the completion of the drilling of one in Wyoming. The budget also includes expenditures for the installation of associated pipeline infrastructure, distribution facilities and geophysical operations.

This budget will be funded primarily from cash on hand, cash flow from operations and borrowings under our line of credit.

Management believes it has sufficient capital for its 2007 operational budget, but may need to raise additional capital for its capital budget in 2008. The Company may consider several options for raising additional funds such as selling securities, selling assets or farm-outs or similar type arrangements. Any financing obtained through the sale of Gasco equity will likely result in substantial dilution to the Company’s stockholders.

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, 2006.

43

	Payments due by Period
			Less than 1						More than
Contractual Obligations	Total		year		1-3 years		3-5 years		5 years
Convertible Notes
Principal	$	65,000,000	$	—	$	—	$	65,000,000	$	—
Interest		17,030,903		3,575,000		7,150,000		6,305,903		—
Drilling Rig Contracts *		38,182,875		21,613,875		15,330,000		1,239,000		—
Operating Leases		1,298,171		478,385		756,740		63,046		—
Employment Contracts		509,167		470,000		39,167		—		—
Consulting Agreements		145,200		145,200		—		—		—
Total Contractual Cash Obligations	$	122,166,316	$	26,282,460	$	23,275,907	$	72,607,949	$	—

* 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.

The above table does not include asset retirement obligations as discussed in Note 2 of the accompanying consolidated financial statements, as the Company cannot determine with accuracy the timing of such payments.

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 Reserves

Gasco 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 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.

44

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 $28,400,000. 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 has not recorded 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 quarter ended June 30, 2006. A change in the estimated value of the full cost ceiling as describe above, could have a material impact on the total of the impairment recorded by the Company.

Estimated reserve quantities and future net cash flows have the most significant impact on the Company because these reserve estimates are used in providing a measure of the Company’s overall value. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company’s proved properties.

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 the Company’s wells have been producing less than six 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 Company’s estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Company’s 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 the Company’s estimates. Any significant variance could materially affect the quantities and present value of the Company’s 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 the Company’s December 31, 2006 present value of future net cash flows of approximately $2,180,900. In addition, the

45

Company 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. The Company’s reserves may also be susceptible to drainage by operators on adjacent properties.

     Impairment of Long-lived Assets

The cost of the Company’s 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. Each quarter the Company’s management reviews all unproved property. If a determination is made that acreage will be expiring or that the Company does not plan to develop some of the acreage that is no longer considered to be prospective, the Company records an impairment of the acreage and reclassifies the costs to the full cost pool. The Company estimates the value of these acres for the purpose of recording the related impairment. The impairments that have been recorded by the Company 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 the Company. This per acre estimate is then applied to the acres that the Company does not plan to develop in order to calculate the impairment. As a result of this process the Company has recorded impairments of $3,786,000 and $5,300,000 during the years ended December 31, 2006 and 2005, respectively. These impairments related primarily to the costs of expiring acreage in Wyoming. A change in the estimated value of the acreage could have a material impact on the total of the impairment recorded by the Company.

     Stock Based Compensation

Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards “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. The Company uses the Black-Scholes option valuation model to calculate the fair value disclosures under SFAS 123(R). This model requires the Company to estimate a risk free interest rate and the volatility of the Company’s 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.

Prior to the adoption of SFAS No. 123(R), Gasco had followed Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees”, and related interpretations, through December 31, 2005 for accounting for stock option awards to employees and directors which resulted in the accounting for grants of awards to employees and directors at their intrinsic value in the consolidated financial statements. Accordingly, Gasco has recognized compensation expense in the financial statements for awards granted to consultants which must be re-measured each period under the mark-to-market accounting method. Gasco had previously adopted the provisions of FAS No. 123, “Accounting for Stock-Based Compensation”, as

46

amended by FAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure”, through disclosure only.

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. In accordance with the modified prospective method, we have not adjusted the financial statements for periods ended prior to January 1, 2006. The Company did not recognize any one time effects of the adoption and continued to use similar option valuation models and assumptions as were used prior to January 1, 2006. The total fair-value-based compensation expense associated with prior awards that was not vested on the date of the adoption of SFAS No. 123(R) was approximately $4,800,000 which was expected to be recognized over the weighted average remaining life of the options of approximately one year.

Results of Operations

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

	For the Year Ended December 31,
	2006		2005		2004
Natural gas production (Mcf)		3,686,638		1,648,870		505,967
Average sales price per Mcf	$	5.38	$	8.16	$	5.79
Oil production (Bbl)		21,646		10,636		5,080
Average sales price per Bbl	$	54.86	$	56.91	$	38.43

2006 Compared to 2005

The increase in oil and gas revenue of $6,970,865 during 2006 compared with 2005 is comprised of an increase in oil and gas production of 11,010 bbls and 2,037,768 Mcf partially offset by a decrease in the average oil price of $2.05 per bbl and a decrease in the average gas price of $2.78 per Mcf during 2006. The $6,970,865 increase in oil and gas revenue during 2006 represents an increase of $11,583,247 related to the production increase partially offset by a decrease of $4,612,382 related to the oil and gas price decline. The production increase is due to the Company’s drilling, completion and recompletion activity during 2005 and 2006 and is partially offset by normal production declines on all wells.

Gathering revenue and expense from gathering operations represents the income earned and expenses incurred from the Riverbend area pipeline that was constructed by the Company during 2004 and 2005. The gathering revenue increased by $529,800 during 2006 as compared with 2005 due to the increased production attributable to the outside working interest owners, resulting from the Company’s drilling activity in this area. Approximately $500,000 of the $1,551,516 increase in expense from gathering operations is due to the installation of additional compression to the system and approximately $594,000 of the increase is the result of the

47

Company’s decision to revise its methodology for calculating charges related to compressor fuel. The additional expense resulting from this change represents amounts that will be refunded to the outside working interest and royalty owners in the Company’s producing wells. The remaining increase is related to increase operating costs related to the increased production in the area.

Interest income increased $1,310,860 during 2006 compared with 2005 primarily due to higher interest rates and higher average cash and cash equivalent and short-term investment balances during 2006 relating primarily to the net proceeds of approximately $79,000,000 from the Company’s common stock offering during November 2005.

Lease operating expense increased $2,642,975 during 2006 compared with 2005. The increase is primarily due to the increased operational costs such as pumping, swabbing, chemicals, electricity, allocated overhead, etc. of approximately $1,200,000 due to the increase in the number of producing wells from 45 wells at December 31, 2005 to 81 wells at December 31, 2006. Also contributing to the higher lease operating expenses during 2006 is increased water hauling and disposal costs of approximately $420,000 and increased production and property taxes of $620,000. Additionally, lease operating expense during 2006 includes approximately $400,000 of costs related to workovers performed on ten of our wells in the Riverbend area in order to restore efficient operating conditions on these wells.

Depletion, depreciation and amortization expense during 2006 is comprised of depletion expense related to the Company’s oil and gas properties, depreciation expense of furniture, fixtures and equipment and accretion expense related to the asset retirement obligation. The increase of $6,042,258 is due primarily to the increase in oil and gas production and related capital costs resulting from the Company’s increased drilling and completion activity discussed above, partially offset by the $51,000,000 reduction in the full cost pool due to the impairment recorded during the second quarter of 2006, as described below.

Impairment expense during 2006 represents the impairment recorded as of June 30, 2006 because the present value of Gasco’s future net revenue discounted at 10% exceeded the Company’s full cost pool based on current oil and gas prices of $59.87 per barrel and $5.42 per mcf.

General and administrative expense increased by $3,428,768 during 2006 as compared with 2005. The increase is primarily due to an increase in stock-based compensation expense of $4,151,509 due to the adoption of SFAS 123(R) on January 1, 2006 as further discussed in Note 3 of the accompanying financial statements and increased consulting expenses of approximately $141,000 related to the maintenance and testing of our internal controls. The increased expenses were partially offset by a decrease of approximately $860,000 related to the capitalization of certain drilling and completion overhead and the allocation of internal administrative costs related to the operations of our wells during 2006.

Interest expense during 2006 and 2005 consists primarily of interest expense related to the Company’s outstanding Convertible Senior Notes which were issued on October 20, 2004.

48

2005 Compared to 2004

Oil and gas revenue increased $10,944,419 during 2005 compared with 2004 due to an increase in oil and gas production of 5,556 bbls and 1,142,903 Mcf combined with an increase in the average oil and gas prices of $18.48 per bbl and $2.37 per Mcf during 2005. The $10,944,419 increase in oil and gas revenue during 2005 is comprised of $9,650,353 related to the production increase and $1,294,066 related to the price increase. The production increase is due to the Company’s drilling, completion and recompletion activity during 2004 and 2005 and is partially offset by the production decrease resulting from the Company’s disposition of approximately 50% of its revenue interest in two wells during the first quarter of 2004 and by normal production declines on all wells.

The Company recognized gathering revenue of $1,411,259 and expenses from gathering operations of $1,166,841 during 2005 which represents the revenue earned and expenses incurred from the Riverbend area pipeline. The increase in this revenue and expense from 2004 is due to the full year of activity during 2005 as well as the increased production as described above.

Interest income increased $1,058,858 during 2005 compared 2004 primarily due to higher average cash and cash equivalent and short-term investment balances during 2005 relating primarily to proceeds from the Company’s $65,000,000 Convertible Senior Note issuance during October 2004 and the proceeds from the common stock offering during November 2005.

Lease operating expense increased $232,326 during 2005 compared with 2004 primarily due to the increased number of producing wells during 2005.

Depletion, depreciation and amortization expense during 2005 increased as compared with 2004 due primarily to the increase in production and related costs resulting from the Company’s increased drilling and completion activity discussed above.

General and administrative expense increased by $1,795,041 during 2005 as compared with 2004, primarily due to the Company’s increased operational activity. The increase in these expenses is comprised of approximately $855,000 in salary expense and consulting fees associated with our increased operational activity, $355,000 in fees associated with the Company’s audit of internal controls as required under the Sarbanes Oxley Act of 2002 and $525,000 in stock-based compensation primarily related to the Company’s restricted stock issuance and the issuance of stock options to consultants. The remaining increase in general and administrative expenses is due to the fluctuation in numerous other expenses, none of which are individually significant.

Interest expense during 2005 consists of interest expense related to the Company’s outstanding Convertible Senior Notes which were issued on October 20, 2004. Interest expense during 2004 consists of the interest on the Company’s outstanding Convertible Debentures issued in October 2003 that were converted into common stock during October 2004 and interest on the Convertible Senior Notes for approximately two months.

49

Recent Accounting Pronouncements

On June 1, 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, “Accounting Changes and Error Corrections”, which replaced Accounting Principles Board Opinion No. 20, Accounting Changes and SFAS No. 3. SFAS 154 provided guidance on the accounting for and reporting of accounting changes and error corrections. It established retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 was effective for accounting changes and corrections of errors made January 1, 2006. The adoption of SFAS No. 154 had no impact on the Company’s financial statements.

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and also resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 was issued to eliminate the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for in a similar fashion, regardless of the instrument’s form. The Company does not believe that its financial position, results of operations or cash flows will be impacted by SFAS No. 155 as the Company does not currently hold any hybrid financial instruments.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109, “Accounting for Income Taxes”. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective January 1, 2006 for the Company. The adoption of FIN 48 is expected to have an immaterial impact on the Company’s consolidated financial position, results of operations and cash flows.

In September 2006, the FASB issued SFAS 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. The Statement is to be effective for the Company’s financial statements issued in 2008; however, earlier application is encouraged. The Company is currently evaluating the timing of adoption and the impact that adoption might have on its financial position or results of operations.

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108

50

expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB 108 is effective for the Company on January 1, 2007. The Company does not believe SAB 108 will have a material impact on its financial position or results from operations.

In December 2006, the FASB issued FASB Staff Position (“FSP”) EITF 00-19-2, “Accounting for Registration Payment Arrangements.” This FSP specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement should be separately recognized and measured in accordance with FASB Statement No. 5, “Accounting for Contingencies”. This FSP is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to December 21, 2006, the guidance in the FSP is effective January 1, 2006 for the Company. The Company does not believe that this FSP will have a material impact on its financial position or results from operations.

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 is effective for the Company’s financial statements issued in 2008. The Company is currently evaluating the impact that the adoption of SFAS No. 159 might have on its financial position or results of operations.

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, 2006, 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

The Company’s primary market risk relates to changes in the pricing applicable to the sales of gas production in the Uinta Basin of northeastern Utah and the Greater Green River Basin of west central Wyoming. This risk will become more significant to the Company as more wells are drilled and begin producing in these areas. Although the Company is not using derivatives at this time to mitigate the risk of adverse changes in commodity prices, it may consider using them in the future. The Company does not have any obligations, including under its credit facility, that are subject to variable rates of interest.

51

ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	53
Consolidated Balance Sheets at December 31, 2006 and 2005	54-55
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005 and 2004	56
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004	57
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004	58
Notes to Consolidated Financial Statements	59-94

52

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the consolidated balance sheets of Gasco Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2006. These 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 provided 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 the Company as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, 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 February 27, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

As discussed in Note 3 to the accompanying consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R),Share-Based Payment.

/s/ Hein & Associates LLP
Denver, Colorado
February 27, 2007

53

GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS

	December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	12,876,879		$	62,661,368
Restricted investment		3,575,000			10,139,000
Short-term investments		6,000,000			15,000,000
Accounts receivable
Joint interest billings		5,955,186			1,792,038
Revenue		3,081,850			3,115,154
Inventory		1,297,498			1,182,982
Prepaid expenses		644,490			645,554
Total		33,430,903			94,536,096
PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved properties		159,407,481			83,972,300
Unproved properties		12,538,067			13,323,712
Wells in progress		5,215,252			—
Gathering assets		12,703,346			4,831,050
Facilities and equipment		8,492,632			5,148,388
Furniture, fixtures and other		241,009			175,607
Total		198,597,787			107,451,057
Less accumulated depletion, depreciation, amortization and impairment		(68,945,779	)		(6,986,662	)
Total		129,652,008			100,464,395
NON-CURRENT ASSETS
Restricted investment		—			3,565,020
Deferred financing costs		2,371,507			2,634,461
		2,371,507			6,199,481
TOTAL ASSETS	$	165,454,418		$	201,199,972

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

54

GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)

	December 31,
	2006			2005
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	16,228,056		$	3,095,819
Revenue payable		1,678,427			1,658,141
Advances from joint interest owners		2,955,376			2,476,080
Accrued interest		844,102			844,098
Accrued expenses		595,000			383,000
Total		22,300,961			8,457,138
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes		65,000,000			65,000,000
Asset retirement obligation		908,543			223,947
Deferred rent expense		72,993			78,727
Total		65,981,536			65,302,674
COMMITMENTS AND CONTINGENCIES (NOTES 5, 12, 13)
STOCKHOLDERS’ EQUITY
Series B Convertible Preferred stock — $.001 par value; 20,000 shares authorized; 763 shares issued and outstanding with a liquidation preference of $335,720 as of December 31, 2005		—			1
Common stock — $.0001 par value; 300,000,000 shares authorized; 86,173,715 shares issued and 86,100,015 outstanding as of December 31, 2006; 85,041,492 shares issued and 84,967,792 shares outstanding as of December 31, 2005		8,617			8,504
Additional paid-in-capital		162,646,592			157,540,755
Deferred compensation		—			(443,579	)
Accumulated deficit		(85,352,993	)		(29,535,226	)
Less cost of treasury stock of 73,700 common shares		(130,295	)		(130,295	)
Total		77,171,921			127,440,160
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	165,454,418		$	201,199,972

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

55

GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Year Ended December 31,
	2006			2005			2004
REVENUES
Gas	$	19,851,663		$	13,462,977		$	2,928,689
Oil		1,187,509			605,330			195,199
Gathering		1,941,059			1,411,259			143,326
Interest income		2,694,719			1,383,859			325,001
Total		25,674,950			16,863,425			3,592,215
OPERATING EXPENSES
Lease operating		3,513,568			870,593			638,267
Gathering operations		2,718,357			1,166,841			267,450
Depletion, depreciation and amortization		10,885,697			4,843,439			1,102,575
Impairment		51,000,000			—			—
General and administrative		9,415,787			5,987,019			4,191,978
Interest expense		3,959,308			4,033,168			1,597,775
Total		81,492,717			16,901,060			7,798,045
NET LOSS		(55,817,767	)		(37,635	)		(4,205,830	)
Preferred stock dividends		(1,393	)		(33,347	)		(140,853	)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(55,819,160	)	$	(70,982	)	$	(4,346,683	)
NET LOSS PER COMMON SHARE — BASIC AND DILUTED	$	(0.65	)	$	(0.00	)	$	(0.07	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING — BASIC AND DILUTED		85,383,306			72,152,977			63,194,223

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

56

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, 2003		11,734		$	12			45,675,936		$	4,568		$	52,979,325		$	(179,766	)	$	(25,291,761	)	$	(130,295	)	$	27,382,083
Conversion of preferred shares to common shares		(9,479	)		(10	)		5,958,226			596			(586	)											—
Issuance of common stock								14,714,787			1,472			20,786,130			(748,157	)								20,039,445
Conversion of Convertible Debentures								4,166,665			416			2,503,376												2,503,792
Exercise of common stock options								33,336			3			33,333												33,336
Stock compensation																	415,483									415,483
Proceeds from 16b violation														106,858												106,858
Dividends								41,959			4			(61,973	)											(61,969	)
Net loss		—			—			—			—			—			—			(4,205,830	)		—			(4,205,830	)
Balance December 31, 2004		2,255			2			70,590,909			7,059			76,346,463			(512,440	)		(29,497,591	)		(130,295	)		46,213,198
Issuance of common stock								12,929,516			1,293			79,449,446			(172,773	)								79,277,966
Conversion of preferred shares to common shares		(1,492	)		(1	)		937,827			94			(93	)											—
Exercise of common stock options								583,240			58			1,275,685												1,275,743
Stock compensation														502,601			241,634									744,235
Dividends														(33,347	)											(33,347	)
Net loss		—			—			—			—			—			—			(37,635	)		—			(37,635	)
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 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

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

57

GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(55,817,767	)	$	(37,635	)	$	(4,205,830	)
Adjustment to reconcile net loss to net cash provided by (used in) Operating activities
Depletion, depreciation, amortization and impairment expense		61,816,513			4,829,403			1,085,912
Accretion of asset retirement obligation		69,184			14,036			16,663
Stock compensation		4,151,509			744,235			415,483
Amortization of deferred rent expense		(5,734	)		48,727			—
Landlord incentive payment		—			30,000			—
Amortization of beneficial conversion feature		—			—			161,514
Amortization of deferred financing costs		503,216			458,167			294,993
Changes in operating assets and liabilities:
Accounts receivable		(4,129,844	)		(3,862,148	)		(545,681	)
Inventory		(114,516	)		(173,068	)		(1,009,914	)
Prepaid expenses		1,064			(186,999	)		59,992
Accounts payable		2,376,327			(3,109,102	)		1,113,109
Revenue payable		20,286			1,323,376			91,252
Advances from joint interest owners		479,296			1,584,081			891,999
Accrued interest		4			148,959			695,139
Accrued expenses		12,713			323,000			30,000
Net cash provided by (used in) operating activities		9,362,251			2,135,032			(905,369	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for acquisitions, development and exploration		(79,557,785	)		(55,181,914	)		(25,736,066	)
Cash paid for furniture, fixtures and other		(67,994	)		(106,790	)		(64,053	)
Proceeds from property sales		—			828,102			4,463,161
Investment in short-term investments		—			—			(27,000,000	)
Proceeds from the sale of short-term investments		9,000,000			12,000,000			—
Cash designated as restricted		(9,980	)		(6,816,967	)		(10,313,095	)
Cash undesignated as restricted		10,139,000			3,426,042			250,000
Net cash used in investing activities		(60,496,759	)		(45,851,527	)		(58,400,053	)
CASH FLOWS FROM FINANCING ACTIVITIES
Exercise of options to purchase common stock		1,591,674			1,275,743			33,336
Cash paid for debt issuance costs		(240,262	)		(275,378	)		(4,636,828	)
Preferred dividends		(1,393	)		(33,347	)		(61,793	)
Proceeds from sale of common stock		—			79,693,764			21,500,001
Issuance of convertible notes		—			—			65,000,000
Proceeds from 16b violation		—			—			106,858
Net cash provided by financing activities		1,350,019			80,660,782			81,941,394
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(49,784,489	)		36,944,287			22,635,972
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD		62,661,368			25,717,081			3,081,109
END OF PERIOD	$	12,876,879		$	62,661,368		$	25,717,081

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

58

GASCO ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

NOTE 1 — ORGANIZATION

Gasco Energy, Inc. (“Gasco” or the “Company”) is an independent energy company engaged in the exploration, development, and acquisition and production of crude oil and natural gas in the western United States. “Our”, “we”, and “us” as used herein also refer to Gasco Energy, Inc.

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.

Restricted Investment

The restricted investment balance as of December 31, 2006 is comprised of $3,575,000 invested in U.S. government securities in an amount sufficient to provide for the payment of two semi-annual scheduled interest payments on the Company’s outstanding 5.5% Convertible Senior Notes (“Notes”), as further described in Note 7. This investment will be held until maturity and the cost of the investment approximates its market value. The restricted investment balance at December 31, 2005 was comprised of $7,140,020 invested in U.S. government securities in an amount sufficient to provide for the payment of four semi-annual scheduled interest payments on the Company’s outstanding Notes, and $6,564,000 of cash invested in cash equivalents as collateral for a one year letter of credit. The letter of credit was obtained in connection with one of the Company’s long-term rig contracts. The collateral for this letter of credit was released during the first quarter of 2006 in connection with the Company’s credit facility further described in Note 6. The non-current portion at December 31, 2005 represented the interest payments that were due after one year.

Short-term Investments

The Company’s short-term investments consist primarily of preferred auction rate securities, which are classified as available-for-sale. Preferred auction rate securities represent preferred shares issued by closed end funds and are typically traded at auctions that are held periodically where the dividend rate for the next period is set. The Company invests in AAA/Aaa rated preferred auctions that have a dividend rate period of 28 days or less. These securities are stated

59

at fair value based on quoted market prices. The income earned on these investments is included in interest income in the accompanying consolidated financial statements.

Concentration of Credit Risk

The Company���s cash equivalents and short-term investments are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds 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, 2006, 2005 and 2004, over 90% of the Company’s production was sold to one customer, ConocoPhillips Company. However, Gasco does not believe that the loss of a single purchaser, including ConocoPhillips Company, would materially affect the Company’s business because there are numerous other purchasers in the areas in which Gasco sells its production. For the years ended December 31, 2006, 2005 and 2004, purchases by the following company exceeded 10% of the total oil and gas revenues of the Company.

	For the Year Ended December 31,
	2006	2005	2004
ConocoPhillips Company	94%	96%	93%

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, overhead directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $353,190, $260,227 and $69,238 of internal costs during the years ended December 31, 2006, 2005 and 2004, respectively. 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

60

and the proved reserves attributable to these costs. 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. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. During 2006, approximately $3,786,000 of unproved lease costs related to expiring acreage in Wyoming was reclassified to proved property and was included in the ceiling test and depletion calculations.

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.

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes (full cost pool) 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. Should the full cost pool exceed this ceiling, 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 December 31, 2006, based on oil and gas prices of $45.53 per barrel and $4.47 per mcf, the full cost pool would have exceeded the above described ceiling by $28,500,000. As a result of the increase in the ceiling amount using subsequent prices, the Company has not recorded 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 quarter ended June 30, 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 2006 were $231,500. No interest was capitalized during 2005 or 2004.

61

Wells in Progress

Wells in progress at December 31, 2006 represent the costs associated with the drilling of two wells in the Riverbend area of Utah and one well in the Greater Green River Basin in Wyoming. Since the wells had not reached total depth as of December 31, 2006, they were classified as wells in progress and were withheld from the depletion calculation and the ceiling test. The costs for these wells will be transferred into proved property when the wells reach total depth and are cased and will become subject to depletion and the ceiling test calculation in future periods.

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

During 2006, the Company constructed two evaporation pits in the Riverbend area of Utah to be used for the disposal of produced water from the wells that Gasco operates in the area. The pits 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, net revenue attributable to the outside working interest owners from the evaporation pits of $179,766 was recorded as a credit to proved properties during 2006.

During December 2005, Gasco purchased a drilling rig for approximately $5,000,000. The rig and the other oil and gas equipment owned by the Company is depreciated using the straight-line method over the estimated useful life of the equipment of five to ten years. The rental of the rig and 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 $748,690 was recorded as a credit to proved properties during 2006.

Impairment of Long-lived Assets

The Company’s unproved properties are evaluated quarterly for the possibility of potential impairment. During the year ended December 31, 2006 approximately $3,786,000 of unproved lease costs related primarily to expiring acreage in Wyoming was reclassified to proved property. Other than oil and gas properties, the Company has no other long-lived assets and to date has not recognized any impairment losses.

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, which are being amortized over the seven year life of the notes; and the debt issuance costs incurred in connection with the Company’s credit facility, which are being amortized over the four year term of the credit facility (see Note 6). The Company

62

recorded amortization expense of $503,216 and $458,167 related to these costs during the years ended December 31, 2006 and 2005, respectively.

Financial Instruments

The Company’s financial instruments including cash and cash equivalents, restricted cash, short-term investments, 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 Notes are recorded at cost, and the fair value is disclosed in Note 7. Since 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.

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. The future cash outflows for oil and gas properties associated with settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are also included in the ceiling test calculation. 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,
	2006		2005			2004
Balance beginning of period	$	223,947	$	108,566		$	142,806
Liabilities incurred		545,879		123,190			29,394
Liabilities settled		—		(21,845	)		(25,188	)
Revisions in estimated cash flows (a)		69,533		—			(55,109	)
Accretion expense		69,184		14,036			16,663
Balance end of period	$	908,543	$	223,947		$	108,566

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

63

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, 2006, 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.

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, 2006 and 2005 were not significant.

Computation of Net Loss per Share

Basic net loss per share is computed by dividing net 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, directors and employees of the Company are included in the computation only after the shares become fully vested. Diluted net income per common share includes the potential dilution that could occur upon exercise of the options to acquire common stock. The Notes, which are convertible into 16,250,000 shares of common stock and the outstanding common stock options, have not been included in the computation of diluted net loss per share during all periods because their inclusion would have been anti-dilutive.

As of December 31, 2006, we had 86,100,015 shares of common stock outstanding. As of such date, there were 9,878,502 shares of common stock issuable upon exercise of outstanding options. Additional options may be granted to purchase 1,895,000 shares of common stock under our stock option plan and an additional 474,200 shares of common stock are issuable under our restricted stock plan. As of December 31, 2006, 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.

64

Assuming all of the 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 102,350,015 shares (this number assumes no exercise of the options or rights described above).

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, and timing and costs associated with its retirement obligations.

Other Comprehensive Income

The Company’s short-term investments are classified as available-for-sale, and are carried on the balance sheet at market value. Unrealized gains and losses, net of deferred income taxes, are generally reported as other comprehensive income and as an adjustment to stockholders’ equity. If a decline in market value below cost is assessed as being other than temporary, such impairment is included in the determination of net income. The Company’s available-for-sale securities are readily marketable and available for use in its operations should the need arise. Therefore, the Company has classified such securities as current assets. As of December 31, 2006 and 2005, the market value of the Company’s short-term investments approximates its cost basis and therefore, there were no unrealized gains and losses included in other comprehensive income during 2006 or 2005.

The Company does not have any other items of other comprehensive income for the years ended December 31, 2006, 2005 and 2004. 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.

Stock Compensation

The Company adopted SFAS No. 123(R), “Accounting for Stock-Based Compensation” which

65

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.

Recent Accounting Pronouncements

On June 1, 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, “Accounting Changes and Error Corrections”, which replaced Accounting Principles Board Opinion No. 20, Accounting Changes and SFAS No. 3. SFAS 154 provided guidance on the accounting for and reporting of accounting changes and error corrections. It established retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 was effective for accounting changes and corrections of errors made January 1, 2006. The adoption of SFAS No. 154 had no impact on the Company’s financial statements.

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and also resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 was issued to eliminate the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for in a similar fashion, regardless of the instrument’s form. The Company does not believe that its financial position, results of operations or cash flows will be impacted by SFAS No. 155 as the Company does not currently hold any hybrid financial instruments.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109, “Accounting for Income Taxes”. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective January 1, 2006 for the Company. The adoption of FIN 48 is expected to have an immaterial impact on the Company’s consolidated financial position, results of operations and cash flows.

In September 2006, the FASB issued SFAS 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. The Statement is to be effective for the Company’s financial statements issued in 2008; however, earlier application is encouraged. The Company is currently evaluating the timing of adoption and the impact that adoption might have on its financial position or results of operations.

66

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB 108 is effective for the Company on January 1, 2007. The Company does not believe SAB 108 will have a material impact on its financial position or results from operations.

In December 2006, the FASB issued FASB Staff Position (“FSP”) EITF 00-19-2, “Accounting for Registration Payment Arrangements.” This FSP specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement should be separately recognized and measured in accordance with FASB Statement No. 5, “Accounting for Contingencies”. This FSP is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to December 21, 2006, the guidance in the FSP is effective January 1, 2006 for the Company. The Company does not believe that this FSP will have a material impact on its financial position or results from operations.

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 is effective for the Company’s financial statements issued in 2008. The Company is currently evaluating the impact that the adoption of SFAS No. 159 might have on its financial position or results of operations.

Reclassifications

Certain reclassifications have been made to prior years’ amounts to conform to the classifications used in the current year. Such reclassifications had no effect on the Company’s net loss in any of the periods presented.

NOTE 3 — STOCK-BASED COMPENSATION

Gasco had followed Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees”, and related interpretations, through December 31, 2005 for accounting for stock option awards to employees and directors which resulted in the accounting for grants of awards to employees and directors at their intrinsic value in the consolidated financial statements. Accordingly, Gasco has recognized compensation expense in the financial statement for awards granted to consultants which must be re-measured each period under the mark-to-market accounting method. Gasco had previously adopted the provisions of FAS No. 123, “Accounting for Stock-Based Compensation”, as amended by FAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure”, through disclosure only.

67

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. In accordance with the modified prospective method, we have not adjusted the financial statements for periods ended prior to January 1, 2006. SFAS 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 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. Previously, Gasco only recorded the impact of forfeitures as they occurred for employee options. 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 year ending December 31, 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.

We account 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.

As of December 31, 2006, options to purchase an aggregate of 9,878,502 shares of the Company’s common stock and 365,920 shares of restricted stock were outstanding. These awards were granted during the years from 2001 through 2006 to the Company’s employees, directors and consultants. The options have exercise prices ranging from $1.00 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 $4,152,268, $344,872, and $312,243 and stock-based non-employee compensation expense was $6,264, $399,364, $103,240 before tax for the years ending December 31, 2006, 2005, and 2004. Of this $6,264 of total calculated compensation expense for non-employees for the year ending December 31, 2006, $(759) will be expensed and $7,023 will be capitalized relating to drilling personnel.

The Company recognized the full impact of its equity incentive plans in the consolidated statements of operations for the year ended December 31, 2006 under SFAS No. 123(R) and did not capitalize any such costs on the consolidated balance sheets, as such costs that qualified for capitalization were not significant.

The adoption of SFAS No. 123R increased the Company’s basic and diluted net loss attributable to common stockholders per share by $(.05) year ending December 31, 2006. The Company did not recognize a tax benefit from share-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.

68

The table below summarizes the effect on net loss and net loss per share for the years ended December 31, 2005 and 2004 as if the Company has applied the fair value recognition of SFAS No. 123(R) to the employee based stock awards.

	For the Year Ended December 31,
	2005			2004
Net loss attributable to common shareholders:
As reported	$	(70,982	)	$	(4,346,683	)
Add: Stock-based employee compensation included in net loss (a)		344,873			312,243
Less: Stock based employee compensation determined under the fair value based method		(2,920,997	)		(757,294	)
Pro forma	$	(2,647,106	)	$	(4,791,734	)
Net loss per common share:
As reported	$	(0.00	)	$	(0.07	)
Pro forma	$	(0.04	)	$	(0.08	)

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 2006, 2005, and 2004 was calculated using the following assumptions:

	Employee Options
	2006	2005	2004
Expected dividend yield	—	—	—
Expected price volatility	85-88%	75-79%	79-87%
Risk-free interest rate	4.64 - 5.08%	3.7-3.9%	3.2-3.9%
Expected life of options	6 years	5 years	5 years

The weighted average grant-date fair value of options granted to employees during 2006, 2005, and 2004 was $3.76, $2.25, and $1.28, respectively.

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

Stock Options

The following table summarizes the stock option activity in the equity incentive plans during the years ended December 31, 2006, 2005 and 2004:

69

	2006		2005		2004
		Weighted		Weighted		Weighted
		Average		Average		Average
	Stock	Exercise	Stock	Exercise	Stock	Exercise
	Options	Price	Options	Price	Options	Price
Outstanding at beginning of year	8,812,667	$2.29	7,043,250	$1.85	5,666,586	$2.07
Granted	1,925,000	$4.97	2,450,000	$3.53	1,410,000	$1.98
Exercised	(604,161)	$2.63	(643,083)	$2.16	(33,336)	$1.00
Forfeited	(186,671)	$4.63	(37,500)	$3.39	0	n/a
Expired	(68,333)	$3.84	0	n/a	0	n/a
Outstanding at the end of year	9,878,502	$2.74	8,812,667	$2.29	7,043,250	$1.85
Exercisable at December 31,	7,543,463	$2.14	6,574,281	$1.97	5,624,417	$1.42

The following table summarizes information related to the outstanding and vested options as of December 31, 2006:

	Outstanding
	Options		Vested Options
Number of shares		9,878,502		7,543,463
Weighted Average Remaining Contractual Life		6.70		5.92
Weighted Average Exercise Price	$	2.74	$	2.14
Aggregate intrinsic value	$	4,666,252	$	4,666,252

The aggregate intrinsic value in the table above represents the total pretax intrinsic value, based on the Company’s closing common stock price of $2.45 as of December 31, 2006, which would have been received by the option holders had all option holders exercised their options as of that date.

The total intrinsic value of options exercised during the year ending December 31, 2006, 2005, and 2004 was $1,256,450, $2,023,726, and $26,335, respectively. The total cash received from employees as a result of employee stock option exercises during the year ending December 31, 2006 was approximately $1,591,679. In connection with these exercises, the tax benefits potentially realizable by the Company for the year ending December 31, 2006 were $439,758. The Company has accumulated net operating losses sufficient to offset its taxable income, therefore, the tax benefit associated with the exercise of these options has not been recognized.

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

As of December 31, 2006, there was $7,943,846 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 weighted-average period of 1.15 years.

70

Restricted Stock

The following table summarizes the restricted stock activity for the years ending December 31, 2006, 2005 and 2004:

	2006		2005		2004
				Weighted		Weighted
		Weighted		Average		Average
	Restricted	Average	Restricted	Fair	Restricted	Fair
	Stock	Fair Value	Stock	Value	Stock	Value
Outstanding at the beginning of the year	565,380	$1.58	695,850	$1.33	375,000	$0.59
Granted	131,250	$3.02	23,700	$6.81	395,850	$1.89
Vested	(305,710)	$0.96	(154,170)	$1.26	(75,000)	$0.59
Forfeited	(25,000)	$2.59	0	n/a	0	n/a
Outstanding at the end of the year	365,920	$2.39	565,380	$1.58	695,850	$1.33

The total fair value of the shares vested during the years ending December 31, 2006, 2005, and 2004 was $293,608, $193,881, and $44,250, respectively.

As of December 31, 2006, there was $465,398 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 3.12 years.

In connection with the adoption of SFAS No. 123(R), $443,579 of deferred compensation as of December 31, 2005 was reclassified to additional paid-in-capital.

The following table summarizes the stock options outstanding at December 31, 2006.

					Weighted
					Average
	Number of		Number of		Remaining
Range of exercise	Shares		Shares		Contractual Life
Prices per Share	Outstanding		Exercisable		(years)
$1.00 – $1.99		3,130,004		3,130,004	5.5
$2.00 – $2.99		2,001,000		1,876,000	6.0
$3.00 – $3.99		3,267,498		2,464,962	7.1
$4.00 – $4.99		50,000		8,333	9.5
$5.00 – $5.99		1,430,000		64,164	9.3
Total		9,878,502		7,543,463	6.7

71

NOTE 4 — OIL AND GAS PROPERTY

The Company believes that its drilling activity in the Riverbend area is developmental. 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,
	2006		2005		2004
Property acquisition costs:
Unproved	$	1,285,289	$	410,062	$	5,021,126
Proved		2,563,862		—		723,9012
Exploration costs		8,543,803		1,064,874		216,165
Development costs		74,877,9292		48,595,0322		17,501,7162
Total	$	87,270,883	$	50,069,968	$	23,462,908

Depletion and impairment expense related to proved properties per equivalent Mcf of production for the years ended December 31, 2006, 2005 and 2004 was $16.22, $2.83 and $2.06, respectively.

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

	2006		2005
Utah	$	5,325,051	$	3,040,717
Wyoming		6,210,382		9,779,223
California		1,002,634		313,586
Nevada		—		190,186
	$	12,538,067	$	13,323,712

During the years ended December 31, 2006 and 2005, approximately $3,786,000 and $5,300,000, respectively, of unproved lease costs related primarily to expiring acreage in Wyoming was reclassified to proved property and was included in the ceiling test and depletion calculations. During 2006, the Company farmed out its acreage in Nevada to an industry partner for the reimbursement of acreage costs paid by the Company.

The following table sets forth a summary of oil and gas property costs not being amortized as of December 31, 2006, by the year in which such costs were incurred.

	Balance		Costs Incurred During Years Ended December 31,
	12/31/06		2006		2005		2004		Prior
Acquisition costs	$	9,015,405	$	1,178,073	$	283,114	$	5,400,264	$	2,153,954
Exploration costs		3,522,662		2,205,099		791,914		219,936		305,713
Total	$	12,538,067	$	3,383,172	$	1,075,028	$	5,620,200	$	2,459,667

The Company’s drilling activities are located primarily in the Riverbend Area of Utah, and the

72

Company plans to drill approximately 35 gross wells in this area during 2007. The Company also plans to drill one well in Wyoming during 2007. The unproved costs associated with the Company’s drilling projects will be transferred to proved properties as the wells are drilled during the next five to ten years.

NOTE 5 — PROPERTY ACQUISITIONS

In August 2006, Gasco acquired certain gathering assets and producing properties associated with the Riverbend Project in the Uinta Basin of Utah for a cash purchase price of $4,875,000, plus settlement for production from the effective date. The acquisition included approximately 21 miles of 4” to 8” mainline gathering pipelines and 24 oil and gas wells. In the transaction, Gasco acquired approximately 1.6 billion cubic feet equivalent of proved reserves. The acquisition has no effect on gross acreage leasehold positions and a negligible effect on net acreage leasehold totals. The transaction closed on August 14, 2006, with an effective date of July 1, 2006.

During December 2005, Gasco purchased a rig for approximately $5,000,000. Gasco entered into a one-year drilling contract with an unrelated third party who will operate the rig. The operator may buy the rig from Gasco at the fair market value of the rig within three years of when the rig is delivered. This rig began drilling in our Riverbend Project during the third quarter of 2006. Also, during December 2005, we entered into a three-year contract for a new-build rig to be delivered in March 2007. In connection with this contract we provided the rig owner a letter of credit from our bank for $6,564,000. The cash collateral for this letter of credit is considered usage under our letter of credit for purposes of calculating availability and commitment fees.

See Note 13 — Commitments for further discussion.

NOTE 6 — CREDIT FACILITY

On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered into a $250,000,000 Credit Agreement (the “Credit Agreement”) with JPMorgan Chase Bank, N.A., as Administrative Agent and the other lenders named therein. Borrowings made under the Credit Agreement are guaranteed by our subsidiaries and secured by a pledge of the capital stock of our
subsidiaries and mortgages on substantially all of our oil and gas properties. We have not borrowed any funds under the Credit Agreement since the time of its execution.

The initial aggregate commitment of the lenders under the Credit Agreement is $250,000,000, subject to a borrowing base which was initially set at $17,000,000. The borrowing base was subsequently increased to $25,000,000 during October 2006. The Credit Agreement also provides for a $10,000,000 sublimit for letters of credit which we may use for general corporate purposes. As of December 31, 2006 there were no loans outstanding, however, a $6,564,000 letter of credit is 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, 2010.

73

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 1.25% (for periods in which we have utilized less than 50% of the borrowing base) to 2.00% (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 or (b) the Federal Funds Effective Rate plus¹/2%, plus (2) an applicable margin that varies from 0% (for periods in which we have utilized less than 50% of the borrowing base) to 0.75% (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. In addition, we are obligated to pay a commitment fee under the Credit Agreement quarterly in arrears based on a percentage multiplied by the daily amount that the aggregate commitments exceed borrowings under the agreement. The commitment fee percentage varies from 0.30% to 0.50% based on the percentage of the borrowing base utilized.

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 Facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Agreement) for the most recent quarter multiplied by four 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. The Company is currently, and as of December 31, 2006 was, in compliance with each of the covenants contained in the credit agreement.

The Company incurred $240,262 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 facility. The credit facility is available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes. 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.

NOTE 7 — 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 “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 Notes were sold only to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933.

The Notes are convertible into Company Common Stock, $.0001 par value per share (“Common Stock”), at any time prior to maturity at a conversion rate of 250 shares of Common Stock per

74

$1,000 principal amount of Notes (equivalent to a conversion price of $4.00 per share), which is subject to certain anti-dilution adjustments.

Interest on the 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.

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 Notes on not less than 20 nor more than 60 days’ prior notice mailed to the holders of the Notes, at a redemption price equal to 100% of the principal amount of 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 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 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.

Pursuant to a Collateral Pledge and Security Agreement dated October 20, 2004, between the Company and Wells Fargo Bank, National Association, as Trustee and Collateral Agent, the Company pledged U. S. government securities in an amount sufficient upon receipt of scheduled principal and interest payments with respect to such securities to provide for the payment of the first six scheduled interest payments on the Notes. The Company used $10,313,095 of the net proceeds from the offering of Notes to acquire such U. S. government securities, the remaining balance of $3,575,000 is recorded as restricted investment in the accompanying financial statements.

The 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 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 Notes may declare the 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 Notes under the Indenture to become due and payable.

The fair value of the Notes is $65,000,000 as of December 31, 2006.

75

The Notes are due in 2011 and therefore the entire balance of $65,000,000 matures in five years.

NOTE 8 — STOCKHOLDERS’ EQUITY

The Company’s capital stock as of December 31, 2006 and 2005 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, 2006, Gasco had no shares of Series B Preferred Stock (“Preferred Stock”) issued and outstanding. All of the Preferred stock was converted by the holders thereof into 479,599 shares of common stock during January 2006. The Preferred Stock was entitled to receive dividends at the rate of 7% per annum payable semi-annually in cash, additional shares of Preferred Stock or shares of common stock at the Company’s option. The conversion price of the Preferred Stock was $0.70 per common share, and the shares of the Preferred Stock were convertible into Gasco common shares at any time at the holder’s election. The Preferred Stock voted as a class on issues that affected the Preferred Stockholders’ interests and voted with shares of common stock on all other issues on an as-converted basis. Additionally, the holders of the Preferred Stock exercised their right to elect one member to Gasco’s board of directors during March 2003.

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 86,173,715 shares of Common Stock issued, 86,100,015 shares outstanding and 73,700 shares held in treasury as of December 31, 2006. 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. Additionally, while the Preferred Stock was outstanding, the holders of the Preferred Stock were entitled to vote with shares of common stock on an as-converted basis. 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.

The Company’s common stock equity transactions during 2006 and 2005 are described as follows:

During the fourth quarter of 2006, the Company’s Board of Directors approved the issuance of 131,250 shares of common stock, under the Gasco Energy, Inc. Amended and Restated 2003 Restricted Stock Plan (“Restricted Stock Plan”), to certain of the Company’s officers and employees. The restricted shares vest 20% on the first anniversary, 20% on the second anniversary and 60% on the third anniversary of the awards. 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.

76

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 three-year vesting period. The shares of restricted stock are considered issued and outstanding at the date of grant and are included in shares outstanding for the purposes of computing diluted earnings per share. The Company had 365,920 unvested shares of restricted stock outstanding as of December 31, 2006.

During 2006, the Company granted 1,925,000 options to purchase shares of common stock to its employees, directors and outside consultants at exercise prices ranging from $2.45 to $5.69 per share. 220,000 of the options vest 16 2/3% at the end of each four-month period after the issuance date and 250,000 of the options vest 25% on the anniversary date of the grant at the end of each year after the grant date. The remaining options vest 16 2/3% at the end of each four-month period commencing on the one year anniversary of the date of grant. All of the options issued expire within ten years from the grant date.

During 2006, 82,787 shares of the Company’s common stock were cancelled in satisfaction of the income tax liability of $199,286 associated with the vesting of restricted stock.

During 2006, the Company issued 604,161 shares of common stock in connection with the exercise of options to purchase shares of common stock at strike prices ranging from $1.61 per common share to $3.70 per common share for total proceeds of $1,591,674.

During January 2006, certain holders of the Company’s Preferred Stock converted the remaining 763 shares of Preferred Stock outstanding into 479,599 shares of common stock.

During 2005, the Company’s Board of Directors approved the issuance of 23,700 shares of common stock, under the Restricted Stock Plan to certain of the Company’s officers and employees. The restricted shares vest 20% on the first anniversary, 20% on the second anniversary and 60% on the third anniversary of the awards. 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.

On November 23, 2005, we closed a public offering of 12,500,000 shares of common stock at a price to the public of $6.50 per share. We also granted the underwriters a 30-day option to purchase up to 1,875,000 additional shares of our common stock solely to cover over-allotments. The underwriters exercised this option for an additional 429,400 shares of common stock and this transaction was closed on December 6, 2005. The net proceeds from this offering, after underwriting discount and offering costs were $79,449,446. These proceeds were used to fund capital expenditures for the development and exploration of Gasco’s oil and natural gas properties and the development associated infrastructure, working capital and general corporate purposes.

During 2005, the Company issued 583,240 shares of common stock in connection with the exercise of options to purchase shares of common stock at strike prices ranging from $1.00 per common share to $3.91 per common share for total proceeds of $1,275,685.

77

During 2005, certain holders of the Company’s Preferred Stock converted 1,492 shares of Preferred Stock into 937,827 shares of common stock in accordance with the terms of such Preferred Stock.

NOTE 10 — STATEMENT OF CASH FLOWS

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 $615,412.

- Stock based compensation of $7,023 capitalized as proved property.

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

- 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.

During the year ended December 31, 2005, 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 $123,190.

- Additions to oil and gas properties included in accounts payable of $2,007,522.

- Reduction in the asset retirement obligation of $21,845 representing the plugging and abandonment activity during 2005.

- Conversion of 1,492 shares of Preferred Stock into 937,827 shares of common stock.

- Write-off of fully depreciated furniture and fixtures of $89,773.

During the year ended December 31, 2004, the Company’s non-cash investing and financing activities consisted of the following transactions:

- Conversion of $2,500,000 of Convertible Debentures issued in October 2003 into 4,166,665 shares of common stock.

- Additions to oil and gas properties included in accounts payable of $2,556,624.

78

- Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $29,394.

- Reduction in the asset retirement obligation of $25,188 representing the sale of certain property interests discussed above and a reduction of $55,109 representing a revision to the Company’s asset retirement obligation.

- Conversion of 9,479 shares of Preferred Stock into 5,958,226 shares of common stock.

- Issuance of 41,959 shares of common stock in payment of the June 30, 2004 Preferred Stock dividend.

- Issuance of 395,850 shares of restricted common stock to certain of the Company’s employees.

- Write – off of fully depreciated furniture and fixtures of $71,514.

Cash paid for interest was $3,687,124, $3,575,000 and $463,769 for the years ended December 31, 2006, 2005 and 2004, respectively. There was no cash paid for income taxes in any of the years ended December 31, 2006, 2005 and 2004.

NOTE 11 – INCOME TAXES

A provision (benefit) for income taxes for the years ended December 31, 2006, 2005 and 2004 consists of the following:

	2006			2005			2004
Current taxes:
Federal	$	—		$	—		$	—
State		—			—			—
Deferred taxes:
Federal		(18,026,132	)		(189,075	)		(1,371,000	)
State		(2,655,462	)		(783	)		(157,580	)
Less: valuation allowance		20,681,594			189,858			1,528,580
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, 2006, 2005 and 2004 is summarized below:

79

	2006			2005			2004
Tax provision (benefit) at federal statutory rate	$	(19,536,218	)	$	(13,172	)	$	(1,429,982	)
State taxes, net of federal tax effects		(1,726,051	)		(509	)		(104,032	)
Change in Tax Rate from Prior Year		—			(182,551	)		—
Other Permanent items		580,675			6,374			5,434
Valuation allowance		20,681,594			189,858			1,528,580
Net income tax provision (benefit)	$	—		$	—		$	—

The components of the deferred tax assets and liabilities as of December 31, 2005 and 2004 are as follows:

	2006			2005
Deferred tax assets:
Federal and state net operating loss carryovers	$	20,236,268		$	12,232,737
Oil and gas property impairment		20,647,375			—
Deferred rent		29,241			30,727
Deferred compensation		1,420,625			589,306
Total deferred tax assets		42,333,509			12,852,770
Less: valuation allowance		(28,827,261	)		(8,134,543	)
		13,506,248			4,718,227
Deferred tax liabilities:
Oil and gas property		7,178,935			2,177,627
Other property, plant & equipment		5,211,582			2,327,118
Other		1,151,731			213,482
Total deferred tax liabilities		13,506,248			4,718,227
Net deferred tax asset	$	—		$	—

The Company has approximately $53,227,000 of net operating loss carryover for federal income tax purposes as of December 31, 2006, of which $1,821,166 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 $44,722,000 of net operating loss carryover for state income tax purposes as of December 31, 2006, 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, 2026. 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 $28,827,261 and $8,134,543 as of December 31, 2006 and 2005 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 increase in the valuation allowance for 2006 and 2005 is $20,681,594 and $189,858, respectively.

80

NOTE 12 – RELATED PARTY TRANSACTIONS

On October 11, 2004, the Board of Directors of Gasco, other than Mr. Erickson and Mr. Bruner, approved a transaction pursuant to which Marc Bruner, the chairman of Gasco’s Board of Directors, and Mark Erickson, a director and President and Chief Executive Officer of Gasco, agreed to transfer to Gasco their rights to receive certain overriding royalty interests in its properties in exchange for the grant to each of them of options to purchase 100,000 shares of Gasco common stock at the market price on the date of grant. Messrs. Bruner and Erickson subsequently agreed to transfer, and transferred such rights to Gasco for no options or other consideration.

For each individual, these interests range between .06% and 0.6% of Gasco’s working interest in certain of its Utah and Wyoming properties. Gasco will also agree to convey equivalent royalty interests to Mr. Bruner and Mr. Erickson, or either of them, in the event that it sells any of the property subject to the royalty interests, upon certain change of control events or upon the involuntary termination of either individual. Mr. Bruner and Mr. Erickson acquired these rights under a Trust Termination and Distribution Agreement, dated December 31, 2002, with respect to the Pannonian Employee Royalty Trust (“Royalty Trust”). The Royalty Trust had been established by Pannonian Energy, Inc. (“Pannonian”) prior to Pannonian becoming a wholly owned subsidiary of Gasco, to provide additional compensation to the employees and founding directors of Pannonian, which included Mr. Bruner and Mr. Erickson, in the form of oil and gas interests. The terms of the Trust Termination and Distribution Agreement (“Termination Agreement”) required Gasco to assign to the participants of the Royalty Trust overriding royalty interests that arise out of the production of oil and gas from certain properties as a result of future drilling. The transaction was reviewed and approved by Gasco’s Audit Committee and was signed by Mr. Erickson and Mr. Bruner on December 23, 2004.

During May 2004, the Company’s Board of Directors authorized the payment of approximately $65,000 to the chairman of the Gasco Board of Directors as reimbursement of legal fees paid by the chairman for legal services provided to the Company.

During the each of years ended December 31, 2006, 2005 and 2004, 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, 2007.

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 13 — COMMITMENTS

The Company leases approximately 8,776 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

81

the lease is approximately $129,300 per year. The Company is currently in negotiations to lease additional space in its current location.

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

Year Ending December 31,	Annual Rentals
2007	$	133,927
2008		141,120
2009		148,313
2010		63,046
2011		—
Thereafter		—
	$	486,406

Rent expense for the years ending December 31, 2006, 2005 and 2004 was $126,352, $121,648 and $52,822, 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, 2008. 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.

During 2005, the Company converted the agreements for two of the three rigs drilling for us from well-to-well contracts to two-year term contracts. The drilling rate in each of the contracts is approximately $18,500 per day for one rig and $22,000 for the other rig and both contracts expire in December 2007. During December 2005, Gasco purchased a rig for approximately $5,000,000. Gasco entered into a one-year drilling contract that has a drilling rate of approximately $18,500 per day with an unrelated third party who will operate the rig. The operator may buy the rig from Gasco at the fair market value of the rig within three years of when the rig is delivered. This rig began drilling in our Riverbend Project in the third quarter of 2006. Also, during December 2005, Gasco entered into a three-year contract with a drilling rate of $21,000 per day for a new-build rig to be delivered at the end of March 2007. The three year drilling contract for the new-build rig contains a provision for the Company to terminate the contract for $12,000 per day for the number days remaining in the original contract. In connection with this contract Gasco provided the rig owner a letter of credit for $6,564,000. The collateral for this letter of credit is considered usage under our line of credit for purposes of calculating availability and commitment fees.

82

The future contractual obligations under the rig contracts are summarized below:

	Annual Drilling
Year Ending December 31,	Obligations
2007	$	21,613,875
2008		7,665,000
2009		7,665,000
2010		1,239,000
Total	$	38,182,875

Gasco has entered into a contract with a gas purchaser to sell its production at current prices. The contract requires Gasco to deliver a minimum amount of production each month, however, the Company has elected the normal purchase and sale exemption under paragraph 10(b) of SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” because the Company anticipates that (1) it will produce the volumes required to be delivered under the terms of the contacts, (2) it is probable the delivery will be made to the counterparties and (3) the counterparties will fulfill their contractual obligations under the terms of the contracts. As such, the Company is 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.

On September 20, 2006, Gasco entered into an agreement to purchase Brek Energy Corporation (“Brek”) for equity consideration of 11,000,000 shares of the Company common stock valued at approximately $30,000,000 based on the closing price of Gasco’s stock on September 20, 2006. As a result of the acquisition, Gasco will acquire approximately 17,095 net acres in the Uinta Basin of Utah and approximately 12,495 net acres in the Green River Basin of Wyoming. The acquisition is expected to simplify 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 does not expect to incur any additional overhead expenses as a result of the acquisition. The boards of directors of both Brek and Gasco have each approved the terms of the transaction, which is expected to close during the second quarter of 2007. The completion of the transaction is subject to the approval of the stockholders of Brek and the completion of a distribution of certain subsidiaries of Brek to its stockholders.

Under the terms of the transaction, a wholly-owned subsidiary of Gasco will merge with and into Brek. As a result of the merger, Brek will become a wholly-owned subsidiary of Gasco and each stockholder of Brek will receive a number of shares of common stock of Gasco equal to 11,000,000 divided by the total number of shares of common stock of Brek outstanding on the date of the merger, calculated on a fully diluted basis. Gasco may issue additional shares of our common stock upon exercise of certain Brek options and warrants that we intend to assume in connection with the Brek acquisition. As part of the transaction, the directors of Brek, who collectively own approximately 24% of Brek’s outstanding stock, have entered into an agreement to vote their shares in favor of the transaction. In addition, Brek’s President and CEO, who owns approximately 18% of the outstanding common stock of Brek, has agreed to deposit 550,000 shares of Gasco common stock acquired in the transaction in escrow to satisfy any claims with respect to breaches of representations and warranties of Brek.

83

NOTE 14 — 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 $76,685, $58,110 and $36,225 during the years ended December 31, 2006, 2005 and 2004, respectively.

NOTE 15 – SELECTED QUARTERLY INFORMATION (Unaudited)

The following represents selected quarterly financial information for the years ended December 31, 2005 and 2006.

	For the Quarter Ended
2005	March 31,			June 30,			September 30,		December 31,
Gross revenue	$	1,285,347		$	2,548,900		$	4,696,727	$	8,458,948
Net revenue from oil and gas operations		544,115			1,796,945			3,927,771		7,173,301
Net income (loss)		(1,700,128	)		(998,867	)		649,303		2,012,057
Net income (loss) per share basic and diluted		(0.02	)		(0.01	)		0.01		0.02

The increase in gross revenue, net revenue from oil and gas operations and net income is due to the Company’s drilling activity during the year as described above and the increase in average oil and gas prices during 2005. The Company’s number of gross producing wells increased from 21 gross producing wells at December 31, 2004 to 42 gross producing wells at December 31, 2005. Additionally, the average oil and gas prices increased from $5.79 per mcf and $38.43 per bbl during 2004 to $8.16 per mcf and $56.91 per bbl during 2005.

	For the Quarter Ended
2006	March 31,			June 30,			September 30,			December 31,
Gross revenue	$	7,259,522		$	5,784,328		$	6,058,733		$	6,572,367
Net revenue from oil and gas operations		5,495,008			3,740,996			3,597,027			3,915,275
Net loss		(177,157	)		(53,036,083	)a		(786,759	)		(1,817,768	)
Net loss per share basic and diluted		(0.00	)		(0.62	)		(0.01	)		(0.02	)

a – The increase in the Company’s net loss during the second quarter as compared with the other quarters is primarily due to the $51,000,000 impairment recorded at June 30, 2006 as further discussed in Note 2.

84

NOTE 16 — CONSOLIDATING FINANCIAL STATEMENTS

On September 23, 2005, Gasco filed a Form S-3 shelf registration statement with the Securities Exchange Commission which was subsequently amended in a Form S-3/A that was filed on October 27, 2005. Under this registration statement, which was declared effective on November 1, 2005, we may from time to time offer and sell 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, the parent, and the Guarantor Subsidiaries.

85

Condensed Consolidating Balance Sheet
As of December 31, 2006
(Unaudited)

				Guarantor
	Parent			Subsidiaries			Eliminations		Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10,831,082		$	2,045,797		$	—	$	12,876,879
Restricted investment		3,575,000			—			—		3,575,000
Short-term investments		6,000,000			—			—		6,000,000
Accounts receivable		—			9,037,036			—		9,037,036
Inventory		—			1,297,498			—		1,297,498
Prepaid expenses		618,505			25,985			—		644,490
Total		21,024,587			12,406,316			—		33,430,903
PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved mineral interests		7,024			159,400,457			—		159,407,481
Unproved mineral interests		506,049			12,032,018			—		12,538,067
Wells in progress		—			5,215,252			—		5,215,252
Gathering assets		—			12,703,346			—		12,703,346
Facilities and equipment		—			8,492,632			—		8,492,632
Furniture, fixtures and other		241,009			—			—		241,009
Total		754,082			197,843,705			—		198,597,787
Less accumulated depreciation, depletion and amortization		(101,985	)		(68,843,794	)		—		(68,945,779	)
Total		652,097			128,999,911			—		129,652,008
OTHER ASSETS
Deferred financing costs		2,371,507			—			—		2,371,507
Intercompany		154,960,689			(154,960,689	)		—		—
Total		157,332,196			(154,960,689	)		—		2,371,507
TOTAL ASSETS	$	179,008,880		$	(13,554,462	)		—	$	165,454,418
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	218,366		$	16,009,690		$	—	$	16,228,056
Revenue payable		—			1,678,427			—		1,678,427
Advances from joint interest owners		—			2,955,376			—		2,955,376
Accrued interest		844,102			—			—		844,102
Accrued expenses		595,000			—			—		595,000
Total		1,657,468			20,643,493			—		22,300,961
NONCURRENT LIABILITES
5.5% Convertible Senior Notes		65,000,000			—			—		65,000,000
Asset retirement obligation		—			908,543			—		908,543
Deferred rent expense		72,993			—			—		72,993
Total		65,072,993			908,543			—		65,981,536
STOCKHOLDERS’ EQUITY
Common stock		8,617			—			—		8,617
Other		112,269,802			(35,106,498	)		—		77,163,304
Total		112,278,419			(35,106,498	)		—		77,171,921
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	179,008,880		$	(13,554,462	)	$	—	$	165,454,418

86

Condensed Consolidating Balance Sheet
As of December 31, 2005
(Unaudited)

				Guarantor
	Parent			Subsidiaries			Eliminations		Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	59,314,343		$	3,347,025			—	$	62,661,368
Restricted investment		10,139,000			—			—		10,139,000
Short-term investments		15,000,000			—			—		15,000,000
Accounts receivable		—			4,907,192			—		4,907,192
Inventory		—			1,182,982			—		1,182,982
Prepaid expenses		645,229			325			—		645,554
Total		85,098,572			9,437,524			—		94,536,096
PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved mineral interests		—			83,972,300			—		83,972,300
Unproved mineral interests		274,540			13,049,172			—		13,323,712
Gathering assets		—			4,831,050			—		4,831,050
Equipment		—			5,148,388			—		5,148,388
Furniture, fixtures and other		175,607			—			—		175,607
Total		450,147			107,000,910			—		107,451,057
Less accumulated depreciation, depletion and amortization		(46,064	)		(6,940,598	)		—		(6,986,662	)
Total		404,083			100,060,312			—		100,464,395
OTHER ASSETS
Restricted investment		3,565,020			—			—		3,565,020
Deferred financing costs		2,634,461			—			—		2,634,461
Intercompany		103,081,444			(103,081,444	)		—		—
Total		109,280,925			(103,081,444	)		—		6,199,481
TOTAL ASSETS	$	194,783,580		$	6,416,392		$	—	$	201,199,972
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	785,373		$	2,310,446		$	—	$	3,095,819
Revenue payable		—			1,658,141			—		1,658,141
Advances from joint interest owners		—			2,476,080			—		2,476,080
Accrued interest		844,098			—			—		844,098
Accrued expenses		383,000			—			—		383,000
Total		2,012,471			6,444,667			—		8,457,138
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes		65,000,000			—			—		65,000,000
Asset retirement obligation		—			223,947			—		223,947
Deferred rent expense		78,727			—					78,727
Total		65,078,727			223,947			—		65,302,674
STOCKHOLDERS’ EQUITY
Series B Convertible Preferred stock		1			—			—		1
Common stock		8,504			—			—		8,504
Other		127,683,877			(252,222	)		—		127,431,655
Total		127,692,382			(252,222	)		—		127,440,160
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	194,783,580		$	6,416,392		$	—	$	201,199,972

87

Consolidating Statements of Operations

				Guarantor
For the Year Ended December 31, 2006	Parent			Subsidiaries			Eliminations			Consolidated
REVENUES
Oil and gas	$	—		$	21,039,172		$	—		$	21,039,172
Gathering		—			4,344,616			(2,403,557	)		1,941,059
Interest income		2,693,955			764			—			2,694,719
Total		2,693,955			25,384,552			(2,403,557	)		25,674,950
OPERATING EXPENSES
Lease operating		—			5,917,125			(2,403,557	)		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
Interest expense		3,959,308			—			—			3,959,308
Total		13,433,608			70,462,666			(2,403,557	)		81,492,717
NET LOSS		(10,739,653	)		(45,078,114	)		—			(55,817,767	)
Preferred stock dividends		(1,393	)		—			—			(1,393	)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(10,741,046	)	$	(45,078,114	)	$	—		$	(55,819,160	)

				Guarantor
For the Year Ended December 31, 2005	Parent			Subsidiaries		Eliminations			Consolidated
REVENUES
Oil and gas	$	—		$	14,068,307	$	—		$	14,068,307
Gathering		—			2,258,206		(846,947	)		1,411,259
Interest income		1,383,740			119		—			1,383,859
Total		1,383,740			16,326,632		(846,947	)		16,863,425
OPERATING EXPENSES
Lease operating		—			1,717,540		(846,947	)		870,593
Gathering operations		—			1,166,841					1,166,841
Depletion, depreciation and amortization		45,648			4,797,791					4,843,439
General and administrative		5,987,019			—		—			5,987,019
Interest expense		4,033,168			—		—			4,033,168
Total		10,065,835			7,682,172		(846,947			16,901,060
NET INCOME (LOSS)		(8,682,095	)		8,644,460		—			(37,635	)
Preferred stock dividends		(33,347	)		—		—			(33,347	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(8,715,442	)	$	8,644,460	$	—		$	(70,982	)

88

Consolidating Statements of Operations

				Guarantor
For the Year Ended December 31, 2004	Parent			Subsidiaries			Eliminations		Consolidated
REVENUES
Oil and gas	$	—		$	3,123,888		$	—	$	3,123,888
Interest income		—			143,326			—		143,326
Total		324,897			104			—		325,001
		324,897			3,267,318					3,592,215
OPERATING EXPENSES								—
Lease operating		—			638,267			—		638,267
Gathering operations		—			267,450			—		267,450
Depletion, depreciation and amortization		12,132			1,090,443			—		1,102,575
General and administrative		2,714,031			1,477,947			—		4,191,978
Interest expense		1,597,775			—			—		1,597,775
Total		4,323,938			3,474,107			—		7,798,045
NET LOSS		(3,999,041	)		(206,789	)		—		(4,205,830	)
Preferred stock dividends		(140,853	)		—			—		(140,853	)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(4,139,894	)	$	(206,789	)	$	—	$	(4,346,683	)

89

Consolidating Statements of Cash Flows

				Guarantor
For the Year Ended December 31, 2006	Parent			Subsidiaries			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(7,015,061	)	$	16,377,312		$	—	$	9,362,251
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
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			(79,557,785	)		—		(60,496,759	)
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 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

				Guarantor
For the Year Ended December 31, 2005	Parent			Subsidiaries			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(7,222,953	)	$	9,357,985		$	—	$	2,135,032
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(106,790	)		—			—		(106,790	)
Cash paid for acquisitions, development and exploration		—			(55,181,914	)		—		(55,181,914	)
Proceeds from property sales		—			828,102			—		828,102
Proceeds from sale of short-term investments		12,000,000			—			—		12,000,000
Cash designated as restricted		(6,816,967	)		—			—		(6,816,967	)
Cash undesignated as restricted		3,426,042			—			—		3,426,042
Net cash provided by (used) in investing activities		8,502,285			(54,353,812	)		—		(45,851,527	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the sale of common stock		79,693,764								79,693,764
Preferred dividends		(33,347	)		—			—		(33,347	)
Cash paid for offering costs		(275,378	)		—			—		(275,378	)
Exercise of options to purchase common stock		1,275,743			—			—		1,275,743
Intercompany		(45,982,844	)		45,982,844			—		—
Net cash provided by financing activities		34,677,938			45,982,844			—		80,660,782
NET INCREASE IN CASH AND CASH EQUIVALENTS		35,957,270			987,017					36,944,287
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD		23,357,073			2,360,008			—		25,717,081
END OF PERIOD	$	59,314,343		$	3,347,025		$	—	$	62,661,368

90

Consolidating Statements of Cash Flows

				Guarantor
For the Year Ended December 31, 2004	Parent			Subsidiaries			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(456,645	)	$	(448,724	)	$	—	$	(905,369	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(64,053	)		—			—		(64,053	)
Cash paid for acquisitions, development and exploration		—			(25,736,066	)		—		(25,736,066	)
Proceeds from property sales		—			4,463,161			—		4,463,161
Investment in short-term investments		(27,000,000	)		—			—		(27,000,000	)
Cash designated as restricted		(10,313,095	)		—			—		(10,313,095	)
Cash undesignated as restricted		250,000			—			—		250,000
Net cash used in investing activities		(37,127,148	)		(21,272,905	)		—		(58,400,053	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of convertible notes		65,000,000			—			—		65,000,000
Preferred dividends		(61,973	)		—					(61,973	)
Exercise of options to purchase common stock		33,336			—					33,336
Proceeds from sale of common stock		21,500,001			—					21,500,001
Cash paid for offering costs		(4,636,828	)		—			—		(4,636,828	)
Proceeds from 16b violation		106,858			—			—		106,858
Intercompany		(23,700,657	)		23,700,657			—		—
Net cash provided by financing activities		58,240,737			23,700,657			—		81,941,394
NET INCREASE IN CASH AND CASH EQUIVALENTS		20,656,944			1,979,028			—		22,635,972
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD		2,700,129			380,980			—		3,081,109
END OF PERIOD	$	23,357,073		$	2,360,008		$	—	$	25,717,081

91

NOTE 17—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, 2006, 2005 and 2004 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 oil and gas prices used as of December 31, 2006, 2005 and 2004 were $45.53 per bbl of oil and $4.47 per Mcf, $59.87 per bbl of oil and $8.01 per Mcf of gas and $42.25 per bbl of oil and $5.56 per Mcf of gas, respectively. Future production costs are based on year-end costs and include severance taxes. Each property that is operated by the Company is also charged with field-level overhead in the reserve calculation. The present value of future cash inflows is based on a 10% discount rate.

92

Reserve Quantities

	Gas			Oil
	Mcf			Bbls
Proved Reserves:
Balance, December 31, 2003		13,601,003			100,987
Extensions and discoveries		26,788,308			168,451
Revisions of previous estimates (a)		(4,940,340	)		(28,898	)
Sales of reserves in place		(2,879,772	)		(23,712	)
Purchases of reserves in place		7,636,924			62,326
Production		(505,967	)		(5,080	)
Balance, December 31, 2004		39,700,156			274,074
Extensions and discoveries		49,217,928			222,943
Revisions of previous estimates (b)		(12,814,086	)		(109,093	)
Sales of reserves in place		—			—
Purchases of reserves in place		—			—
Production		(1,648,870	)		(10,636	)
Balance, December 31, 2005		74,455,128			377,288
Extensions and discoveries		16,006,692			97,529
Revisions of previous estimates (c)		(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
Proved Developed Reserves
Balance, December 31, 2006		38,817,964			370,581
Balance, December 31, 2005		18,974,697			111,655
Balance, December 31, 2004		8,163,127			69,752

(a)	The revisions of previous estimates during 2004 relate to the write down of the reserves related to two wells and their offset locations resulting from scale deposits in the wellbores.
(b)	The majority of the revisions of previous estimates during 2005 are comprised of the following:

• Four proved undeveloped locations were omitted from the 2005 reserve report because these locations required a higher capital investment than originally estimated due to drilling and completion problems and due to the lack of historical data related to recent completions and recompletions in this area.

• Six proved undeveloped locations were omitted from the 2005 reserve report because recent drilling activity indicates that these locations may be outside of or on the edge of a previously identified zone.

• Two proved developed non-producing completions significantly underperformed previous forecasts.

(c) The majority of the revisions of previous estimates were a result of the following:

93

- 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 current estimated capital investment based on recent 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.

Standardized Measure of Discounted Future Net Cash Flows

	December 31,
	2006			2005			2004
Future cash flows	$	195,545,000		$	618,843,800		$	231,958,400
Future production and development costs		(69,135,000	)		(300,991,100	)		(123,579,100	)
Future income taxes		—			(23,006,800	)		—
Future net cash flows before discount		126,410,000			294,845,900			108,379,300
10% discount to present value		(63,242,800	)		(190,224,900	)		(76,077,700	)
Standardized measure of discounted future net cash flows	$	63,167,200		$	104,621,000		$	32,301,600

Changes in the Standardized Measure of Discounted Future Net Cash Flows

	For the Years Ended December 31,
	2006			2005			2004
Standardized measure of discounted future net cash flows at the beginning of year	$	104,621,000		$	32,301,600		$	16,195,100
Sales of oil and gas produced, net of production Costs		(17,525,604	)		(13,197,714	)		(2,485,621	)
Net changes in prices and production costs		(110,791,730	)		28,283,823			(4,045,575	)
Extensions and discoveries, net of future production and development costs		26,686,765			107,380,301			34,439,255
Previously estimated development costs incurred		9,571,134			(1,681,163	)		17,499,346
Changes in estimated future development costs		127,888,117			(34,138,277	)		(62,687,146	)
Revisions of previous quantity estimates		(77,662,093	)		(28,607,463	)		(1,055,871	)
Purchases of reserves in place		1,592,041			—			1,654,068
Sales of reserves in place		—			—			(623,985	)
Net change in income taxes		3,225,000			(3,225,000	)		—
Accretion of discount		13,773,265			3,214,885			1,619,510
Other		(18,210,695	)		14,290,008			31,792,519
Standardized measure of discounted future net cash flows at the end of year	$	63,167,200		$	104,621,000		$	32,301,600

94

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, 2006. 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, 2006, 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.

95

Changes in internal control over financial reporting during the fourth quarter of 2006.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, 2006, that have materially affected or are reasonably likely to materially affect our internal controls 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 my deteriorate.

     Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. 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 believes that the Company maintained effective internal control over financial reporting as of December 31, 2006.

     The Company’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 has been audited by Hein & Associates LLP, an independent registered public accounting firm, as stated in their report which appears elsewhere in this report.

96

     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 February 27, 2007.

Mark A. Erickson
President & Chief Executive Officer

W. King Grant
Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors
Gasco Energy, Inc.
Englewood, Colorado

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting that Gasco Energy, Inc. (“Gasco”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Gasco’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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of

97

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, management’s assessment that Gasco Energy, Inc. maintained effective internal control over financial reporting as of December 31, 2006 is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by COSO. Also in our opinion, Gasco maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Gasco Energy, Inc. and our report dated February 27, 2007 expressed an unqualified opinion.

/s/ Hein & Associates LLP
Denver, Colorado
February 27, 2007

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 2007 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

ITEM 11 — EXECUTIVE COMPENSATION

The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2007 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

98

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

The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2007 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

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

The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2007 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

ITEM 14 — PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2007 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

ITEM 15 — EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)	1. See “Index to Financial Statements” under Item 8 on page 101.
	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 9, 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).

99

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).
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).
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	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).

100

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 30, 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 30, 2006, File No. 001-32369).
4.13	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).
# 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).

101

# 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).
10.9	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).
10.10	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).
10.11	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).
10.12	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).
10.13	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).
10.14	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).
10.15	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).
10.16	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).

102

10.17	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).
10.18	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).
10.19	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).
#10.20	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).
*23.1	Consent of Netherland, Sewell & Associates, Inc.
*23.2	Consent of Hein & Associates LLP
*31	Rule 13a-14(a)/15d-14(a) Certifications
*32	Section 1350 Certifications

*	Filed herewith.
#	Identifies management contracts and compensatory plans or arrangements.

103

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: April 4, 2007
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. EricksonMark A. Erickson	Director and President and Chief Executive Officer	April 4, 2007
/s/ Marc A. Bruner	Director	April 4, 2007
Marc A. Bruner
/s/ Carl Stadelhofer Carl Stadelhofer	Director	April 4, 2007
/s/ W. King GrantW. King Grant	Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	April 4, 2007
/s/ Carmen Lotito Carmen (“Tony”) Lotito	Director	April 4, 2007
/s/ Charles B. CrowellCharles B. Crowell	Director	April 4, 2007
/s/ Richard S. LangdonRichard S. Langdon	Director	April 4, 2007
/s/ R. J. BurgessR.J. Burgess	Director	April 4, 2007
/s/ John A. SchmitJohn A. Schmit	Director	April 4, 2007

104

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 9, 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).
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	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).

105

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 30, 2006, File No. 001-32369).

106

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 30, 2006, File No. 001-32369).
4.13	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).
# 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).
# 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).
10.9	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).
10.10	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).
10.11	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).
10.12	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).

107

10.13	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).
10.14	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).
10.15	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).
10.16	Amendment No. 1 to Property Purchase Agreement dated as of August 9, 2002 between the Company and Shama Zoe Limited Partnership. (Filed as Exhibit 10.21 to the Company’s Form S-1 dated November 15, 2002, filed on November 15, 2002, File No. 333-98759)).
10.17	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).
10.18	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).
10.19	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).
#10.20	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).
*23.1	Consent of Netherland, Sewell & Associates, Inc.
*23.2	Consent of Hein & Associates LLP
*31	Rule 13a-14(a)/15d-14(a) Certifications
*32	Section 1350 Certifications

*	Filed herewith.
#	Identifies management contracts and compensatory plans or arrangements.

108