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  **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 SECURITIESEXCHANGE ACT OF 1934****For the fiscal Year Ended December 31, 2006**   o **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE 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. Employerincorporation 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 ofthe Securities Act. Yes o No þIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 orSection 15(d) of the Act. Yes o No þIndicate by check mark whether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or forsuch shorter period that the registrant was required to file such reports), and (2) has beensubject to such filing requirements for the past 90 days. Yes þ No oIndicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K isnot contained herein and will not be contained, to the best of the registrant’s knowledge, indefinitive proxy or information statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K. oIndicate 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” inRule 12b-2 of the Exchange Act. (Check one):Large accelerated filero     Accelerated filer þ      Non-accelerated filer oIndicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of theAct). Yes o No þAs of June 30, 2006, approximately 85,894,802 shares of Common Stock, par value $0.0001 per sharewere outstanding, and the aggregate market value of the outstanding shares of Common Stock of theCompany held by non-affiliates was approximately $341,847,947 based on a closing price of $4.34 pershare, which was the closing price per share on June 30, 2006. As of February 27, 2007, 86,100,015shares 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 byreference from portions of the registrant’s definitive proxy statement relating to its 2007 annualmeeting of stockholders to be filed within 120 days after December 31, 2006.  
 

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**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 
 

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     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
 

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**EXPLANATORY NOTE**     The Company is filing this Amendment No. 1 to its Annual Report on Form 10-K (the “Amendment”) inresponse to a routine Securities and Exchange Commission comment letter. Changes have been made toItem 1- Business, Item 1A. — Risk Factors, Item 7 — Management’s Discussion and Analysis ofFinancial Condition and Results of Operation and to Note 2 — Significant Accounting Policies andthe Report of Independent Registered Public Accounting Firm of Item 8 — Financial Statements andSupplementary Data. These are the only items that have been amended, but for convenience, the Form10-K is being amended and restated in this Amendment. No other information is being amended bythe Amendment and the Company has not updated disclosures in this Amendment to reflect any eventsubsequent to the Company’s filing of the original report.
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**PART I****ITEM 1 — BUSINESS****Business of Gasco**Gasco Energy, Inc. (“Gasco,” “the Company,” “we,” “our” or “us”) was incorporated under the laws ofthe 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 inlocating and developing hydrocarbon resources, primarily in the Rocky Mountain region. Ourprincipal business strategy is to enhance stockholder value by using technologies new to a specificarea to generate and develop high-potential exploitation resources in this area. Our principalbusiness is the acquisition of leasehold interests in petroleum and natural gas rights, eitherdirectly 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 Basinof 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 (18.0net) 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 alsospudded two wells in Gasco’s Wyoming projects. As of December 31, 2006, Gasco operated 77 grosswells with two additional wells awaiting completion activities. All 77 gross wells are currentlyproducing. Currently, we are operating three drilling rigs in the Riverbend Project and expectdelivery 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, 1997under 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 whollyowned subsidiary of Gasco.In February 2001, a subsidiary of the Company merged with Gasco Production Company (formerly knownas Pannonian Energy, Inc.) (“GPC”), a private corporation incorporated under the laws of the Stateof Delaware. GPC was an independent energy company engaged in the exploration, development andacquisition of crude oil and natural gas reserves in the western United States. Prior to closing ofthe 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. Thenet 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 assetslocated outside of the United States were held by
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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’scapital 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 theCompany, for financial reporting purposes the business combination is accounted for as a reverseacquisition 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 Companycompleted a property acquisition of approximately 21 miles of mainline gathering pipelines andworking interests in 24 oil and gas wells in the Uinta Basin of Utah for $4,875,000, which isincluded 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 atapproximately $30,000,000 based on the closing price of Gasco’s stock on September 20, 2006. As aresult of this acquisition (“Brek Acquisition”), Gasco will acquire approximately 17,095 net acresin 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 interestpartner 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. Theboards of directors of both Brek and Gasco have each approved the terms of the transaction, whichis expected to close during the second quarter of 2007. The completion of the transaction issubject to the approval of the stockholders of Brek and the completion of a distribution of certainsubsidiaries of Brek to its stockholders.Under the terms of the transaction, a wholly-owned subsidiary of Gasco will merge with and intoBrek. As a result of the merger, Brek will become a wholly-owned subsidiary of Gasco and eachstockholder of Brek will receive a number of shares of common stock of Gasco equal to 11,000,000divided by the total number of shares of common stock of Brek outstanding on the date of themerger, calculated on a fully diluted basis. As part of the transaction, the directors of Brek, whocollectively own approximately 24% of Brek’s outstanding stock, have entered into an agreement tovote their shares in favor of the transaction. In addition, Brek’s President and CEO, who ownsapproximately 18% of the outstanding common stock of Brek, has agreed to deposit 550,000 shares ofGasco common stock acquired in the transaction in escrow to satisfy any claims with respect tobreaches of representations and warranties of Brek.
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**Principal Products or Services and Markets**Gasco focuses its exploitation activities on locating natural gas and crude petroleum. Theprincipal markets for these commodities are natural gas transmission pipeline and marketingcompanies, utilities, refining companies and private industry end-users. Historically, nearly allof the Company’s sales have been to a few customers. During the years ended December 31, 2006, 2005and 2004, over 90% of our production was sold to one customer, ConocoPhillips. However, Gasco doesnot believe that the loss of a single purchaser, including ConocoPhillips, would materially affectthe Company’s business because there are numerous other potential purchasers in the areas in whichGasco sells its production. For the years ended December 31, 2006, 2005 and 2004, purchases by thefollowing 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 2004ConocoPhillips  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 competitiveand speculative business atmosphere. In seeking suitable natural gas and petroleum properties foracquisition, 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 andother resources. Management does not believe that Gasco’s competitive position in the petroleumand natural gas industry will be significant.Management anticipates a competitive market for hiring field and technical personnel and obtainingdrilling rigs and services. The current high level of drilling activity in Gasco’s areas ofexploration may have a significant adverse impact on the timing and profitability of Gasco’soperations. In addition, as discussed under “Item 1A — Risk Factors,” Gasco is required to obtaindrilling and right of way permits for its wells, and there is no assurance that such permits willbe 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 ofcompetition to acquire the most promising acreage blocks and obtaining the most favorable pricesfor transporting the product. Gasco, and ventures in which it participates, are relatively smallcompared to other petroleum and natural gas exploration companies. As a result, we may havedifficulty acquiring additional acreage and/or projects, and may have difficulty arranging for thetransportation of the oil or natural gas we produce.
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**Governmental Regulations and Environmental Laws**We are subject to stringent federal, state, and local laws and regulations governing the dischargeof materials into the environment or otherwise relating to environmental protection. These lawsand regulations may require the acquisition of permits before drilling commences, limit or prohibitoperations on environmentally sensitive lands such as wetlands or wilderness areas, result incapital expenditures to limit or prevent emissions or discharges, and place restrictions on themanagement of wastes. Failure to comply with these laws and regulations may result in theassessment of administrative, civil and criminal penalties, the imposition of remedial obligations,and the issuance of injunctive relief. Any changes in environmental laws and regulations thatresult in more stringent and costly waste handling, disposal or cleanup requirements could have amaterial adverse effect on our operations. While we believe that we are in substantial compliancewith current environmental laws and regulations and that continued compliance with existingrequirements would not materially affect us, there is no assurance that this trend will continue inthe 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 thelegality of the original conduct, on certain classes of persons who are considered to beresponsible 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 upthe hazardous substances that have been released into the environment, for damages to naturalresources, and for the costs of certain health studies, and it is not uncommon for neighboringlandowners and other third parties to file claims for personal injury and property damage allegedlycaused by the release of hazardous substances into the environment. We also may incur liabilityunder the Resource Conservation and Recovery Act, also known as “RCRA”, which imposes requirementsrelating to the management and disposal of solid and hazardous wastes. While there exists anexclusion from the definition of hazardous wastes for “drilling fluids, produced waters, and otherwastes associated with the exploration, development, or production of crude oil, natural gas orgeothermal 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 ashazardous waste.We currently own or lease, and have in the past owned or leased, properties that for a number ofyears have been used for the exploration and production of oil and gas. Although we have utilizedoperating and disposal practices that were standard in the industry at the time, hydrocarbons orother wastes may have been disposed of or released on or under the properties owned or leased by usor on or under other locations where such wastes have been taken for disposal. In addition, someof these properties may have been operated by third parties whose disposal or release ofhydrocarbons or other wastes was not under our control. These properties and the wastes disposedthereon may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could berequired to remove or remediate previously disposed wastes or property contamination or to performremedial 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 ofpollutants, including produced waters and other oil and gas wastes, into state or federal waters.
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The discharge of pollutants into regulated waters is prohibited, except in accord with the terms ofa permit issued by EPA or the state. The Clean Water Act provides civil and criminal penalties forany discharge of oil in harmful quantities and imposes liabilities for the costs of removing an oilspill.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 canbegin, and existing facilities may be required to incur capital costs in order to remain incompliance. In addition, the EPA has promulgated more stringent regulations governing emissions oftoxic air pollutants from sources in the oil and gas industry, and these regulations may increasethe costs of compliance for some facilities.In response to increasing levels of concern that emissions of certain gases, including carbondioxide resulting from combustion of hydrocarbons, may be contributing to warming of the Earth’satmosphere, many foreign nations have agreed to limit emissions of these gases, generally referredto 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 KyotoProtocol, the Congress is considering numerous proposals for climate control legislation, includingbills that could restrict greenhouse gas emissions. In addition, several states have alreadyadopted legislation, regulations and/or regulatory initiatives to reduce emissions of greenhousegases. Also, on November 29, 2006, the U.S. Supreme Court heard arguments on a case appealed fromthe U.S. Circuit Court of Appeals for the District Columbia, *Massachusetts, et al. v. EPA*, in whichthe appellate court held that the U.S. Environmental Protection Agency had discretion under thefederal Clean Air Act to refuse to regulate carbon dioxide emissions from mobile sources. Passageof climate control legislation by Congress or a Supreme Court reversal of the appellate decisioncould result in federal regulation of carbon dioxide emissions and other greenhouse gases. Anyfederal or state restrictions on emissions of greenhouse gases that may be imposed in the UnitedStates could adversely affect our operations and the demand for our products.Under the National Environmental Policy Act (“NEPA”), a federal agency, in conjunction with apermit holder, may be required to prepare an environmental assessment or a detailed environmentalimpact statement, also known as an “EIS,” before issuing a permit that may significantly affect thequality 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 andproduction operations in the Uinta Basin of Utah. We expect that the EIS will take approximately18 to 24 months to complete, at an estimated cost to us of about $500,000. Until the EIS iscompleted and issued by the BLM, we will be limited in the number of oil and gas wells that we candrill in the areas undergoing EIS review. To add further assurance that we will not experience asignificant curtailment, we signed a Memorandum of Understanding with the BLM during the first halfof 2005 that allows us to continue drilling while the EIS is being completed. While we do notexpect that the EIS process will result in a significant curtailment in future oil and gasproduction from this particular area, we can provide no assurance regarding the outcome of the EISprocess.
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**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 is http://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, quarterlyreports on Form 10-Q, current reports on Form 8-K and amendments to such reports filed or furnishedpursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon asreasonably 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 themeaning of Section 27A of the Securities Act of 1933, Section 21E of the Private SecuritiesLitigation Reform Act of 1995. These statements express, or are based on, our expectations aboutfuture events. Forward-looking statements give our current expectations or forecasts of futureevents. Forward-looking statements generally can be identified by the use of forward lookingterminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,”“believe” or “continue” or the negative thereof or similar terminology. They include statementsregarding 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;
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 **•** competition and regulation; and  **•** plans, objectives and expectations.Although we believe the expectations and forecasts reflected in these and other forward-lookingstatements are reasonable, we can give no assurance they will prove to have been correct. They canbe affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors thatcould cause actual results to differ materially from expected results are described under “RiskFactors” 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 ofdevelopment 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 thirdparties 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;
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 **•** 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 overfinancial reporting.Any of the factors listed above and other factors contained in this annual report could cause ouractual results to differ materially from the results implied by these or any other forward-lookingstatements made by us or on our behalf. We cannot assure you that our future results will meet ourexpectations.When you consider these forward-looking statements, you should keep in mind these risk factors andthe other cautionary statements in this annual report. Our forward-looking statements speak onlyas 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 industryterms used in this annual report.     *Bbl*. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this annual report inreference 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 toone Bbl of crude oil, condensate or natural gas liquids.     *Btu or British Thermal Unit*. The quantity of heat required to raise the temperature of onepound 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 gasreserve.     *Developed acreage*. The number of acres that are allocated or assignable to productive wellsor wells capable of production.     *Development well*. A well drilled within the proved area of an oil or gas reservoir to thedepth of a stratigraphic horizon known to be productive.
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     *Dry hole*. A well found to be incapable of producing hydrocarbons in sufficient quantitiessuch 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 notclassified as proved, to find a new reservoir in a field previously found to be productive ofnatural gas or oil in another reservoir or to extend a known reservoir. Generally, an exploratorywell 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 naturalgas and oil lease assigns the working interest or a portion of the working interest to anotherparty who desires to drill on the leased acreage. Generally, the assignee is required to drill oneor more wells in order to earn its interest in the acreage. The assignor usually retains a royaltyor reversionary interest in the lease. The interest received by an assignee is a “farm-in” whilethe interest transferred by the assignor is a “farm-out.”     *Field*. An area consisting of either a single reservoir or multiple reservoirs, all grouped onor 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 workinginterest is owned.     *Lead*. A specific geographic area which, based on supporting geological, geophysical or otherdata, 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 toone 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 toone 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 orwells, as the case may be.     *Net feet of pay*. The true vertical thickness of reservoir rock estimated to both containhydrocarbons and be capable of contributing to producing rates.
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     *Present value of future net revenues or present value of discounted future net cash flows orpresent value or PV-10*. The pretax present value of estimated future revenues to be generated fromthe production of proved reserves calculated in accordance with SEC guidelines, net of estimatedproduction and future development costs, using prices and costs as of the date of estimationwithout future escalation, without giving effect to non-property related expenses such as generaland administrative expenses, debt service and depreciation, depletion and amortization, anddiscounted using an annual discount rate of 10%.     *Productive well*. A well that is found to be capable of producing hydrocarbons in sufficientquantities 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 orother data and also preliminary economic analysis using reasonably anticipated prices and costs, isdeemed to have potential for the discovery of commercial hydrocarbons.     *Proved area*. The part of a property to which proved reserves have been specificallyattributed.     *Proved developed oil and gas reserves*. Reserves that can be expected to be recovered throughexisting wells with existing equipment and operating methods. Additional oil and gas expected tobe obtained through the application of fluid injection or other improved recovery techniques forsupplementing the natural forces and mechanisms of primary recovery should be included as “proveddeveloped reserves” only after testing by a pilot project or after the operation of an installedprogram 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 naturalgas liquids which geological and engineering data demonstrate with reasonable certainty to berecoverable 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 ifeconomic producibility is supported by either actual production or conclusive formation test. Thearea of a reservoir considered proved includes (a) that portion delineated by drilling and definedby gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yetdrilled, but which can be reasonably judged as economically productive on the basis of availablegeological and engineering data. In the absence of information on fluid contacts, the lowest knownstructural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserveswhich can be produced economically through application of improved recovery techniques (such asfluid injection) are included in the “proved” classification when successful testing by a pilotproject, or the operation of an installed program in the reservoir, provides support for theengineering analysis on which the project or program was based. Estimates of proved reserves donot include the following: (a) oil that may become available from known reservoirs but isclassified separately as “indicated additional reserves”; (b) crude oil, natural gas and naturalgas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as togeology, reservoir characteristics or economic factors; (c) crude oil, natural gas and natural gasliquids that may occur in undrilled prospects;
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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 onundrilled acreage or from existing wells where a relatively major expenditure is required forrecompletion. Reserves on undrilled acreage are limited to those drilling units offsettingproductive units that are reasonably certain of production when drilled. Proved reserves for otherundrilled units can be claimed only where it can be demonstrated with certainty that there iscontinuity of production from the existing productive formation. Proved undeveloped reserves maynot include estimates attributable to any acreage for which an application of fluid injection orother improved recovery technique is contemplated, unless such techniques have been provedeffective by actual tests in the area and in the same reservoir.     *Reservoir*. A porous and permeable underground formation containing a natural accumulation ofproducible natural gas and/or oil that is confined by impermeable rock or water barriers and isseparate from other reservoirs.     *Service well.*A well drilled or completed for the purpose of supporting production in anexisting field. Specific purposes of service wells include gas injection, water injection, steaminjection, air injection, salt-water disposal, water supply for injection, observation, orinjection for in-situ combustion.     *Stratigraphic test well*. A drilling effort, geologically directed, to obtain informationpertaining to a specific geologic condition. Such wells customarily arc drilled without theintention of being completed for hydrocarbon production. This classification also includes testsidentified 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 apoint that would permit the production of commercial quantities of natural gas and oil regardlessof 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 andconduct 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 gasprospects, the following risk factors apply to Gasco’s operations:
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***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 workingcapital for our ongoing overhead, the funding of our lease acquisitions and the exploration anddevelopment of our properties. Without adequate financing, we may not be able to successfullydevelop any prospects that we have or acquire and we may not achieve profitability from operationsin 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 tradingprice of our common stock or our ability to raise additional capital. Any of these circumstancescould 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 ourreserves. The markets for these commodities are very volatile and even relatively modest drops inprices can significantly affect our financial results and impede our growth. Prices for natural gasand oil may fluctuate widely in response to a variety of additional factors that are beyond ourcontrol, 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 ExportingCountries 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 alsomay reduce the amount of natural gas and oil that we can produce economically. This reduction mayresult in our having to make substantial downward adjustments to our estimated proved reserves. Forexample, 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
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$8.01 per mcf at December 31, 2005 to $45.53 per barrel and $4.47 per mcf at December 31, 2006. Theprice per barrel of oil reflects our blend of oil and condensate. If the estimated capitalinvestment based on recent historical data to drill and complete wells in this area is not reducedmaterially or if the prices for oil and gas do not increase materially from year end 2006 prices wewill 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 gasproduction is anticipated to be located in, the Rocky Mountain Region of the United States. Thegas prices that we and other operators in the Rocky Mountain region have received and are currentlyreceiving are at a discount to gas prices in other parts of the country. Factors that can causeprice volatility for crude oil and natural gas within this region are: **•** the availability of gathering systems with sufficient capacity to handle localproduction;  **•** 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 Mountainregion.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 theavailability of transportation facilities. Our management believes that the steep discount in theprices it receives may be due to pipeline constraints out of the region, but there is no assurancethat increased capacity will improve the prices to levels seen in other parts of the country in thefuture. Even if we acquire additional pipeline capacity, conditions may not improve due to otherfactors listed above.It is impossible to predict natural gas and oil price movements with certainty. Lower natural gasand oil prices may not only decrease our revenues on a per unit basis but also may reduce theamount of natural gas and oil that we can produce economically. A substantial or extended declinein natural gas and oil prices would materially and adversely affect our future business, financialcondition, 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 theprice at which we sell our gas.***Gasco’s production is transported through a single intrastate pipeline and therefore anyconstraints on the capacity of this pipeline could adversely affect our ability to sell ourproduction. Additionally, many pipelines, particularly those connecting to higher — priced easternmarkets, 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,
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or all, of our natural gas production in a given period. As producers vie one with another to selltheir gas, this situation may also serve to reduce the price at which we are able to sell the gasthat does flow. A reduction in the amount of natural gas that we can sell or the price at whichsuch natural gas can be sold could materially adversely affect our financial position and resultsof 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 numerousuncertainties inherent in the process. The process relies on interpretations of availablegeological, geophysical, engineering and production data. The extent, quality and reliability ofthis technical data can vary. The process also requires certain economic assumptions, some ofwhich are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capitalexpenditures, taxes and availability of funds. The accuracy of a reserve estimate is a functionof: **•** 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 onestimates prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers.The most accurate method of determining proved reserve estimates is based upon a decline analysismethod, which consists of extrapolating future reservoir pressure and production from historicalpressure decline and production data. The accuracy of the decline analysis method generallyincreases with the length of the production history. Since most of our wells had been producingless than six years as of December 31, 2006, their production history was relatively short, soother (generally less accurate) methods such as volumetric analysis and analogy to the productionhistory of wells of other operators in the same reservoir were used in conjunction with the declineanalysis method to determine our estimates of proved reserves. As our wells are produced over timeand more data is available, the estimated proved reserves will be redetermined on an annual basisand may be adjusted based on that data. These adjustments could result in downward revisions of ourreserve estimates. We have revised our reserves downward by 36%, 32% and 63% in each of theprevious three years.Actual future production, gas and oil prices, revenues, taxes, development expenditures, operatingexpenses and quantities of recoverable gas and oil reserves most likely will vary from ourestimates. Any significant variance could materially affect the quantities and present value ofour reserves. In addition, we may adjust estimates of proved reserves to reflect productionhistory, results of exploration and development and prevailing gas and oil prices. Our reservesmay 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 thecurrent market value of our estimated proved gas and oil reserves. In accordance with SEC
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requirements, we base the estimated discounted future net cash flows from proved reserves on pricesand costs on the date of the estimate. Actual future prices and costs may be materially higher orlower 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 inimpairment charges.***We may be required to write down the carrying value of our gas and oil properties when gas and oilprices 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 costsless accumulated depletion and net of deferred income taxes may not exceed an amount equal to thepresent value, discounted at 10%, of estimated future net revenues from proved gas and oil reservesless the future cash outflows associated with the asset retirement obligations that have beenaccrued on the balance sheet plus the cost, or estimated fair value, if lower of unprovedproperties.Should capitalized costs exceed this ceiling, an impairment would be recognized. The present valueof estimated future net revenues is computed by applying current prices of gas and oil to estimatedfuture production of proved gas and oil reserves as of period-end, less estimated futureexpenditures to be incurred in developing and producing the proved reserves assuming thecontinuation of existing economic conditions. Once an impairment of gas and oil properties isrecognized, 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 toeliminate the need for the impairment and therefore, impairment expense of $51,000,000 was recordedduring the quarter ended June 30, 2006.***The development of oil and gas properties involves substantial risks that may materially andadversely affect us.***The business of exploring for and producing oil and gas involves a substantial risk of investmentloss that even a combination of experience, knowledge and careful evaluation may not be able toovercome. Drilling oil and gas wells involves the risk that the wells will be unproductive orthat, although productive, the wells do not produce oil and/or gas in economic quantities. Otherhazards, such as unusual or unexpected geological formations, pressures, fires, blowouts, loss ofcirculation of drilling fluids or other conditions may substantially delay or prevent completion ofany well. Adverse weather conditions can also hinder drilling operations.A productive well may become uneconomic in the event water or other deleterious substances areencountered, 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 deleterioussubstances.If we experience any one or more of these risks, our business, financial condition and results ofoperations could be materially and adversely affected.
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***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 similartypes of transactions to fund working capital and the acquisition of our prospects and relatedleases. Failure to generate operating cash flow or to obtain additional financing could result insubstantial dilution of our property interests, or delay or cause indefinite postponement offurther 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 currentand any future indebtedness. In particular, we face uncertainties relating to our ability togenerate sufficient cash flows from operations to fund the level of capital expenditures requiredfor our oil and gas exploration and production activities and our obligations under variousagreements with third parties relating to exploration and development of certain prospects. Ourfailure to find the financial resources necessary to fund our planned activities and service ourdebt and other obligations could materially and adversely affect our business, financial conditionand results of operations.***Delays in obtaining drilling permits could have a materially adverse effect on our ability todevelop our properties in a timely manner.***The average processing time at the Bureau of Land Management in Vernal, Utah for an application todrill on federal leases has been increasing and currently is approximately 14 months. Approximately82% of our gross acreage in Utah is located on federal leases. If we are delayed in procuringsufficient drilling permits for our federal properties, we will shift more of our drilling in Utahto our state leases, the permits for which require an average processing time of approximately twomonths. While such a shift in resources would not necessarily affect the rate of growth of our cashflow, it would result in a slower growth rate of our total proved reserves, because a higherpercentage of the wells drilled on the state leases will be drilled on leases to which provedundeveloped 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 asignificant strain on our financial, technical, operational and management resources. As we expandour 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 failureto continue to upgrade our technical, administrative, operating and financial control systems orthe occurrence of unexpected expansion difficulties, including the recruitment and retention ofexperienced managers, geoscientists and engineers, could have a material adverse effect on ourbusiness, financial condition and results of operations and our ability to timely execute ourbusiness 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 andspeculative business atmosphere. In seeking suitable natural gas and petroleum properties foracquisition, 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
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other resources. We do not believe that our competitive position in the petroleum and natural gasindustry is significant.We anticipate a competitive market for obtaining drilling rigs and services, and the manpower tooperate them. The current high level of drilling activity in our areas of exploration may have asignificant adverse impact on the timing and profitability of our operations. In addition, we arerequired to obtain drilling and right of way permits for our wells, and there is no assurance thatsuch 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 havechosen not to insure against.***Insurance against every operational risk is not available at economic rates. We may suffer lossesfrom uninsurable hazards or from hazards, which we or the operator have chosen not to insureagainst because of high premium costs or other reasons. We may become subject to liability forpollution, fire, explosion, blowouts, cratering and oil spills against which we cannot insure oragainst which we may elect not to insure. Such events could result in substantial damage to oiland gas wells, producing facilities and other property and personal injury. The payment of anysuch liabilities may have a material adverse effect on our business, financial condition andresults 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 andnatural gas lease that has been purchased in error from a person who is not the owner of themineral interest desired, our interest would be worthless. In such an instance, the amount paidfor 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 inpetroleum and natural gas leases, not to undergo the expense of retaining lawyers to examine thetitle to the mineral interest to be placed under lease or already placed under lease. Rather, wewill rely upon the judgment of petroleum and natural gas lease brokers or landmen who perform thefieldwork in examining records in the appropriate governmental office before attempting to acquirea lease in a specific mineral interest.If there are any title defects in the properties in which we hold an interest, we may suffer amonetary loss, including as a result of performing any necessary curative work prior to thedrilling 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 thatwe discover. These factors include the proximity, capacity and availability of oil and gaspipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure,allowable production and environmental protection. The extent of these factors cannot beaccurately predicted, but any one or a combination of these factors may result in our inability tosell 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
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pipeline were to become unavailable, we would incur additional costs to secure a substitutefacility in order to deliver the gas that we produce. In addition, although we currently haveaccess to firm transportation for the majority of our current gas production, there is no assurancethat 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 suchrequirements 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 linetransportation system. Questar is currently evaluating their gas quality requirements to transportgas on their system. These requirements could and most likely, would be imposed on all companiesdelivering gas into their main line. If Questar should require companies to meet more strictquality requirements, there is no assurance that we could meet the new requirements in the shortterm future. It is possible that we would need to make significant capital expenditures to retainthese short term arrangements that allow a majority of our current gas production to access firmtransportation or meet the new gas quality requirements and/or to transport our gas. During thisprocess and/or adding new transportation facilities, our production could be severely curtailed oreven shut -in completely.***Environmental costs and liabilities and changing environmental regulation could materially affectour cash flow.***Our operations are subject to stringent federal, state and local laws and regulations relating toenvironmental protection. These laws and regulations may require the acquisition of permits orother 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 withthese laws may result in the assessment of administrative, civil and criminal penalties, theimposition of remedial obligations, and the issuance of injunctions that may delay or prevent ouroperations. Any stringent changes to these environmental laws and regulations may result inincreased costs to us with respect to the disposal of wastes, the performance of remedialactivities, 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 ourbusiness.***Petroleum and natural gas exploration, development and production are subject to various types ofregulation by local, state and federal agencies. We may be required to make large expenditures tocomply with these regulatory requirements. Legislation affecting the petroleum and natural gasindustry is under constant review for amendment and expansion. Also, numerous departments andagencies, both federal and state, are authorized by statute to issue and have issued rules andregulations binding on the petroleum and natural gas industry and its individual members, some ofwhich carry substantial penalties for failure to comply. Any increases in the regulatory burden onthe petroleum and natural gas industry created by new legislation would increase our cost of doingbusiness and, consequently, adversely affect our profitability. A major
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risk inherent in drilling is the need to obtain drilling and right of way permits from localauthorities. Delays in obtaining drilling and/or right of way permits, the failure to obtain adrilling and/or right of way permit for a well or a permit with unreasonable conditions or costscould 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 forproperties and to better withstand periods of low market prices for hydrocarbons.***The petroleum and natural gas industry is intensely competitive, and we compete with othercompanies, which have greater resources. Many of these companies not only explore for and producecrude petroleum and natural gas but also carry on refining operations and market petroleum andother products on a regional, national or worldwide basis. Such companies may be able to pay morefor 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 humanresources permit. In addition, such companies may have a greater ability to continue explorationactivities during periods of low hydrocarbon market prices. Our ability to acquire additionalproperties and to discover reserves in the future will be dependent upon our ability to evaluateand 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, productionproblems or significant changes in reserve estimates related to any property could have a materialimpact on our business.***Our current reserves and production primarily come from a small number of producing properties inUtah. If mechanical problems with the wells or production facilities including salt waterdisposal, pipelines, compressors and processing plants, depletion or other events including weatheradversely affect any particular property, we could experience a significant decline in ourproduction, which could have a material adverse effect on our cash flows, financial condition andresults of operations. In addition, if the actual reserves associated with any one of ourproperties are less than estimated, our overall reserve estimates could be materially and adverselyaffected.***Financial difficulties encountered by our partners or third-party operators could adversely affectthe exploration and development of our prospects.***Liquidity and cash flow problems encountered by our partners or the co-owners of our properties mayprevent or delay the drilling of a well or the development of a project. Our partners and workinginterest co-owners may be unwilling or unable to pay their share of the costs of projects as theybecome due. In the case of a farm-out partner, we would have to find a new farm-out partner orobtain alternative funding in order to complete the exploration and development of the prospectssubject to the farm-out agreement. In the case of a working interest owner, we could be required topay the working interest owner’s share of the project costs. We cannot assure you that we would beable to obtain the capital necessary to fund either of these contingencies or that we would be ableto find a new farm-out partner. If any of these circumstances were to occur, our ability to exploreand develop our prospects could be adversely affected which could have a material adverse effect onour business, financial condition and results of operations.
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***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 ofdrilling 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. Inaddition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, mayrise as the number of rigs in service increases. If drilling rigs, equipment, supplies or qualifiedpersonnel are unavailable to us due to excessive costs or demand or otherwise, our ability toexecute our exploration and development plans could be materially and adversely affected and, as aresult, our business, financial condition and results of operations could be materially andadversely affected.***Hedging our production may result in losses*****.**We currently have no hedging agreements in place. However, we may in the future enter intoarrangements 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. Hedgingwill 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 inthe hedging agreement and actual prices received.In addition, hedging may limit the benefit we would otherwise receive from increases in the pricesof oil and gas. Further, if we do not engage in hedging, we may be more adversely affected bychanges 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 operateour business.***Our credit facility imposes certain operational and financial restrictions on us. Theserestrictions, 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
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conditions. These restrictions could also limit our ability to obtain future financings, makeneeded capital expenditures, withstand a downturn in our business or the economy in general, orotherwise conduct necessary corporate activities. Our credit facility and restrictions there underare described in greater detail in “Item 7 — Management’s Discussion and Analysis of FinancialCondition and Results of Operations — Credit Facility.”***Our success depends on our key management personnel, the loss of any of whom could disrupt ourbusiness.***The success of our operations and activities is dependent to a significant extent on the effortsand abilities of our management. The loss of services of any of our key managers could have amaterial adverse effect on our business. We have not obtained “key man” insurance for any of ourmanagement. Mr. Erickson is the Chief Executive Officer, Mr. Decker is an Executive Vice Presidentand Chief Operating Officer and Mr. Grant is an Executive Vice President and Chief FinancialOfficer. 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 ofinterest.***Certain of our officers and directors also serve as directors of other companies or havesignificant shareholdings in other companies. Our chairman, Marc A. Bruner, is the largestshareholder of Galaxy Energy Corporation (“Galaxy”) and Exxcel Energy. Mr. Bruner also serves asthe Chairman and Chief Operating Officer of Falcon Oil and Gas, Ltd. (“Falcon”). Falcon’s currentdrilling activities include projects in Romania and Hungary. Carl Stadelhofer, one of our directorsis a director of Falcon. In addition, another of our directors, C. Tony Lotito, currently serves asthe Executive Vice President, Chief Financial Officer, Secretary-Treasurer and a member of theBoard 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 ofPetroHunter and of Providence Resources, Inc. Richard S. Langdon, another one of our directors, isPresident and Chief Executive Officer of Matris Exploration Company, L.P., a private E&P companyactive in onshore California. Mr. Langdon is also a member of the Board of Directors ofConstellation Energy Partners LLC (“CEP”), a public limited liability company focused on theacquisition, development and exploitation of oil and natural gas properties and related midstreamassets. CEP’s activities are currently focused in the Black Warrior Basin of Alabama. Another oneof our directors, Richard Burgess is a director of ROC Oil Company (“ROC”), a Limited LiabilityCorporation incorporated in Australia. ROC has oil and gas activities in China, Australia, UK NorthSea, and West Africa. ROC has no activities in North or South America. The Company estimates thatall of its directors except Mr. Crowell spend approximately 10% of their time on Company businessand 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 leasesand has a majority interest in a private oil and gas company with core assets in Oklahoma andadditional lease holdings in Colorado, Wyoming and Utah. Mr. Erickson spends 100% of his time onGasco business.To the extent that such other companies participate in ventures in which we may participate, orcompete for prospects or financial resources with us, these officers and directors will have a
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conflict of interest in negotiating and concluding terms relating to the extent of suchparticipation. In the event that such a conflict of interest arises at a meeting of the board ofdirectors, a director who has such a conflict must disclose the nature and extent of his interestto the board of directors and abstain from voting for or against the approval of such participationor such terms.In accordance with the laws of the State of Nevada, our directors are required to act honestly andin good faith with a view to the best interests of Gasco. In determining whether or not we willparticipate in a particular program and the interest therein to be acquired by it, the directorswill primarily consider the degree of risk to which we may be exposed and our financial position atthat time.***It may be difficult to enforce judgments predicated on the federal securities laws on some of ourboard members who are not U.S. residents.***Two of our directors reside outside the United States and maintain a substantial portion of theirassets outside the United States. As a result it may be difficult or impossible to effect serviceof process within the United States upon such persons, to bring suit in the United States or toenforce, in the U.S. courts, any judgment obtained there against such persons predicated upon anycivil liability provisions of the U.S. federal securities laws.Foreign courts may not entertain original actions against our directors or officers predicatedsolely upon U.S. federal securities laws. Furthermore, judgments predicated upon any civilliability provisions of the U.S. federal securities laws may not be directly enforceable in foreigncountries.**Risks Related to Our Capital Stock*****Our common stock has experienced, and may continue to experience, price volatility and a lowtrading volume.***The trading price of our common stock has been and may continue to be subject to largefluctuations, which may result in losses to investors. Our stock price may increase or decrease inresponse 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;
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 **•** the operating and stock price performance of other companies that investors may deemcomparable; and  **•** purchases or sales of blocks of our common stock.This volatility may adversely affect the price of our common stock regardless of our operatingperformance. See “Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters andIssuer Purchases of Equity Securities” for further discussion.***Shares eligible for future sale may cause the market price for our common stock to dropsignificantly, even if our business is doing well.***If our existing shareholders sell our common stock in the market, or if there is a perception thatsignificant sales may occur, the market price of our common stock could drop significantly. Insuch case, our ability to raise additional capital in the financial markets at a time and pricefavorable to us might be impaired. In addition, our board of directors has the authority to issueadditional shares of our authorized but unissued common stock without the approval of ourshareholders. Additional issuances of our common stock would dilute the ownership percentage ofexisting shareholders and may dilute the earnings per share of our common stock. As of December31, 2006 we had 86,100,015 shares of common stock issued and outstanding. Additional options maybe granted to purchase 1,895,000 shares of common stock under our stock option plan and anadditional 474,200 shares of common stock are issuable under our restricted stock plan. As ofDecember 31 of each year, the number of shares of common stock issuable under our stock option planautomatically increases so that the total number of shares of common stock issuable under such planis 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 theapplicable conversion prices, the number of shares of our common stock outstanding would increaseby approximately 16,250,000 shares to approximately 101,217,792 shares (this number assumes noexercise of the options or rights described above). In addition, we expect to issue an additional11,000,000 shares of our common stock to former holders of Brek common stock in connection with theBrek Acquisition as well as additional shares of our common stock upon exercise of certain Brekoptions 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 theforeseeable future.***We have not in the past paid, and do not anticipate paying in the foreseeable future, cashdividends on our common stock because our outstanding credit agreement contains covenants thatrestrict our ability to pay dividends on our common stock. Additionally, any future decision to paya dividend and the amount of any dividend paid, if permitted, will be made at the discretion of ourboard of directors.
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***We have anti-takeover provisions in our certificate of incorporation and by-laws that maydiscourage a change of control.***Our articles of incorporation and bylaws contain several provisions that could delay or make moredifficult the acquisition of us through a hostile tender offer, open market purchases, proxycontest, merger or other takeover attempt that a stockholder might consider in his or her bestinterest, including those attempts that might result in a premium over the market price of ourcommon stock.Under the terms of our articles of incorporation and as permitted under Nevada law, we have electednot 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 theoutstanding voting stock of a corporation could not engage in specified business combinations withthe corporation for a period of three years after the date on which the person became an interestedstockholder. With the approval of our stockholders, we may amend our articles of incorporation inthe future to become governed by the anti-takeover law. This provision would then have ananti-takeover effect for transactions not approved in advance by our board of directors, includingdiscouraging takeover attempts that might result in a premium over the market price for the sharesof our common stock.**ITEM 1 B. UNRESOLVED STAFF COMMENTS**None.
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**ITEM 2 — PROPERTIES****Petroleum and Natural Gas Properties**Gasco is a natural gas and petroleum exploitation, development and production company engaged inlocating and developing hydrocarbon resources primarily in the Rocky Mountain Region. Gasco’sprincipal business strategy is to enhance stockholder value by using technologies new to a specificarea to generate and develop high-potential exploitation prospects in this area. Our principalbusiness is the acquisition of leasehold interests in petroleum and natural gas rights, eitherdirectly or indirectly, and the exploitation and development of the properties subject to theseleases.The Company’s corporate strategy is to grow through drilling projects. We have been focusing ourdrilling efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah. Theincreased drilling activity in the Company’s areas of operations resulting from the higher oil andgas prices during 2005 and through the first quarter of 2006 has also decreased the availability ofdrilling rigs and experienced personnel in this area and may continue to do so. The Company alsocontinues to incur higher drilling and operating costs resulting from the increased fuel and steelcosts and from the increased drilling activity in this area.     ***Riverbend Project***The Riverbend Project comprises approximately 124,041 gross acres in the Uinta Basin ofnortheastern 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 theUinta basin: the Wasatch, Mesaverde and Blackhawk formations. A typical well may encountermultiple distinct natural gas sands located between approximately 6,000 and 13,000 feet in depththat 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 (18.0net). Initial completion operations were conducted on 26 wells and 16 well bores were re-enteredto complete behind-pipe pay. As of December 31, 2006, Gasco had 81 gross wells on production. Wecurrently have three drilling rigs operating in the Uinta Basin Riverbend project, and areexpecting delivery of our fourth rig at the end of March 2007.During August 2006, Gasco acquired certain gathering assets and producing properties associatedwith the Riverbend Project in the Uinta Basin of Utah for a cash purchase price of $4,875,000, plussettlement for production from effective date. The gathering assets and properties are locatedentirely within Gasco’s existing Riverbend leasehold allowing the Company to further capitalize oneconomies of scale and operating efficiencies. The transaction closed on August 14, 2006, with aneffective date of July 1, 2006.During 2006, Gasco linked the Wilkin Ridge and West Desert gathering systems to its existing 50MMcfd gas processing facility which began operations in June 2006. Now, up to 95% of producedvolumes are processed in the plant, ensuring that production will meet pipeline specificationsreducing the likelihood of any future curtailments due to gas quality. The
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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 approvedEA 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 asthe 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 “ServiceParties”) to accelerate the development of Gasco’s oil and gas properties by drilling up to 50wells in Gasco’s Riverbend Project in Utah’s Uinta Basin. The development of this project typicallyoccurred 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 notapprove the fourth bundle as proposed by Gasco. As a result, Gasco and the Service Parties arecurrently in discussions on a fourth bundle.We utilize the full cost method of accounting, under which capitalized oil and gas property costsless accumulated depletion, net of deferred income taxes (full cost pool) may not exceed an amountequal to the present value, discounted at 10%, of estimated future net revenues from proved oil andgas reserves less the future cash outflows associated with the asset retirement obligations thathave been accrued in the balance sheet plus the cost, or estimated fair value, if lower of unprovedproperties and the costs of any properties not being amortized, if any. Should the full cost poolexceed this ceiling, an impairment is recognized. This impairment is recorded as non-cash expenseand is not permitted to be reversed in future periods in the event that oil and gas pricessubsequently increase resulting in a higher ceiling. The present value of estimated future netrevenues is computed by applying current prices of oil and gas to estimated future production ofproved oil and gas reserves as of period-end, less estimated future expenditures to be incurred indeveloping and producing the proved reserves assuming the continuation of existing economicconditions. However, subsequent commodity price increases may be utilized to calculate the ceilingvalue.As of December 31, 2006, based on oil and gas prices of $4.47 per mcf and $45.53 per barrel, thefull cost pool would have exceeded the above described ceiling by $28,500,000. However, subsequentto year end, oil and gas prices increased; and using these prices, the Company’s full cost poolwould not have exceeded the ceiling limitation. As a result of the increase in the ceiling amountusing subsequent prices, the Company has not recorded an impairment of its oil and gas prices atDecember 31, 2006. As of June 30, 2006, the Company’s full cost pool exceeded the ceilinglimitation based on oil and gas prices of $59.87 per barrel and $5.42 per mcf. Subsequent commodityprice 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 acresand 29,380 net acres in the Greater Green River Basin area of Wyoming. The acreage
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covers two prospects identified by Gasco. During 2006, Gasco entered into a farmout agreement withan industry partner that drilled to earn acreage in our Daniel Anticline Prospect in Wyoming. Theagreement 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 mutualinterest (AMI) covering this prospect. The AMI will allow both parties to jointly test theproductive potential in the core area and to later implement a plan of development. Under the termsof the farmout agreement, we paid 25% of the well costs and earned 25% of the first well which wasa Hilliard Shale test. The well was drilled to approximately 16,600 feet and was intended to testthe natural gas potential in five formations. Although gas quantities were present, the well wasdetermined to be uneconomic and was plugged during January 2007. The total costs for this well wereapproximately $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 gaspotential in five formations to a revised proposed depth of 14,400 feet. Intermediate casing wasset at approximately 9,600 feet, and the rig was released and drilling operations have beensuspended due to winter lease stipulations. Drilling operations on this well are expected to resumein 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 acreagein 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 thisacquisition (“Brek Acquisition”), Gasco will acquire approximately 17,095 net acres in the UintaBasin of Utah and approximately 12,495 net acres in the Green River Basin of Wyoming. Theacquisition is expected to simplify Gasco’s acreage portfolio by absorbing a working interestpartner 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. Theboards of directors of both Brek and Gasco have each approved the terms of the transaction, whichis expected to close during the second quarter of 2007. The completion of the transaction issubject to the approval of the stockholders of Brek and the completion of a distribution of certainsubsidiaries of Brek to its stockholders.Under the terms of the transaction, a wholly-owned subsidiary of Gasco will merge with and intoBrek. As a result of the merger, Brek will become a wholly-owned subsidiary of Gasco andstockholders of Brek in the aggregate will receive a number of shares of common stock of Gascoequal to 11,000,000 divided by the total number of shares of common stock of Brek outstanding onthe date of the merger, calculated on a fully diluted basis. Gasco may issue additional shares ofour common stock upon exercise of certain Brek options and warrants that we intend to assume inconnection with the Brek acquisition. As part of the transaction, the directors of Brek, whocollectively own approximately 24% of Brek’s outstanding stock, have entered into an agreement tovote their shares in favor of the transaction. In addition, Brek’s President and CEO, who ownsapproximately 18% of the outstanding common stock of Brek, has agreed to deposit
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550,000 shares of Gasco common stock acquired in the transaction in escrow to satisfy any claimswith 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 Kernand San Luis Obispo Counties of Southern California. During 2006, the Company entered into afarm-out agreement under which an unrelated entity has committed to drill one well on our acreagein San Luis Obispo and Kern Counties, California. Under this agreement, Gasco contributed theacreage 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 acreagepositions and develop its remaining California prospects.     ***Nevada Project***The Company has a leasehold interest in approximately 57,302 gross (11,232 net acres) in sixprospects within White Pine County Nevada. We have farmed out our acreage to an industry partnerfor the development of these prospects. Under the terms of the agreement, the industry partner hasthe right to earn up to 80% of the Company’s interest in these properties. The drilling of thefirst 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 presentvalue of discounted future net cash flows is based on prices at December 31, 2006 of $4.47 per Mcfof gas and $45.53 per bbl of oil. All of the Company’s proved reserves are located within the stateof 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                   
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Actual future prices and costs may be materially higher or lower than the prices and costs asof 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 anincrease/decrease in the Company’s December 31, 2006 present value of discounted future net cashflows of approximately $2,180,900.No estimates of proved reserves comparable to those included herein have been included in reportsto 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 pricesreceived and average production costs associated with the Company’s sales of natural gas and oilfor 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 indevelopment and exploration activities, respectively. During 2006, the Company completed a propertyacquisition of approximately 21 miles of mainline gathering pipelines and working interests in 24oil and gas wells in the Uinta Basin of Utah for $4,875,000. Additionally during 2005 we purchaseda drilling rig for approximately $5,000,000. As of December 31, 2006, the Company held an interestin 81 gross (50.8 net to Gasco’s interest) producing gas wells and 16 gross (15.4 net) shut-in gaswells located on these properties.The Company believes that its drilling activity in the Riverbend area is developmental. Thefollowing table presents information regarding the Company’s net costs incurred in the purchase ofproved and unproved properties and in exploration and development activities:
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               **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 thatare capable of production but are currently not producing. Gross wells are the total number ofwells in which the Company has an interest. Net wells are the sum of the Company’s fractionalinterests 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 bythe Company as of December 31, 2006. Undeveloped acres are acres on which wells have not beendrilled or completed to a point that would permit the production of commercial quantities of oiland gas, regardless of whether or not such acreage contains proved reserves. Developed acres areacres, which are spaced or assignable to productive wells. Gross acres are the total number ofacres in which Gasco has a working interest. Net acres are the sum of Gasco’s fractional interestsowned in the gross acres. The table does not include acreage that the Company has a contractualright to acquire or to earn through drilling projects, or any other acreage for which the Companyhas not yet received leasehold assignments. In certain leases, the Company’s ownership is not thesame for all depths; therefore, the net acres in these leases are calculated using the greatestownership interest at any depth. Generally this greater interest represents Gasco’s ownership inthe primary objective formation.
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                   **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 eachof the next three years. The Company’s acreage positions are maintained by the payment of delayrentals 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 onfederal lands and approximately 17% of the acreage is located on state lands. It has been Gasco’sexperience that the permitting process related to the development of acreage on federal lands ismore 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 federalpermits has taken approximately 14 months or longer. If we are delayed in procuring sufficientdrilling permits for our federal properties, we will shift more of our drilling in Utah to ourstate leases. While such a shift in resources would not necessarily affect the rate of growth ofour cash flow, it would result in a slower growth rate of our total proved reserves, because ahigher percentage of the wells drilled on the state leases will be drilled on leases to whichproved undeveloped reserves may already have been attributed. Additionally, if the development ofthe 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 workinginterest, and “net” refers to gross wells multiplied by the Company’s working interest.
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                           **For the Year Ended December 31,**  **2006** **2005** **2004**  Gross Net Gross Net Gross NetExploratory 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 alease, which terminates on May 31, 2010. The average rent for this space over the life of the leaseis approximately $129,300 per year. The Company is currently in negotiations to lease additionalspace in its current location.**ITEM 3 — LEGAL PROCEEDINGS**None.**ITEM 4 — SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS**None.
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**PART II****ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OFEQUITY SECURITIES**The Company’s common stock commenced trading on the OTC bulletin board on March 30, 2001, under thesymbol “GASE.OB.” On December 6, 2004, Gasco’s common stock commenced trading as a listed securityon the American Stock Exchange under the symbol “GSX.” As of February 27, 2007, the Company had110 record shareholders of its common stock. During the last two fiscal years, no cash dividendswere declared on Gasco’s common stock. The Company’s management does not anticipate that dividendswill be paid on its common stock in the near future as Gasco’s credit facility further discussedItem 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 shareof 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 notregistered under the Securities Act of 1933 are described as follows:During 2006, certain holders of the Company’s Series B Convertible Preferred Stock (“PreferredStock”) converted 763 shares of Preferred Stock into 479,599 shares of common stock in accordancewith the terms of such Preferred Stock. The issuance of these shares of common stock was exemptfrom 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 RelatedStockholder Matters regarding information about the Company’s equity compensation plans.
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**ITEM 6 — SELECTED FINANCIAL DATA**The following table sets forth selected financial data, derived from our historical consolidatedfinancial statements and related notes, regarding Gasco’s financial position and results ofoperations as the dates indicated. The financial information is an integral part of, and should beread in conjunction with, the consolidated financial statements and notes thereto. Informationconcerning 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 2002Summary 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 2002Balance 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 lookingstatements used by the Company.**Overview**Gasco is a natural gas and petroleum exploitation, development and production company engaged inlocating and developing hydrocarbon prospects, primarily in the Rocky Mountain region. TheCompany’s business strategy is to enhance shareholder value by using technologies new to a specificarea to generate and develop high-potential exploitation resources in this area. The Company’sprincipal 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 thoseleases. Gasco’s preliminary budget for our 2007 capital program reflects Gasco’s commitment tobuild upon its historical successes and continue its efforts to
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demonstrate the economic viability of its resource in the Uinta Basin of Utah. Economic viabilityof this resource play is a function of the price of natural gas and oil, well investment, welloperating cost and well performance. If the estimated capital investment based on recent historicaldata to drill and complete wells in this area is not reduced materially, if the estimated wellperformance based on recent historical performance data in this area is not increased materially orif the prices for oil and gas do not increase materially from year end 2006 prices we will beunable 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 materialincreases in the prices of oil and gas reflected at year end 2006. In 2007, we plan to continue toprove the geological model, delineate the resource and demonstrate additional operationalefficiencies. During 2007 the Company believes, based on historical experience in 2006, that itwill be able to demonstrate reduced well investment through operating efficiencies gained throughimproved drilling and completion practices, introduction of new technologies and economies ofscale. In the last half of 2006 we experienced reduced well investment due to reduced drilling daysand lower service costs. We believe well performance is likely to improve as knowledge increaseswith additional well development and introduction of new technologies. Historically, during periodsof lower prices of natural gas and oil well investment has been much lower and the Company believesthat any prolonged period of prices similar to those seen at year end 2006 would result insignificantly lower well investment in the future. However, the Company believes that commodityprices reflected at the year end 2006 are not representative of the long term price for natural gasand oil.The Company’s corporate strategy is to grow through drilling projects. The Company has beenfocusing its drilling efforts in the Riverbend Project located in the Uinta Basin of northeasternUtah. The higher oil and gas prices during 2005 and through the first quarter of 2006 due tofactors such as inventory levels of gas in storage, extreme weather in parts of the country andincreasing demand in the United States, combined with the continued instability in the Middle Eastresulted in increased drilling activity in the Riverbend area. The increased drilling activity inthe area decreased the availability of drilling rigs and experienced personnel in this area and maycontinue to do so in the future. The Company also continues to incur higher drilling and operatingcosts resulting from the increased fuel and steel costs and from the increased drilling activity inthis area.**Recent Developments*****Drilling Activity***During the year ended December 31, 2006, the Company spudded 30 gross wells (approximately 18.5 netwells) and reached total depth on 29 gross wells (approximately 18.0 net wells) in the Riverbendarea. We also conducted initial completion operations on 26 wells (16.5 net wells) and re-entered16 wells (8.0 net wells) to complete pay zones that were behind pipe. As of December 31, 2006, weoperated 77 gross wells with two additional wells awaiting completion activities. We currently havethree drilling rigs operating in the Uinta Basin Riverbend project, and are expecting delivery ofour fourth rig at the end of March 2007.
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During 2006, Gasco entered into a farmout agreement with an industry partner that drilled to earnacreage in our Daniel Anticline Prospect in Wyoming. The agreement allows our industry partner toearn 50% of our Daniel Anticline Prospect to all depths. We will retain operations of the wells inthe project. We have also established an area of mutual interest (AMI) covering this prospect. TheAMI will allow both parties to jointly test the productive potential in the core area and to laterimplement a plan of development. Under the terms of the farmout agreement, we paid 25% of the wellcosts and earned 25 % of the first well which was a Hilliard Shale test. The well was drilled toapproximately 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 pluggedduring January 2007.Gasco is also currently drilling a well in the Muddy Creek Prospect in Wyoming to test natural gaspotential in five formations to a revised proposed depth of 14,400 feet. Intermediate casing wasset at approximately 9,600 feet, and the rig has been released and drilling operations have beensuspended due to winter lease stipulations. Drilling operations on this well are expected to resumein 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 “ServiceParties”) to accelerate the development of Gasco’s oil and gas properties by drilling up to 50wells in Gasco’s Riverbend Project in Utah’s Uinta Basin. The development of this project typicallyoccurred 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 notapprove the fourth bundle as proposed by Gasco. As a result, Gasco and the Service Parties arecurrently in discussions on a fourth bundle.***Property Impairment***During 2006, approximately $3,786,000 of unproved lease costs related primarily to expiring acreagein Wyoming were reclassified to proved property.We utilize the full cost method of accounting, under which capitalized oil and gas property costsless accumulated depletion, net of deferred income taxes (full cost pool) may not exceed an amountequal to the present value, discounted at 10%, of estimated future net revenues from proved oil andgas reserves less the future cash outflows associated with the asset retirement obligations thathave been accrued in the balance sheet plus the cost, or estimated fair value, if lower of unprovedproperties and the costs of any properties not being amortized, if any. Should the full cost poolexceed this ceiling, an impairment is recognized. This impairment is recorded as non-cash expenseand is not permitted to be reversed in future periods in the event that oil and gas pricessubsequently increase resulting in a higher ceiling. The present value of estimated future netrevenues is computed by applying current prices of oil and gas to estimated future production ofproved oil and gas reserves as of period-end, less estimated future expenditures to be incurred indeveloping and producing the proved reserves assuming the continuation of existing economicconditions. However, subsequent commodity price increases may be utilized to calculate the ceilingvalue.
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As of December 31, 2006, based on oil and gas prices of $4.47 per mcf and $45.53 per barrel, thefull cost pool would have exceeded the above described ceiling by $28,400,000. However, subsequentto year end, oil and gas prices increased; and using these prices, the Company’s full cost poolwould not have exceeded the ceiling limitation. As a result of the increase in the ceiling amountusing subsequent prices, the Company has not recorded an impairment of its oil and gas prices atDecember 31, 2006. As of June 30, 2006, the Company’s full cost pool exceeded the ceilinglimitation based on oil and gas prices of $59.87 per barrel and $5.42 per mcf. Subsequent commodityprice 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 RiverbendProject in the Uinta Basin of Utah for a cash purchase price of $4,875,000, plus settlement forproduction from effective date. The gathering assets and properties are located entirely withinGasco’s existing Riverbend leasehold allowing the Company to further capitalize on economies ofscale and operating efficiencies. The transaction closed on August 14, 2006, with an effectivedate of July 1, 2006. The Company assigned a value of approximately $2,500,000 to the gatheringassets, which include 21 miles of 4” to 8” mainline gathering pipelines. The acquired gatheringassets should provide more timely and cost-effective tie-in of the existing Wilkin Ridge and WestDesert systems to Gasco’s Riverbend gas processing facility. Gasco now controls nearly 100 miles ofmainline 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 itsRiverbend gas processing plant. The gathering lines acquired in this transaction may be tied intothese systems at an estimated cost of $1.5 million, allowing the Company to potentially realize asavings of $1 million versus amounts previously budgeted.Also included in the acquisition are 24 oil and gas wells producing 400 thousand cubic feetequivalent per day (Mcfe/d) gross (320 Mcfe/d net). In the transaction, Gasco acquiredapproximately 1.6 billion cubic feet equivalent of proved reserves. The acquisition has no effecton 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 SpringCanyon (Blackhawk) wells which should yield savings on building a new drilling pad and access roadof $50,000 to $100,000 per location.***Other Operations***During 2006, Gasco completed the linking of the Wilkin Ridge and West Desert gathering systems toits 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 pipelinespecifications reducing the likelihood of any future curtailments. The Company currently operatesnearly 100 miles of gathering system along with the processing facility.
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Gasco recently received approval of its Riverbend Environmental Assessment (EA). The approved EAincludes 45 proposed wells within the Spring Canyon marine trend of the Blackhawk Formation. TheEA should provide for accelerated permitting approvals from the Bureau of Land Management as theenvironmental 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 theacquisition, Gasco will acquire approximately 17,095 net acres in the Uinta Basin of Utah andapproximately 12,495 net acres in the Green River Basin of Wyoming. The acquisition is expected tosimplify Gasco’s acreage portfolio by absorbing a working interest partner that previously ownedapproximately 14% of Gasco’s undeveloped acreage in Utah and Wyoming. Gasco does not expect toincur any additional overhead expenses as a result of the acquisition. The boards of directors ofboth Brek and Gasco have each approved the terms of the transaction, which is expected to closeduring the second quarter of 2007. The completion of the transaction is subject to the approval ofthe stockholders of Brek and the completion of a distribution of certain subsidiaries of Brek toits stockholders.Under the terms of the transaction, a wholly-owned subsidiary of Gasco will merge with and intoBrek. As a result of the merger, Brek will become a wholly-owned subsidiary of Gasco andstockholders of Brek in the aggregate will receive a number of shares of common stock of Gascoequal to 11,000,000 divided by the total number of shares of common stock of Brek outstanding onthe date of the merger, calculated on a fully diluted basis. Gasco may issue additional shares ofour common stock upon exercise of certain Brek options and warrants that we intend to assume inconnection with the Brek acquisition. As part of the transaction, the directors of Brek, whocollectively own approximately 24% of Brek’s outstanding stock, have entered into an agreement tovote their shares in favor of the transaction. In addition, Brek’s President and CEO, who ownsapproximately 18% of the outstanding common stock of Brek, has agreed to deposit 550,000 shares ofGasco common stock acquired in the transaction in escrow to satisfy any claims with respect tobreaches of representations and warranties of Brek.***Credit Facility***On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered into a $250million Credit Agreement (the “Credit Agreement”) with JPMorgan Chase Bank, N.A., as AdministrativeAgent and the other lenders named therein. Borrowings made under the Credit Agreement areguaranteed by our subsidiaries and secured by a pledge of the capital stock of our subsidiaries andmortgages on substantially all of our oil and gas properties. We have not borrowed any funds underthe 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 wassubsequently increased to $25,000,000 during October 2006. The Credit Agreement also
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provides for a $10,000,000 sublimit for letters of credit which we may use for general corporatepurposes. As of December 31, 2006 there were no loans outstanding, however; a $6,564,000 letter ofcredit is considered usage, for purposes of calculating availability and commitment fees. Ouraggregate borrowings and outstanding letters of credit under the Credit Agreement may not at anytime exceed the borrowing base. Interest on borrowings is payable monthly and principal is due atmaturity on March 29, 2010.Interest on borrowings under the Credit Agreement accrues at variable interest rates at either, atour election, a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated asLIBOR plus an applicable margin that varies from 1.25% (for periods in which we have utilized lessthan 50% of the borrowing base) to 2.00% (for periods in which we have utilized greater than 90% ofthe borrowing base). The alternate base rate is calculated as (1) the greater of (a) the PrimeRate or (b) the Federal Funds Effective Rate plus 1/2%, plus (2) an applicable margin that variesfrom 0% (for periods in which we have utilized less than 50% of the borrowing base) to 0.75% (forperiods in which we have utilized greater than 90% of the borrowing base). We elect the basis ofthe interest rate at the time of each borrowing. In addition, we are obligated to pay a commitmentfee under the Credit Agreement quarterly in arrears based on a percentage multiplied by the dailyamount that the aggregate commitments exceed borrowings under the agreement. The commitment feepercentage 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 Facilitydivided by current liabilities excluding the current portion of the Credit Facility), determined atthe end of each quarter, of not less than 1.0:1; and (2) a ratio of Senior Debt to EBITDAX (as suchterms are defined in the Credit Agreement) for the most recent quarter multiplied by four not to begreater than 3.5:1 for each fiscal quarter. In addition, the Credit Agreement contains covenantsthat restrict our ability to incur other indebtedness, create liens or sell our assets, paydividends on our common stock and make certain investments. As of December 31, 2006, we were incompliance with each of the covenants contained in the Credit Facility.The Company incurred $240,262 in debt issuance costs associated with this facility. These costshave been recorded as deferred financing costs in the accompanying financial statements and arebeing amortized over the four year term of the credit facility. The credit facility is available toprovide funds for the exploration, development and/or acquisition of oil and gas properties, torefinance existing indebtedness and for working capital and other general corporate purposes. TheCredit Agreement provides for semi-annual evaluation of the borrowing base, which will bedetermined as a percentage of the discounted present value of the Company’s oil and natural gasreserves.The following table presents certain of the Company’s production information for each of the threeyears ended December 31, 2006 and our estimated proved reserves as of December 31 of each yearpresented. The Mcfe calculations assume a conversion of 6 Mcf’s for each Bbl of oil.
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               **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 with2005 primarily due to the Company’s drilling and completion of 26 gross (16.5 net) wells during2006. During 2006, the developed oil and gas reserve quantities increased by 109% to 41.0 Bcfe from19.6 Bcfe in 2005. During 2006, on a combined basis, the oil and gas reserve quantities decreasedby 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 ispartially offset by reserve additions of 22% and reserve purchases of 1%. The Company’s oil and gasreserves 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 the2006 reserve report because these locations did not yield a positive net present value at adiscount rate of 10% at the current estimated capital investment based on recent historicaldata to drill and complete wells in this area.  **–** Four gross locations previously classified as proved undeveloped were developed in 2006and two gross proved undeveloped locations were added.The Company’s oil and gas production increased by approximately 219% during 2005 as compared with2004 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% primarilydue to reserve additions of 122% which were partially offset by annual production of 4% andrevisions of previous estimates of 32%. The majority of the revisions of previous estimates were aresult of the following: **–** Four locations previously classified as proved undeveloped were omitted from the 2005reserve report because these locations required a higher capital investment than originallyestimated due to drilling and completion problems and due to the lack of historical datarelated to recent completions and recompletions in this area.
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 **–** Six locations previously classified as proved undeveloped were omitted from the 2005reserve report because recent drilling activity indicates that these locations may beoutside of or on the edge of a previously identified zone.  **–** Two proved developed non-producing completions significantly underperformed previousforecasts.**Liquidity and Capital Resources**The following table summarizes the Company’s sources and uses of cash for each of the three yearsended 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 ingross revenue during 2006. The increase is comprised of a 124% increase in oil and gas productionand a 94% increase in interest income due to a higher outstanding average balance in cash and shortterm investments, partially offset by a 34% decrease in gas prices during 2006. The increase incash provided by operations during 2005 compared to 2004 is primarily due to a 219% increase in oiland gas production, a 41% increase in gas prices and a 48% increase in oil prices. The productionincreases in 2006 and 2005 were primarily due to drilling activity.The Company’s investing activities during the three years ended December 31, 2006 related primarilyto the Company’s development and exploration activities and the purchase of a drilling rig. During2004, we also completed acquisitions of acreage and additional working interests in producing wellsfor approximately $5,800,000. We had sales proceeds of $828,102 during 2005 which represented thesale of acreage to an unrelated entity. Our sales proceeds during 2004 represented a disposition ofnet profits interests in 8 wells in the Riverbend area for $4,463,161. We also invested $27,000,000in short-term investments during 2004 and sold $9,000,000 and $12,000,000 of these investmentsduring 2006 and 2005, respectively. The remaining investing activity during 2006, 2005 and 2004consisted primarily of changes in our restricted investments.The Company’s financing activities during 2006 are comprised mainly of proceeds from the exerciseof 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 saleof 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 priceto the public of $6.50 per share. We also granted the underwriters a 30-day option to purchase upto 1,875,000 additional shares of our common stock solely to cover over-allotments.
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Pursuant to this option, the underwriters purchased an additional 439,400 shares of common stock onDecember 6, 2005. The net proceeds from this offering, after underwriting discount and offeringcosts, 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 itscommon stock to a group of accredited investors at a price of $1.50 per share, receiving netproceeds of $20,070,000 and closed the private placement of $65,000,000 in aggregate principalamount 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 boardof director approval. The program will primarily cover the drilling and completion of at least 10net wells on our Riverbend Project and the completion of the drilling of one in Wyoming. The budgetalso includes expenditures for the installation of associated pipeline infrastructure, distributionfacilities and geophysical operations.This budget will be funded primarily from cash on hand, cash flow from operations and borrowingsunder our line of credit.Management believes it has sufficient capital for its 2007 operational budget, but may need toraise additional capital for its capital budget in 2008. The Company may consider several optionsfor raising additional funds such as selling securities, selling assets or farm-outs or similartype arrangements. Any financing obtained through the sale of Gasco equity will likely result insubstantial dilution to the Company’s stockholders.**Schedule of Contractual Obligations**The following table summarizes the Company’s obligations and commitments to make future paymentsunder its notes payable, operating leases, employment contracts, consulting agreements and servicecontracts for the periods specified as of December 31, 2006.
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                       **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 CashObligations $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 forthe Company to terminate the contract prior to lease expiration for payments of $12,000per 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 theaccompanying consolidated financial statements, as the Company cannot determine with accuracy thetiming of such payments.**Critical Accounting Policies and Estimates**The preparation of the Company’s consolidated financial statements in conformity with generallyaccepted accounting principles in the United States requires management to make assumptions andestimates that affect the reported amounts of assets, liabilities, revenues and expenses as well asthe disclosure of contingent assets and liabilities at the date of the financial statements and thereported amounts of revenues and expenses during the reporting period. The following is a summaryof the significant accounting policies and related estimates that affect the Company’s financialdisclosures.     ***Oil and Gas Reserves***Gasco follows the full cost method of accounting whereby all costs related to the acquisition anddevelopment of oil and gas properties are capitalized into a single cost center referred to as afull cost pool. Depletion of exploration and development costs and depreciation of productionequipment is computed using the units-of-production method based upon estimated proved oil and gasreserves. Under the full cost method of accounting, capitalized oil and gas property costs lessaccumulated depletion and net of deferred income taxes may not exceed an amount equal to thepresent value, discounted at 10%, of estimated future net revenues from proved oil and gas reservesless the future cash outflows associated with the asset retirement obligations that have beenaccrued on the balance sheet plus the cost, or estimated fair value if lower, of unprovedproperties. Should capitalized costs exceed this ceiling, an impairment would be recognized.
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As of December 31, 2006, based on oil and gas prices of $4.47 per mcf and $45.53 per barrel, thefull cost pool would have exceeded the above described ceiling by $28,400,000. However, subsequentto year end, oil and gas prices increased; and using these prices, the Company’s full cost poolwould not have exceeded the ceiling limitation. As a result of the increase in the ceiling amountusing subsequent prices, the Company has not recorded an impairment of its oil and gas prices atDecember 31, 2006. As of June 30, 2006, the Company’s full cost pool exceeded the ceilinglimitation based on oil and gas prices of $59.87 per barrel and $5.42 per mcf. Subsequent commodityprice 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 inthe estimated value of the full cost ceiling as describe above, could have a material impact on thetotal of the impairment recorded by the Company.Estimated reserve quantities and future net cash flows have the most significant impact on theCompany because these reserve estimates are used in providing a measure of the Company’s overallvalue. These estimates are also used in the quarterly calculations of depletion, depreciation andimpairment of the Company’s proved properties.Estimating accumulations of gas and oil is complex and is not exact because of the numerousuncertainties inherent in the process. The process relies on interpretations of availablegeological, geophysical, engineering and production data. The extent, quality and reliability ofthis technical data can vary. The process also requires certain economic assumptions, some ofwhich 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. Theaccuracy of a reserve estimate is a function of the quality and quantity of available data; theinterpretation of that data; the accuracy of various mandated economic assumptions; and thejudgment of the persons preparing the estimate.The most accurate method of determining proved reserve estimates is based upon a decline analysismethod, which consists of extrapolating future reservoir pressure and production from historicalpressure decline and production data. The accuracy of the decline analysis method generallyincreases with the length of the production history. Since most of the Company’s wells have beenproducing less than six years, their production history is relatively short, so other (generallyless accurate) methods such as volumetric analysis and analogy to the production history of wellsof other operators in the same reservoir were used in conjunction with the decline analysis methodto determine the Company’s estimates of proved reserves including developed producing, developednon-producing and undeveloped. As the Company’s wells are produced over time and more data isavailable, the estimated proved reserves will be redetermined on an annual basis and may beadjusted based on that data.Actual future production, gas and oil prices, revenues, taxes, development expenditures, operatingexpenses and quantities of recoverable gas and oil reserves most likely will vary from theCompany’s estimates. Any significant variance could materially affect the quantities and presentvalue of the Company’s reserves. For example a decrease in price of $0.10 per Mcf for natural gasand $1.00 per barrel of oil would result in a decrease in the Company’s December 31, 2006 presentvalue of future net cash flows of approximately $2,180,900. In addition, the
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Company may adjust estimates of proved reserves to reflect production history, acquisitions,divestitures, ownership interest revisions, results of exploration and development and prevailinggas and oil prices. The Company’s reserves may also be susceptible to drainage by operators onadjacent properties.     ***Impairment of Long-lived Assets***The cost of the Company’s unproved properties is withheld from the depletion base as describedabove, 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’smanagement reviews all unproved property. If a determination is made that acreage will be expiringor that the Company does not plan to develop some of the acreage that is no longer considered to beprospective, the Company records an impairment of the acreage and reclassifies the costs to thefull cost pool. The Company estimates the value of these acres for the purpose of recording therelated impairment. The impairments that have been recorded by the Company were estimated bycalculating a per acre value from the total unproved costs incurred for the applicable acreagedivided by the total net acres owned by the Company. This per acre estimate is then applied to theacres that the Company does not plan to develop in order to calculate the impairment. As a resultof this process the Company has recorded impairments of $3,786,000 and $5,300,000 during the yearsended December 31, 2006 and 2005, respectively. These impairments related primarily to the costs ofexpiring acreage in Wyoming. A change in the estimated value of the acreage could have a materialimpact 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 recognizecompensation 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 isrecognized 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 disclosuresunder SFAS 123(R). This model requires the Company to estimate a risk free interest rate and thevolatility of the Company’s common stock price. The use of a different estimate for any one ofthese 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, throughDecember 31, 2005 for accounting for stock option awards to employees and directors which resultedin the accounting for grants of awards to employees and directors at their intrinsic value in theconsolidated financial statements. Accordingly, Gasco has recognized compensation expense in thefinancial statements for awards granted to consultants which must be re-measured each period underthe mark-to-market accounting method. Gasco had previously adopted the provisions of FAS No. 123,“Accounting for Stock-Based Compensation”, as
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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,” usingthe 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 accordancewith the modified prospective method, we have not adjusted the financial statements for periodsended prior to January 1, 2006. The Company did not recognize any one time effects of the adoptionand continued to use similar option valuation models and assumptions as were used prior to January1, 2006. The total fair-value-based compensation expense associated with prior awards that was notvested on the date of the adoption of SFAS No. 123(R) was approximately $4,800,000 which wasexpected to be recognized over the weighted average remaining life of the options of approximatelyone year.**Results of Operations**The following table presents information regarding the production volumes and average sales pricesreceived 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 anincrease in oil and gas production of 11,010 bbls and 2,037,768 Mcf partially offset by a decreasein the average oil price of $2.05 per bbl and a decrease in the average gas price of $2.78 per Mcfduring 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 relatedto 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 normalproduction declines on all wells.Gathering revenue and expense from gathering operations represents the income earned and expensesincurred 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 increasedproduction attributable to the outside working interest owners, resulting from the Company’sdrilling activity in this area. Approximately $500,000 of the $1,551,516 increase in expense fromgathering operations is due to the installation of additional compression to the system andapproximately $594,000 of the increase is the result of the
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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 theoutside working interest and royalty owners in the Company’s producing wells. The remainingincrease 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 higherinterest rates and higher average cash and cash equivalent and short-term investment balancesduring 2006 relating primarily to the net proceeds of approximately $79,000,000 from the Company’scommon stock offering during November 2005.Lease operating expense increased $2,642,975 during 2006 compared with 2005. The increase isprimarily 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 producingwells from 45 wells at December 31, 2005 to 81 wells at December 31, 2006. Also contributing to thehigher lease operating expenses during 2006 is increased water hauling and disposal costs ofapproximately $420,000 and increased production and property taxes of $620,000. Additionally, leaseoperating expense during 2006 includes approximately $400,000 of costs related to workoversperformed on ten of our wells in the Riverbend area in order to restore efficient operatingconditions on these wells.Depletion, depreciation and amortization expense during 2006 is comprised of depletion expenserelated to the Company’s oil and gas properties, depreciation expense of furniture, fixtures andequipment 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 costsresulting from the Company’s increased drilling and completion activity discussed above, partiallyoffset by the $51,000,000 reduction in the full cost pool due to the impairment recorded during thesecond quarter of 2006, as described below.Impairment expense during 2006 represents the impairment recorded as of June 30, 2006 because thepresent value of Gasco’s future net revenue discounted at 10% exceeded the Company’s full cost poolbased 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. Theincrease is primarily due to an increase in stock-based compensation expense of $4,151,509 due tothe adoption of SFAS 123(R) on January 1, 2006 as further discussed in Note 3 of the accompanyingfinancial statements and increased consulting expenses of approximately $141,000 related to themaintenance and testing of our internal controls. The increased expenses were partially offset by adecrease of approximately $860,000 related to the capitalization of certain drilling and completionoverhead and the allocation of internal administrative costs related to the operations of our wellsduring 2006.Interest expense during 2006 and 2005 consists primarily of interest expense related to theCompany’s outstanding Convertible Senior Notes which were issued on October 20, 2004.
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**2005 Compared to 2004**Oil and gas revenue increased $10,944,419 during 2005 compared with 2004 due to an increase in oiland gas production of 5,556 bbls and 1,142,903 Mcf combined with an increase in the average oil andgas prices of $18.48 per bbl and $2.37 per Mcf during 2005. The $10,944,419 increase in oil and gasrevenue during 2005 is comprised of $9,650,353 related to the production increase and $1,294,066related to the price increase. The production increase is due to the Company’s drilling, completionand recompletion activity during 2004 and 2005 and is partially offset by the production decreaseresulting from the Company’s disposition of approximately 50% of its revenue interest in two wellsduring 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 Riverbendarea pipeline. The increase in this revenue and expense from 2004 is due to the full year ofactivity 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 cashand cash equivalent and short-term investment balances during 2005 relating primarily to proceedsfrom the Company’s $65,000,000 Convertible Senior Note issuance during October 2004 and theproceeds from the common stock offering during November 2005.Lease operating expense increased $232,326 during 2005 compared with 2004 primarily due to theincreased number of producing wells during 2005.Depletion, depreciation and amortization expense during 2005 increased as compared with 2004 dueprimarily to the increase in production and related costs resulting from the Company’s increaseddrilling 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 iscomprised of approximately $855,000 in salary expense and consulting fees associated with ourincreased operational activity, $355,000 in fees associated with the Company’s audit of internalcontrols as required under the Sarbanes Oxley Act of 2002 and $525,000 in stock-based compensationprimarily related to the Company’s restricted stock issuance and the issuance of stock options toconsultants. The remaining increase in general and administrative expenses is due to thefluctuation in numerous other expenses, none of which are individually significant.Interest expense during 2005 consists of interest expense related to the Company’s outstandingConvertible Senior Notes which were issued on October 20, 2004. Interest expense during 2004consists of the interest on the Company’s outstanding Convertible Debentures issued in October 2003that were converted into common stock during October 2004 and interest on the Convertible SeniorNotes for approximately two months.
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**Recent Accounting Pronouncements**On June 1, 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, “AccountingChanges 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 reportingof accounting changes and error corrections. It established retrospective application, or thelatest practicable date, as the required method for reporting a change in accounting principle andthe reporting of a correction of an error. SFAS 154 was effective for accounting changes andcorrections of errors made January 1, 2006. The adoption of SFAS No. 154 had no impact on theCompany’s financial statements.In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid FinancialInstruments-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 forTransfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and also resolvesissues addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 toBeneficial Interests in Securitized Financial Assets.” SFAS No. 155 was issued to eliminate theexemption from applying SFAS No. 133 to interests in securitized financial assets so that similarinstruments are accounted for in a similar fashion, regardless of the instrument’s form. TheCompany does not believe that its financial position, results of operations or cash flows will beimpacted 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 IncomeTaxes” (“FIN 48”). The interpretation clarifies the accounting for uncertainty in income taxesrecognized in a company’s financial statements in accordance with SFAS 109, “Accounting for IncomeTaxes”. Specifically, the pronouncement prescribes a recognition threshold and a measurementattribute for the financial statement recognition and measurement of a tax position taken orexpected to be taken in a tax return. The interpretation also provides guidance on the relatedderecognition, classification, interest and penalties, accounting for interim periods, disclosureand transition of uncertain tax positions. The interpretation is effective January 1, 2006 for theCompany. The adoption of FIN 48 is expected to have an immaterial impact on the Company’sconsolidated financial position, results of operations and cash flows.In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”. This Statement defines fairvalue as used in numerous accounting pronouncements, establishes a framework for measuring fairvalue in generally accepted accounting principles and expands disclosure related to the use of fairvalue measures in financial statements. The Statement is to be effective for the Company’sfinancial statements issued in 2008; however, earlier application is encouraged. The Company iscurrently evaluating the timing of adoption and the impact that adoption might have on itsfinancial position or results of operations.In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting BulletinNo. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108
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expresses SEC staffviews regarding the process by which misstatements in financial statementsare evaluated for purposes of determining whether financial statement restatement is necessary. SAB108 is effective for the Company on January 1, 2007. The Company does not believe SAB 108 will havea 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 forRegistration Payment Arrangements.” This FSP specifies that the contingent obligation to makefuture payments or otherwise transfer consideration under a registration payment arrangement shouldbe separately recognized and measured in accordance with FASB Statement No. 5, “Accounting forContingencies”. This FSP is effective immediately for registration payment arrangements and thefinancial instruments subject to those arrangements that are entered into or modified subsequent toDecember 21, 2006. For registration payment arrangements and financial instruments subject to thosearrangements that were entered into prior to December 21, 2006, the guidance in the FSP iseffective January 1, 2006 for the Company. The Company does not believe that this FSP will have amaterial 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 andFinancial Liabilities.” This Statement establishes presentation and disclosure requirementsdesigned to facilitate comparisons between companies that choose different measurement attributesfor similar types of assets and liabilities. SFAS No. 159 is effective for the Company’s financialstatements issued in 2008. The Company is currently evaluating the impact that the adoption of SFASNo. 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 riseto off-balance sheet obligations. As of December 31, 2006, the off-balance sheet arrangements andtransactions that we have entered into include undrawn letters of credit, operating leaseagreements and gas transportation commitments. The Company does not believe that these arrangementsare 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 gasproduction in the Uinta Basin of northeastern Utah and the Greater Green River Basin of westcentral Wyoming. This risk will become more significant to the Company as more wells are drilledand begin producing in these areas. Although the Company is not using derivatives at this time tomitigate 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 tovariable rates of interest.
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**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 EndedDecember 31, 2006, 2005 and 2004 56   Consolidated Statements of Stockholders’ Equity for the YearsEnded December 31, 2006, 2005 and 2004 57   Consolidated Statements of Cash Flows for the Years EndedDecember 31, 2006, 2005 and 2004 58    Notes to Consolidated Financial Statements 59-94
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**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. Ourresponsibility 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 OversightBoard (United States). Those standards require that we plan and perform the audit to obtainreasonable assurance about whether the financial statements are free of material misstatement. Anaudit includes examining, on a test basis, evidence supporting the amounts and disclosures in thefinancial statements. An audit also includes assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overall financial statementpresentation. 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 allmaterial respects, the financial position of the Company as of December 31, 2006 and 2005, and theresults of their operations and their cash flows for each of the three years in the period endedDecember 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 OversightBoard (United States), the effectiveness of the Company’s internal control over financial reportingas of December 31, 2006, based on criteria established in Internal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and ourreport dated February 27, 2007 expressed an unqualified opinion on management’s assessment of theeffectiveness of the Company’s internal control over financial reporting and an unqualified opinionon 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-BasedPayment*./s/ Hein & Associates LLP