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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2011

OR

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

FOR THE TRANSITION PERIOD FROM              TO

Commission File Number: 001-32369

GASCO ENERGY, INC.

(Exact name of registrant as specified in its charter)

(303) 483-0044

(Registrant’s telephone number, including area code)

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

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

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

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

Number of common shares outstanding as of May 10, 2011: 126,943,715

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Please refer to the section entitled “Cautionary Statement Regarding Forward-Looking Statements” at the end of Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2011 (“Quarterly Report”) for a discussion of factors which could affect the outcome of forward-looking statements used in this Quarterly Report.

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ITEM I — FINANCIAL STATEMENTS

PART 1 — FINANCIAL INFORMATION

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

(Unaudited)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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GASCO ENERGY, INC.

NOTES TO UNAUDITED CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

THREE MONTHS ENDED MARCH 31, 2011 AND 2010

NOTE 1 — ORGANIZATION

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

The unaudited condensed consolidated financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States (“US GAAP”) applicable to interim financial statements and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods.  Such financial statements conform to the presentation reflected in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 (“2010 10-K”) filed with the Securities and Exchange Commission (the “SEC”). The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Note 2 “Significant Accounting Policies,” included in the Company’s 2010 10-K.

The results of operations for the three months ended March 31, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. All significant intercompany transactions have been eliminated.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Oil and Gas Properties

The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, internal costs directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $48,573 of internal costs during the three months ended March 31, 2011 and none of these costs during the three months ended March 31, 2010. Additionally, the Company capitalized stock compensation expense related to its drilling consultants as further described in Note 6 “Stock-Based Compensation” herein. Costs associated with production and general corporate activities are expensed in the period incurred. During April 2010, the Company began charging a marketing fee related to the sale of its natural gas production to the wells in which it is the operator and, therefore, the net income attributable to the

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outside working interest owners from the marketing activities of $37,994 was recorded as a credit to proved properties during the three months ended March 31, 2011. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to a cost center.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development costs to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties of $35,946,155 as of March 31, 2011 are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment.

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

Under the full cost method of accounting, the ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs exceed this ceiling limitation. The present value of estimated future net revenues is computed by applying the average, first-day-of—the-month oil and gas price during the 12-month period ended March 31, 2011 for the 12-month period ended March 31, 2011 to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions.

Facilities and Equipment

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

The Company’s other oil and gas equipment is depreciated using the straight-line method over an estimated useful life of five to ten years for the equipment and twenty five years for the evaporative facilities, which were sold in February 2010. The rental of the equipment owned by the Company is charged to the wells that are operated by the Company and, therefore, the net expense attributable to the outside working interest owners

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from the equipment rental of $33,165 and $26,310 was recorded as an adjustment to proved properties during the three months ended March 31, 2011 and 2010, respectively. See Note 3 “Asset Sales” herein.

Derivatives

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The Company records all commodity derivative instruments at fair value within the accompanying unaudited condensed consolidated balance sheets. Changes in fair value are currently recognized in earnings unless specific hedge accounting criteria are met. The Company’s management has decided not to use hedge accounting under the accounting guidance for its commodity derivatives and therefore, the changes in fair value are recognized currently in earnings.

Asset Retirement Obligation

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

The information below reconciles the value of the asset retirement obligation for the periods presented.

Off Balance Sheet Arrangements

From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of March 31, 2011, the off-balance sheet arrangements and transactions that the Company had entered into include undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

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Computation of Net Income (Loss) Per Share

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

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

Net income (loss) per share information is determined using the two-class method, which includes the weighted-average number of common shares outstanding during the period and other securities that participate in dividends (“participating security”). The Company considers the Preferred Stock to be a participating security because it includes rights to participate in dividends with the common stock. In applying the two-class method, earnings are allocated to both common stock shares and the Preferred Stock common stock equivalent shares based on their respective weighted-average shares outstanding for the period. Losses are not allocated to Preferred Stock shares. The table below sets forth the computations of basic and diluted net income (loss) per share for the three months ended March 31, 2011 and 2010.

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

Use of Estimates

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

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

Reclassifications

Certain reclassifications have been made to prior years’ amounts to conform to the classifications used in the current year. Such reclassifications had no effect on the Company’s net income for the period presented.

Recently Issued Accounting Pronouncements

Effective January 1, 2011, the Company adopted ASC guidance that requires enhanced disclosure detail in the level 3 reconciliation for fair value measurements. The adoption had no impact on the Company’s consolidated

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financial position, results of operations or cash flows. Refer to Note 8 “Fair Value Measurement” herein for further details regarding the Company’s assets and liabilities measured at fair value.

NOTE 3 — ASSET SALES

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

Pursuant to the Purchase Agreement, simultaneous with Closing, Gasco entered into the following contracts with Monarch: (i) a transition services agreement pursuant to which the Company agreed to provide certain services relating to the operation of the acquired assets to Monarch for a six-month term commencing at Closing; (ii) a gas gathering agreement pursuant to which the Company agreed to dedicate its natural gas production from all of its Utah acreage for a minimum fifteen-year period and Monarch agreed to provide gathering, compression and processing services to the Company utilizing the gathering system; and (iii) a salt water disposal services agreement pursuant to which Monarch agreed that the Company may deliver salt water produced by its operations to the evaporative facilities for a minimum fifteen-year period.

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

The following unaudited pro forma information is presented as if the Asset Sale had an effective date of January 1, 2010.

NOTE 4 - CONVERTIBLE SENIOR NOTES

As of March 31, 2011, the Company had $400,000 aggregate principal amount of 2011 Notes and $45,168,000 aggregate principal amount of 2015 Notes outstanding.

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2011 Notes

The 2011 Note are governed by an indenture, dated as of October 20, 2004, by and between the Company and Wells Fargo Bank, National Association, as trustee (the “2011 Indenture”). The 2011 Notes were issued on October 20, 2004 and have a maturity date of October 5, 2011.

The 2011 Notes bear interest at a rate of 5.50% per annum, and such interest is payable in cash semi-annually in arrears on April 5th and October 5th of each year.

The 2011 Notes are convertible into shares of common stock at any time prior to maturity at a conversion rate of 250 shares of common stock per $1,000 principal amount of 2011 Notes, which is subject to certain anti-dilution adjustments.

The Company, at its option, may at any time in whole, and from time to time in part, redeem the 2011 Notes on not less than 20 nor more than 60 days’ prior notice mailed to the holders of the 2011 Notes, at a redemption price equal to 100% of the principal amount of 2011 Notes to be redeemed plus any accrued and unpaid interest to but not including the redemption date, if the closing price of the common stock has exceeded 130% of the conversion price for at least 20 trading days in any consecutive 30 trading-day period.

Upon a “change of control” (as defined in the 2011 Indenture), each holder of 2011 Notes can require the Company to repurchase all of that holder’s notes 45 days after the Company gives notice of the change of control, at a repurchase price equal to 100% of the principal amount of 2011 Notes to be repurchased plus accrued and unpaid interest to, but not including, the repurchase date, plus a make-whole premium under certain circumstances described in the 2011 Indenture.

2015 Notes

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

The 2015 Notes bear interest at a rate of 5.50% per annum, and such interest is payable in cash semi-annually in arrears on April 5th and October 5th of each year.

The 2015 Notes are convertible, at the option of the holder, at any time prior to maturity, into shares of common stock or, at the election of such holder, into Preferred Stock. The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the 2015 Indenture, a holder may not convert all or any portion of such holder’s 2015 Notes into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion, beneficially own more than 4.99% of the outstanding shares of common stock (the “Maximum Ownership Percentage”), provided that such holder, upon not less than 61 days’ prior written notice to the Company, may increase the Maximum Ownership Percentage applicable to such holder (but, for the avoidance of doubt, not for any subsequent or other holder) to 9.9% of the outstanding shares of common stock.

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

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

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

The 2015 Notes are unsecured and unsubordinated and rank on a parity in right of payment with all of the Company’s existing and future senior unsecured indebtedness (including outstanding 2011 Notes), rank senior in right of payment to any of the Company’s existing and future subordinated indebtedness, and are effectively subordinated in right of payment to any of the Company’s secured indebtedness or other obligations to the extent of the value of the assets securing such indebtedness or other obligations. The Company’s subsidiaries guarantee the 2015 Notes pursuant to a Guaranty Agreement dated as of June 25, 2010, by and among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of the Trustee.

The debt discount that was recognized in connection with the 2015 Notes is being accreted to interest expense under the effective interest method at a rate of 26.3%.

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NOTE 5 — DERIVATIVES

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The following table details the fair value of the derivatives recorded in the consolidated balance sheets:

As of March 31, 2011, natural gas derivative instruments consisted of one swap agreement for natural gas production through December 31, 2011 and one collar agreement for production from January 1, 2012 through December 31, 2012. As of December 31, 2010, natural gas derivative instruments consisted of two swap agreements for the gas production through March 2011. These natural gas derivative instruments allow the Company to predict with greater certainty the effective natural gas prices to be realized for its production. The Company’s derivative contracts are described below:

·                  For its swap instrument, the Company receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

·                  The Company’s costless collar contains a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Gasco receives the fixed put or call price and pays the market price. If the market price is between the call and the put strike prices, no payments are due from either party.

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three months ended March 31, 2011 and 2010.

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

The Company’s swap agreement as of March 31, 2011 is summarized in the table below:

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

The Company’s costless collar agreement as of March 31, 2011 is summarized in the table below:

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

NOTE 6 — STOCK-BASED COMPENSATION

The Company has outstanding common stock options and restricted stock issued under its equity incentive plans. The Company measures the fair value at the grant date for stock option grants and restricted stock awards and records compensation expense over the requisite service period. The expense recognized over the service period includes an estimate of the awards that will be forfeited.  The Company assumes no forfeitures for employee awards based on the Company’s historical forfeiture experience. The fair value of stock options is calculated using the Black-Scholes option-pricing model and the fair value of restricted stock is based on the fair value of the stock on the date of grant.

The Company accounts for stock compensation arrangements with non-employees using a fair value approach. Under this approach, the stock compensation related to the unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair value on that date. During the three months ended March 31, 2011 and 2010, the Company recognized stock-based compensation as follows:

Stock Options

The following table summarizes the stock option activity in the equity incentive plans from January 1, 2011 through March 31, 2011:

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During the year ended December 31, 2010, the Company granted 1,371,000 options to purchase 50,000, 175,000, 646,000 and 500,000 shares of common stock with exercise prices of $0.34, $0.35, $0.36 and $0.37 per share, respectively. These options have a one- or two-year vesting period and expire within five years of the grant date. These options were granted contingent on stockholder approval of a new stock option plan, which will be included in the proposals at the Company’s annual meeting of stockholders during 2011 and may not be exercised until approval is received. Therefore these options are accounted for as liability awards until stockholder approval is obtained. A share-based compensation liability of $81,181 is included in current accrued liabilities in the accompanying consolidated balance sheet as of March 31, 2011.

The following table summarizes information related to the outstanding and vested options as of March 31, 2011:

The aggregate intrinsic value in the table above represents the total pretax intrinsic value, which is the amount by which the fair value of the Company’s stock at March 31, 2011 of $0.47 exceeds the exercise price of certain outstanding options.

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

As of March 31, 2011, there is $548,459 of total unrecognized compensation cost related to non-vested options granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 1.7 years.

Restricted Stock

The following table summarizes the restricted stock activity from January 1, 2011 through March 31, 2011:

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As of March 31, 2011, there is $89,258 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a period of 2.7 years.

NOTE 7 — CREDIT FACILITY

The Company’s $250 million revolving credit facility (“Credit Facility”) is available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes. In May 2011, the Company completed its semi-annual re-determination of its borrowing base under the Credit Facility, and as a result, effective May 9, 2011, the borrowing base was decreased from $16 million to $15 million. As of March 31, 2011, there were loans in the amount of $7,544,969 and letters of credit in the amount of $25,195 outstanding under the Credit Facility. During April 2011, the Company borrowed an additional $1 million which increased outstanding loans to $8,544,969. As of May 10, 2011, the unused borrowing base is approximately $6.4 million.

Borrowings made under the Credit Facility are secured by a pledge of the capital stock of certain of the Company’s subsidiaries and mortgages on substantially all of the Company’s oil and gas properties. Interest on borrowings is payable monthly and principal is due at maturity on March 26, 2012.

Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate (“ABR”). The Eurodollar rate is calculated as LIBOR plus an applicable margin that, as amended, varies from 2.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 3.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The ABR, as amended, is equal to the sum of (i) the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50% and (c) the Adjusted LIBOR for a one month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 2.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The Company elects the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the Lenders may require the Company to use the non-elected basis in the event that the elected basis does not adequately and fairly reflect the cost of making such loans. The interest rate on our Credit Facility is 4.8% as of March 31, 2011.

The Credit Facility requires the Company to comply with financial covenants that require it to maintain (1) a current ratio (defined as current assets plus unused availability under the Credit Facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1.0; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Facility) for the most recent four quarters not to be greater than 3.5:1.0 for each fiscal quarter.  In addition, the Credit Facility contains covenants that restrict the Company’s ability to incur other indebtedness, create liens or sell the Company’s assets, pay dividends on the Company’s common stock and make certain investments. Sustained or lower oil and natural gas prices could reduce the Company’s consolidated EBITDAX and thus

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could reduce the Company’s ability to maintain existing levels of bank debt or incur additional indebtedness. Any failure to be in compliance with any material provision or covenant of the Credit Facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under the Credit Facility.  Additionally, should the Company’s obligation to repay indebtedness under the Credit Facility be accelerated, the Company would be in default under the indentures governing the Convertible Senior Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such Convertible Senior Notes.  To the extent it becomes necessary to address any anticipated covenant compliance issues, the Company will seek to obtain a waiver or amendment of the Credit Facility from the Lenders, and in the event that such waiver or amendment is not granted, the Company may be required to sell a portion of its assets or issue additional securities, which would be dilutive to the Company’s stockholders.  Any sale of assets or issuance of additional securities may not be on terms acceptable to the Company.

As of March 31 2011, the Company’s current and senior debt to EBITDAX ratios are 2.3:1.0 and 1.0:1.0, respectively, and the Company is in compliance with each of the covenants contained in the Credit Facility.

NOTE 8 — FAIR VALUE MEASUREMENTS

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

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

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

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

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

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2011 and December 31, 2010 by level within the fair value hierarchy:

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As of March 3, 2011, the Company’s commodity derivative financial instruments are comprised of one natural gas swap agreement and one costless collar agreement. The fair values of the swap and collar agreements are determined based primarily on inputs that are derived from observable data at commonly quoted intervals for the full term of the derivatives and are, therefore, considered level 2 in the fair value hierarchy. The Company determines the fair value of these swap contracts under the income valuation technique using a discounted cash flows model for the swap and option pricing model for the collar. The valuation models require a variety of inputs, including contractual terms, projected gas market prices, discount rate and credit risk adjustments, as appropriate. The Company has consistently applied this valuation technique in all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds. The counterparty in all of the Company’s commodity derivative financial instruments is the Administrative Agent under the Credit Agreement. See Note 6 “Credit Facility” herein.

Other financial instruments not measured at fair value on a recurring basis include cash and cash equivalents, accounts receivable, note receivable, accounts payable, accrued liabilities, 2011 Notes, 2015 Notes and long-term debt. With the exception of the note receivable and 2015 Notes the financial statement carrying amounts of these items approximate their fair values due to their short-term nature. The carrying amount of the Company’s note receivable approximates fair value based on current interest rates for similar instruments. The estimated fair value of the 2015 Notes of $39,597,566 and $31,766,000 as of March 31, 2011 and December 31, 2010, respectively, was determined using a discounted cash flow and option pricing model.

NOTE 9 - STATEMENTS OF CASH FLOWS

During the three months ended March 31, 2011, the Company’s non-cash investing and financing activities consisted of the following transactions:

·                  Stock-based compensation expense of $868 capitalized as proved property.

·      Conversion of 34,600 shares of Preferred Stock into 5,766,667 shares of common stock.

·                  Additions to oil and gas properties included in accounts payable of $547,301.

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

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

·                  Stock-based compensation expense reduction of $1,860 capitalized as proved property.

·                  Additions to oil and gas properties included in accounts payable of $48,072.

·                  Recognition of deferred income of $3,036,794 in connection with Asset Sale described in Note 3 “Asset Sales” herein.

Cash paid for interest during the three months ended March 31, 2011 and 2010 was $68,741 and $283,145, respectively. There was no cash paid for income taxes during the three months ended March 31, 2011 and 2010.

NOTE 10 — LEGAL PROCEEDINGS

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

EPA Enforcement Action

On June 22, 2007, Riverbend Gas Gathering, LLC (“Riverbend”) voluntarily notified the United States Environmental Protection Agency (“EPA”) Region 8 office in Denver, Colorado, of its discovery that Riverbend apparently had not obtained certain air permits or complied with certain air pollution regulatory programs applicable to its operations at the Riverbend Compressor Station in Uintah County, Utah.  Subsequent to this notice and negotiations on the matter, Riverbend and the EPA entered into a consent decree that was lodged in the United States District Court of the District of Utah on December 30, 2010.  The consent decree resolves the apparent violations, requires Gasco to pay a civil penalty of $350,000, which was paid on May 5, 2011, specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that will authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented.  The consent decree was approved and entered by the reviewing court on April 6, 2011.

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

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NOTE 11 — GUARANTOR SUBSIDIARIES

On August 22, 2008, Gasco filed a Form S-3 shelf registration statement with the SEC. Under this registration statement, which was declared effective on September 8, 2008, Gasco may from time to time offer and sell securities including common stock, preferred stock, depositary shares and debt securities that may be fully, irrevocably and unconditionally guaranteed by all of its subsidiaries:  Gasco Production Company, Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (collectively, the “Guarantor Subsidiaries”). The stand-alone parent entity, Gasco Energy, Inc., has insignificant independent assets and no operations. Therefore, supplemental financial information on a condensed consolidating basis of the Guarantor Subsidiaries is not required. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries, except those imposed by applicable law.

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ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

We are a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. Our principal business strategy is to enhance stockholder value by using technologies new to a specific area to generate and develop high-potential exploitation resources in these areas. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. We are currently focusing our operational efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.

Recent Developments

Completion Operations

During the first quarter of 2011, we recompleted one (0.3333 net) natural gas well  in the Uinta Basin, Utah. We are on schedule to commence drilling operations on two wells to test the productive potential of the Green River Formation, a shallow, oil-bearing reservoir system that we believe is prospective across approximately 11,000 net acres of our Uinta Basin leasehold. The spud date for the first well is projected for May 2011, with production results from both wells expected during the third quarter of 2011.

As of March 31, 2011, we operated 133 gross wells and we currently have an inventory of 19 operated wells with up-hole recompletions and on Upper Mancos well awaiting initial completion activities.

We do not have a drilling rig under contract at this time, as was the case for all of 2010. We are in the process of contracting a drilling rig for use in the upcoming two-well Green River Oil well program.

California Projects

Northwest McKittrick. The operator of this shallow oil prospect continues to work with the California State Agencies to acquire the appropriate permits.  Progress has been slowed due to California state budget issues and forced furloughs affecting the regulatory agencies.  Despite the delays, the operator anticipates that it will commence drilling operations during the second or third quarter of 2011.

Willow Springs. The operator of this oil prospect has been analyzing recently acquired 3-D seismic data and is currently high-grading drillable locations based upon the ongoing 3-D interpretation. Our understanding is that the project is on schedule to have an initial well drilled by year-end 2011.

Antelope Valley Trend. The operator of these oil and liquids-rich prospects is in the process of shooting 3-D seismic over the Antelope Valley prospects.  Drilling on the trend is anticipated to begin in 2012.

San Joaquin Basin. We continue to develop new prospects and acquire acreage along the west side of the San Joaquin Basin.  The new prospects are a continuation of the structural and stratigraphic geologic model that we have been working for the past nine years that has yielded recent success along the west side as demonstrated by discoveries and field development by other operators with similar geologic models.

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Resignation of Former Chief Executive Officer; Appointment of Replacement

Effective January 1, 2011, our previously announced plan of succession for changes in management was completed.  Charles B. Crowell resigned as our interim Chief Executive Officer and W. King Grant, who was then serving as our President and Chief Financial Officer, assumed the role of Chief Executive Officer.  At that time, Mr. Grant resigned from his position as Chief Financial Officer, but maintained his position as our President. Ms. Peggy Herald, Vice President and Treasurer, is our principal financial officer. Mr. Crowell continues to serve as Chairman of the Board of Directors and Mr. Grant continues to serve as a member of the Board of Directors.

Oil and Gas Production Summary

The following table presents our production and price information during the three months ended March 31, 2011 and 2010. The Mcfe calculations assume a conversion of six Mcf for each Bbl of oil.

Our equivalent oil and gas production decreased by 4% during the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 primarily due to normal production declines on our existing wells which were partially offset by the new production from our recompletion projects during 2010 and the first quarter of 2011.

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities or asset sales, availability under our Credit Facility, and access to capital markets, to the extent available. During May 2011 we completed the semi-annual re-determination of our borrowing base under Credit Facility and as a result, our borrowing base was decreased to $15 million from the previously available $16 million. As of May 10, 2011, we have approximately $8.6 million aggregate amount of outstanding borrowings (including $25,195 of outstanding letters of credit) thereunder. Our Credit Facility provides for periodic and special borrowing base redeterminations which could affect our available borrowing base and our lenders may further reduce our borrowing base in the future. Our inability to access additional borrowings in excess of our $6.4 million of current existing capacity under our Credit Facility may limit our ability to increase our operating budget and execute on our growth plans.

We continually evaluate our capital needs and compare them to our capital resources and ability to raise funds in the financial markets. We adjust capital expenditures in response to changes in natural gas and oil prices, drilling results and cash flow. If we need additional liquidity for future activities, including paying amounts

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

As of March 31, 2011 we had negative working capital of approximately $8.1million primarily due to the approximately $7.6 million aggregate amount of borrowings outstanding under our Credit Facility at such time, which is now a current liability due March 26, 2012, and $400,000 related to the 2011 Notes that will be settled in October 2011. The 2011 Notes will be settled in October 2011 and we are currently working with our lenders to extend the maturity date of our Credit Facility.

Sources and Uses of Funds

The following table summarizes our sources and uses of cash for each of the three months ended March 31, 2011 and 2010.

Cash provided by operations decreased by $223,058 from March 31, 2010 to March 31, 2011.  The decrease in cash provided by operations was primarily due to the lower gas revenue attributable to a 26% reduction in gas prices during the first quarter of 2011.

Our investing activities during the first quarter of 2011 included our development and exploration activities, fixed asset additions and the change in advances from joint interest owners. The investing activity during the first quarter of 2010 was comprised of the sales proceeds of $24,250,000 associated primarily with the sale of our gathering and evaporative facilities (see Note 3 “Asset Sales” of the accompanying unaudited condensed consolidated financial statements), the sale of a partial working interest in 32 producing wells and the development and exploration activities, fixed asset additions and the change in advances from joint interest owners.

The financing activity during the first quarter of 2011 included $1.0 million in borrowings under our Credit Facility and the payment of $65,000 in costs associated with the issuance of our 2015 Notes. The financing activity during the first quarter of 2010 was comprised of $29.0 million in repayments of borrowings on our Credit Facility and the payment of a deposit of $500,000 in connection with our new gathering agreement in February 2010.

Capital Budget

Our Board of Directors approved an initial capital expenditure budget of $6.0 million for our 2011 oil and gas activities. In the Uinta Basin, we allocated approximately $2.4 million for our continued up-hole recompletion program targeting natural gas and an additional $1.6 million for the drilling and completion of two Green River Formation oil wells. A significant portion of the remaining $2.0 million budget may be allocated to additional investments in existing and new California oil and gas prospects in the San Joaquin Basin. Our budget will be

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funded primarily from cash on hand, cash flow from operations and borrowings under our Credit Facility, and will be subject to market conditions, drilling results, oilfield service availability and commodity prices.

Results of Operations

The First Quarter of 2011 Compared to the First Quarter of 2010

Oil and Gas Revenue and Production

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

The decrease in oil and gas revenue of $1,516,488 during the first quarter of 2011 compared with the first quarter of 2010 was comprised of a $1.40 per Mcf decrease in the average gas prices and a 4% decrease in equivalent production partially offset by an increase in the average oil prices of $10.27 per Bbl. The decrease in equivalent oil and gas production was primarily due to normal production declines on our existing wells partially offset by the new production from recompletion projects during 2010 and the first quarter of 2011. The $1,146,026 decrease in oil and gas revenue during the first quarter of 2011 represents a decrease of $1,204,643 related to the net decrease in oil and gas prices and a decrease of $311,845 related to the equivalent production increase.

Gathering Revenue and Expenses

Gathering revenue and expense during 2010 represented the income earned from the third-party working interest owners in the wells we operated (our share of gathering revenue was eliminated against the transportation expense included in our lease operating costs) and the expenses incurred from our gathering system in the Riverbend area that we constructed during 2004 and 2005. We sold our gathering system in February 2010, as described in Note 3 “Asset Sales” of the accompanying unaudited condensed consolidated financial statements, which eliminated these revenue and expenses after February 2010.

Lease Operating Expenses

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

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Lease operating expense increased $399,244 during the first quarter of 2011 compared with the first quarter of 2010. The increase is comprised of a $345,025 increase in operating expenses and a $54,219 increase in production taxes primarily due to the expiration of certain tax benefits during the first quarter of 2011.  The increase in operating expenses was primarily due to a $279,955 increase in workover expenses attributable to the increased number of workover projects during the first quarter of 2011.

Transportation and Processing

Transportation and processing costs of $801,715 ($0.84 per Mcfe) and $239,255 ($0.24 per Mcfe) as of March 31, 2011 and 2010, respectively, represent the costs we incurred to transport the gas production from our wells subsequent to the sale of our gathering system as described in Note 3 “Asset Sales” in the accompanying unaudited condensed consolidated financial statements. The increase of $562,460 in these expenses during the first quarter of 2011 reflects three months of these costs in 2011 versus one month of these costs in 2010 because prior to the sale of our gathering system during February 2010, these intercompany costs were eliminated from revenue and expense.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation and amortization expense during the first quarters of 2011 and 2010 is comprised of depletion expense related to our oil and gas properties, depreciation expense of furniture, fixtures and equipment and accretion expense related to the asset retirement obligation. The decrease of $26,755 during the first quarter of 2011 compared to the first quarter of 2010 was primarily due to the decrease in the depletion rate resulting from the production decrease as described above.

Inventory Loss

The inventory loss during the first quarter of 2010 represents the decrease in the market value of our inventory.

General and Administrative Expense

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

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