Gasco Energy (GSXN) 10-Q 2009 Q1 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

þ QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: March 31, 2009

o TRANSITION REPORT UNDER 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)

Nevada
(State or other jurisdiction of
incorporation or organization) 98-0204105
(IRS Employer
Identification No.)

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

(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 require to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T 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. (Check one):

Large accelerated filer o Accelerated filer þ 
Non-accelerated filer o
(Do not check if a smaller reporting company) Smaller reporting company o

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

Number of common shares outstanding as of May 4, 2009: 107,746,798

TABLE OF CONTENTS

	ITEM I — FINANCIAL STATEMENTS
PART 1 — FINANCIAL INFORMATION
	ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS
	ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	ITEM 4 — CONTROLS AND PROCEDURES
PART II — OTHER INFORMATION
	Item 1 — Legal Proceedings
	Item 1A — Risk Factors
	Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds
	Item 3 — Defaults Upon Senior Securities
	Item 4 — Submission of Matters to a Vote of Security Holders
	Item 5 — Other Information
	Item 6 — Exhibits
	SIGNATURES
Exhibit Index
EX-31
EX-32

ITEM I — FINANCIAL STATEMENTS

PART 1 — FINANCIAL INFORMATION

GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)

	March 31,			December 31,
	2009			2008
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	9,127,511		$	1,053,216
Accounts receivable
Joint interest billings		3,974,810			5,436,636
Revenue		4,108,034			3,827,950
Inventory		2,384,659			4,177,967
Derivative instruments		9,544,763			8,855,947
Prepaid expenses		109,574			188,810
Total		29,249,351			23,540,526
PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved properties		251,759,503			247,976,854
Unproved properties		39,678,648			39,314,406
Wells in progress		—			644,688
Gathering assets		17,625,895			17,440,680
Facilities and equipment		8,596,580			8,549,928
Furniture, fixtures and other		371,605			371,605
Total		318,032,231			314,298,161
Less accumulated depletion, depreciation, amortization and impairment		(229,200,491	)		(185,585,582	)
Total		88,831,740			128,712,579
OTHER ASSETS
Deposit		139,500			139,500
Deferred financing costs		1,350,609			1,492,903
Total		1,490,109			1,632,403
TOTAL ASSETS	$	119,571,200		$	153,885,508

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

2

GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
(Unaudited)

	March 31,			December 31,
	2009			2008
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	3,149,916		$	5,879,150
Revenue payable		2,133,904			3,840,985
Advances from joint interest owners		352,877			612,222
Accrued interest		1,890,534			1,187,495
Accrued expenses		1,142,000			1,126,000
Total		8,669,231			12,645,852
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes		65,000,000			65,000,000
Long-term debt		44,000,000			31,000,000
Asset retirement obligation		1,176,939			1,150,179
Deferred rent expense		40,080			46,589
Total		110,217,019			97,196,768
STOCKHOLDERS’ EQUITY
Series B Convertible Preferred stock — $0.001 par value; 20,000 shares authorized; zero shares outstanding		—			—
Common stock — $.0001 par value; 300,000,000 shares authorized; 107,833,498 shares issued and 107,759,798 outstanding as of March 31, 2009 and 107,825,998 shares issued and 107,752,298 outstanding as of December 31, 2008		10,783			10,783
Additional paid-in capital		219,882,677			219,375,369
Accumulated deficit		(219,078,215	)		(175,212,969	)
Less cost of treasury stock of 73,700 common shares		(130,295	)		(130,295	)
Total		684,950			44,042,888
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	119,571,200		$	153,885,508

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

3

GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
REVENUES
Gas	$	3,911,051		$	7,897,480
Oil		260,971			587,637
Gathering		875,201			908,356
Rental income		366,399			362,250
Total		5,413,622			9,755,723
OPERATING EXPENSES
Lease operating		691,937			1,266,727
Gathering operations		707,514			656,499
Depletion, depreciation, amortization and accretion		2,582,970			2,449,802
Impairment		41,000,000			—
Inventory loss		121,000			—
Contract termination fee		4,701,000			—
General and administrative		1,860,046			2,188,033
Total		51,664,467			6,561,061
OTHER INCOME (EXPENSE)
Interest expense		(1,158,729	)		(1,247,549	)
Derivative gains (losses)		3,542,626			(6,372,452	)
Interest income		1,702			15,222
Total		2,385,599			(7,604,779	)
NET LOSS	$	(43,865,246	)	$	(4,410,117	)
NET LOSS PER COMMON SHARE — BASIC AND DILUTED	$	(0.41	)	$	(0.04	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING — BASIC AND DILUTED		107,519,292			106,903,548

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

4

GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(43,865,246	)	$	(4,410,117	)
Adjustment to reconcile net loss to net cash provided by operating activities
Depletion, depreciation, amortization and impairment expense		43,556,435			2,426,412
Accretion of asset retirement obligation		26,535			23,390
Stock-based compensation		505,317			721,260
Unrealized derivative (gain) loss		(688,816	)		5,933,182
Amortization of deferred rent expense		(6,509	)		(3,755	)
Amortization of deferred financing costs		142,294			129,558
Inventory loss		121,000			—
Changes in operating assets and liabilities:
Accounts receivable		1,181,742			235,918
Inventory		1,672,308			(1,268,003	)
Prepaid expenses		79,236			107,931
Accounts payable		631,066			(1,269,339	)
Revenue payable		(1,707,081	)		1,379,604
Accrued interest		703,039			916,500
Accrued expenses		16,000			(96,000	)
Net cash provided by operating activities		2,367,320			4,826,541
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		—			(10,473	)
Cash paid for acquisitions, development and exploration		(7,033,680	)		(8,336,355	)
Advances from joint interest owners		(259,345	)		1,052,696
Net cash used in investing activities		(7,293,025	)		(7,294,132	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit		13,000,000			12,000,000
Repayment of borrowings		—			(9,000,000	)
Exercise of options to purchase common stock		—			36,498
Net cash provided by financing activities		13,000,000			3,036,498
NET INCREASE IN CASH AND CASH EQUIVALENTS		8,074,295			568,907
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD		1,053,216			1,843,425
END OF PERIOD	$	9,127,511		$	2,412,332

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

5

GASCO ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
THREE MONTHS ENDED MARCH 31, 2009 AND 2008
(Unaudited)

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 using technologies new to a specific area to generate and develop high-potential exploitation resources in this area. The Company’s principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. The Company is currently focusing its drilling efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.

The unaudited financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States 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 filed with the Securities and Exchange Commission (the “SEC”) for the year ended December 31, 2008. The current interim period reported herein should be read in conjunction with the financial statements and summary of significant accounting policies and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.

The Company’s credit agreement provides for periodic borrowing base redeterminations which impact the available borrowing base of the Company. See Note 4 for discussion of the current status of the credit agreement and how it affects the Company’s liquidity.

The results of operations for the three months ended March 31, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009. All significant intercompany transactions have been eliminated.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying consolidated financial statements include Gasco and its wholly-owned subsidiaries.

6

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 $18,635 and $19,538 of internal costs during the three months ended March 31, 2009 and 2008, respectively. Additionally, the Company capitalized stock compensation expense related to its drilling consultants as further described in Note 3. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include: (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion; (b) estimated future development costs to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties of $39,678,648 as of March 31, 2009 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, capitalized oil and gas property costs less accumulated depletion (“full cost pool”) and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued in the balance sheet plus the cost, or estimated fair value if lower of unproved properties and the costs of any properties not being amortized, if any, net of income taxes (“ceiling limitation”). Should the full cost pool exceed this ceiling limitation, an impairment is recognized. The present value of estimated future net revenues is computed by applying current oil and gas prices to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. However, subsequent commodity price increases may be utilized to calculate the ceiling value.

7

As of March 31, 2009, the Company’s full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf by $41,000,000. Therefore, impairment expense of $41,000,000 was recorded during the quarter ended March 31, 2009.

Wells in Progress

Wells in progress at December 31, 2008 represented the costs associated with the drilling of one well in the Riverbend area of Utah. Since the well had not reached total depth as of December 31, 2008, it was classified as wells in progress and was withheld from the depletion calculation and the ceiling test. The costs for this well were transferred into proved property during the first quarter of 2009 and became subject to depletion and the ceiling test.

Facilities and Equipment

The Company constructed four evaporation pits in the Riverbend area of Utah to be used for the disposal of produced water from the wells that Gasco operates in the area. The pits are being depreciated using the straight-line method over their estimated useful life of twenty-five years. The costs of water disposal into the evaporation pits are charged to wells operated by Gasco and therefore, revenue, net of direct costs, attributable to the outside working interest owners from the evaporation pits of $1,881 and $181,960 was recorded as a credit to proved properties during the three months ended March 31, 2009 and 2008, respectively.

The Company’s other oil and gas equipment is depreciated using the straight-line method over the estimated useful life of five to ten years for the equipment, twenty years for the drilling rig and twenty five years for the facilities. The rental of the equipment owned by Gasco is charged to the wells that are operated by Gasco, and therefore the net revenue attributable to the outside working interest owners from the equipment rental of $42,435 and $177,475 was recorded as a credit to proved properties during the three months ended March 31, 2009 and 2008, respectively.

Forward Sales Contract

For 2008 and 2009 production, the Company entered into a firm sales and transportation agreement to sell 30,000 MMBtu. per day of its gross production from the Uinta Basin. During the first quarter of 2008, 18,000 MMBtu. per day of such amount was contracted at the CIG first of month price and the remaining 12,000 MMBtu. per day was priced at the NW Rockies first of month price. Beginning in the second quarter of 2008, the entire contracted amount was based on NW Rockies first of month price.

During April 2009 the Company entered into another firm sales and transportation agreement to sell up to 50,000 MMBtu. per day of its 2010 and 2011 gross production from the Uinta Basin. The contract contains two pricing mechanisms: (1) up to 25,000 MMBtu. per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu. per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price.

8

The Company has elected the normal purchase and sale exemption under paragraph 10(b) of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” because the Company anticipates that (1) it will produce the volumes required to be delivered under the terms of the contracts, (2) it is probable the delivery will be made to the counterparty and (3) the counterparty will fulfill its contractual obligations under the terms of the contracts. As such, the Company believes that it is not required to treat the contracts as derivatives and the contracts will not be marked to market under the provisions of SFAS No. 133.

Derivatives

The Company uses 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 accounts for its derivatives and hedging activities under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133, the Company is required to record its derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in current earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. Management has decided not to use hedge accounting for its derivatives. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair value are recognized in earnings.

As of March 31, 2009 and December 31, 2008, natural gas derivative instruments consisted of two swap agreements and one costless collar agreement for 2009 production. The fair value of the agreements was a current asset of $9,544,763 as of March 31, 2009 and a current asset of $8,855,947 as of December 31, 2008. These assets are recorded in the accompanying consolidated balance sheet as Current Derivative Instruments. During April 2009 the Company entered into an additional swap agreement for production during 2010 and through the first quarter of 2011. These instruments allow the Company to predict with greater certainty the effective natural gas prices to be received for its production. The Company’s derivative contracts are described below:

• For its swap instruments, 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 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 its derivative instruments for the first quarter of 2008 and 2009.

9

	Three Months Ended March 31,
	2009		2008
Realized gains (losses) on derivative instruments	$	2,853,810	$	(439,270	)
Unrealized gains (losses) on derivative instruments		688,816		(5,933,182	)
Total realized and unrealized gains (losses) recorded	$	3,542,626	$	(6,372,452	)

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

The Company’s swap agreements for 2009 through March 2011 are summarized in the table below:

	Remaining			Fixed Price	Floating Price (a)
Agreement Type	Term		Quantity	Counterparty payer	Gasco payer
Swap		4/09 — 12/09	3,000 MMBtu./day	$7.025/MMBtu.	NW Rockies
Swap		4/09 — 12/09	3,000 MMBtu./day	$7.015/MMBtu.	NW Rockies
Swap		1/10 — 3/11	3,000 MMBtu./day	$4.825/MMBtu.	NW Rockies

The Company’s costless collar agreement for 2009 is summarized in the table below:

	Remaining			Index	Call Price	Put Price
Agreement Type	Term		Quantity	Price (a)	Counterparty buyer	Gasco buyer
Costless collar		4/09 — 12/09	3,000 MMBtu./day	NW Rockies	$7.50/MMBtu.	$6.50/MMBtu.

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

Concentrations of Credit Risk

The Company sells the majority of its gas production to a single purchaser. The Company continually monitors the credit worthiness of its purchasers and does not anticipate nonperformance by its current purchasers.

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

Asset Retirement Obligation

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

10

equipment and site restoration on its oil and gas properties and gathering assets. The asset retirement liability is allocated to operating expense using a systematic and rational method. The information below reconciles the value of the asset retirement obligation for the periods presented.

	Three Months Ended
	March 31,
	2009		2008
Balance beginning of period	$	1,150,179	$	1,030,283
Liabilities incurred		225		10,245
Liabilities settled		—		(10,179	)
Accretion expense		26,535		23,390
Balance end of period	$	1,176,939	$	1,053,739

Contract Termination Fee

During February 2009, the Company released its remaining drilling rig and paid the rig contractor $4,701,000 for early termination of the drilling contract, as calculated at $12,000 per day from the rig release date through March 15, 2010, the expiration date of the contract. Upon the Company’s payment of this fee, the letter of credit in the amount of $6,564,000 for the benefit of the rig contractor was released by the Company’s lenders.

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, 2009, the off-balance sheet arrangements and transactions that the Company has entered into include undrawn letters of credit, operating lease agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

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 basic net income (loss) per share only after the shares become fully vested. Diluted net income per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of the options to acquire common stock computed using the treasury stock method which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period). The 5.50% Convertible Senior Notes due 2011 issued on October 20, 2004 (the “Convertible Notes”) and the outstanding common stock options have been excluded from the computation of diluted net income (loss) per share for all periods presented because their inclusion would have been anti-dilutive. As of

11

March 31, 2009, common stock equivalents of 27,279,237 have been excluded from the computation of diluted net income (loss) per share, including 16,250,000 shares of common stock that would have been issued upon conversion of the Convertible Notes.

Use of Estimates

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

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

Reclassifications

Advances from joint interest owners net in 2008 have been reclassified to investing activities in the accompanying consolidated statement of cash flows. Derivative gains (losses) and interest income in 2008 have been reclassified from revenues to other income (expense) and interest expense has been reclassified from operating expenses to other income (expense) to be consistent with the 2009 presentation. The following table summarizes the reclassification of these items within the consolidated statements of operations and cash flows for the three months ended March 31, 2008:

	Three Months
	Ended						Three Months
	March 31, 2008						Ended March 31,
	(Previously						2008
	Reported)			Reclassification			(As Reclassified)
Total revenues	$	3,398,493		$	6,357,230		$	9,755,723
Total operating expenses		7,808,610			1,247,549			6,561,061
Other income (expense)		—			(7,604,779	)		(7,604,779	)
Net cash provided by operating activities		5,879,237			(1,052,696	)		4,826,541
Net cash (used in) provided by investing activities		(8,346,828	)		1,052,696			(7,294,132	)

Recently Issued Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements.” This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure related to the use of fair value measures in financial statements. In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1, “Application of FASB

12

Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active”, which clarified the application of SFAS No. 157 as it relates to the valuation of financial assets in a market that is not active for those financial assets.

On January 1, 2008, the Company adopted the provision of SFAS No. 157 related to financial assets and liabilities measured at fair value on a recurring basis. The Company also adopted FSP FAS 157-1 and FSP FAS 157-3 in 2008. The adoption of these FSPs did not have a material impact on the Company’s financial position or results of operations.

On January 1, 2009, the Company adopted the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include, among others, those nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. Fair value used in the initial recognition of asset retirement obligations is determined based on the present value of expected future dismantlement costs incorporating our estimate of inputs used by industry participants when valuing similar liabilities. Accordingly, the fair value is based on unobservable pricing inputs and therefore, is considered a level 3 value input in the fair value hierarchy (Note 5). The adoption of SFAS No. 157 related to these items did not have a material impact on the Company’s financial position or results of operations.

On April 9, 2009, the FASB issued three FSPs: FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions that are not Orderly,” FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-than- temporary Impairments,” and FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” The objectives of these FSPs are to: (1) provide additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased, including guidance on identifying circumstances that indicate a transaction is not orderly; (2) amend the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements and (3) require disclosures about fair value of financial instruments for interim reporting periods for publicly traded companies as well as in annual financial statements. These three FSP’s are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the provisions of these FSP’s for the period ending March 31, 2009. The adoption of these FSP’s did not have a material impact on the Company’s financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree

13

and the goodwill acquired, and establishes that acquisition costs will be generally expensed as incurred. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. On April 1, 2009 the FASB issued FSP FAS 141R-1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP FAS 141R-1”). This FSP amends and clarifies SFAS No. 141R to address application issues related to initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The Company adopted SFAS No. 141R on January 1, 2009. The adoption of SFAS No. 141R did not have a material impact on the Company’s consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” which amends SFAS No. 133 by requiring expanded disclosures about an entity’s derivative instruments and hedging activities, but does not change SFAS No. 133’s scope or accounting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company adopted SFAS No. 161 on January 1, 2009 and the adoption of SFAS No. 161 did not have an impact on the Company’s financial position or results of operations See Note 2,Derivativesfor required disclosures.

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

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

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

14

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

Many of the Company’s financial reporting disclosures could change as a result of the new rules.

NOTE 3 — STOCK-BASED COMPENSATION

The Company has outstanding common stock options and restricted stock issued under its equity incentive plans. See Note 3 to the financial statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 for additional information. The Company accounts for stock option grants and restricted stock awards in accordance with SFAS No. 123(R), “Share Based Payment.”

During the three months ended March 31, 2009 and 2008, the Company recognized stock-based compensation as follows:

	Three Months Ended
	March 31,
	2009			2008
Stock-based compensation	$	507,308		$	749,417
Consultant compensation capitalized as proved property		(1,991	)		(28,157	)
Total stock-based compensation expense	$	505,317		$	721,260

The Company accounts for stock compensation arrangements with non-employees in accordance with SFAS No. 123(R) and EITF No. 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services,” using a fair value approach. Under this approach, the stock compensation related to the unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair value on that date. Stock-based non-employee compensation expense for the three months ending March 31, 2009 and 2008 was $4,300 and $62,182, respectively. Of these amounts, $1,991 and $28,157 of compensation expense relating to drilling consultants was capitalized during the three months ended March 31, 2009 and 2008, respectively.

15

Stock Options

The following table summarizes the stock option activity in the equity incentive plans from January 1, 2009 through March 31, 2009:

				Weighted-Average
	Stock Options			Exercise Price
Outstanding at January 1, 2009		11,124,788		$	2.06
Granted		127,083		$	2.51
Exercised		—			—
Forfeited		—			—
Cancelled		(222,634	)	$	4.14
Outstanding at March 31, 2009		11,029,237		$	2.02
Exercisable at March 31, 2009		7,851,097		$	2.12

During the quarter ended March 31, 2009, the Company granted 127,083 options to purchase common stock with exercise prices ranging from $0.22 to $5.69 per share. The weighted average grant-date fair value of the options granted during the three months ended March 31, 2009 was $0.13 per share.

The following table summarizes information related to the outstanding and vested options as of March 31, 2009:

	Outstanding Options		Vested options
Number of shares		11,029,237		7,851,097
Weighted Average Remaining Contractual Life		4.95		4.50
Weighted Average Exercise Price	$	2.02	$	2.12
Aggregate intrinsic value	$	6,800		—

The aggregate intrinsic value in the table above represents the total pretax intrinsic value, which is the amount by which the market value of the Company’s stock at March 31, 2009 of $0.39 exceeds the exercise price of the outstanding options.

The total grant date fair value of the shares vested during the three months ended March 31, 2009 was $1,330,294.

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

As of March 31, 2009, there was $2,754,865 of total unrecognized compensation cost related to non-vested options granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 3.5 years.

16

Restricted Stock

The following table summarizes the restricted stock activity from January 1, 2009 through March 31, 2009:

				Weighted-Average
	Restricted			Grant Date
	Stock			Fair Value
Outstanding at January 1, 2009		233,300		$	2.35
Granted		7,500		$	0.25
Vested		(3,900	)	$	2.11
Forfeited		—			—
Outstanding at March 31, 2009		236,900		$	2.29

As of March 31, 2009, there was $391,758 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 3.5 years.

NOTE 4 — CREDIT FACILITY

On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered into a $250 million Credit Agreement (the “Credit Agreement”) with JPMorgan Chase Bank, N.A., (“JP Morgan”) as Administrative Agent. Borrowings made under the Credit Agreement are guaranteed by the Company’s subsidiaries, and are secured by a pledge of the capital stock of such subsidiaries and mortgages on substantially all of the Company’s oil and gas properties. The Credit Agreement is available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes.

The aggregate commitment of the lenders under the Credit Agreement is $250,000,000, subject to a borrowing base of $45,000,000 as of December 2008. The Credit Agreement also provides for a $10,000,000 sublimit for letters of credit which the Company may use for general corporate purposes. The Credit Agreement was amended in December 2008 to extend the maturity date by one year to March 29, 2011. Additionally, the interest rate pricing grid was increased 0.25% to the levels detailed below and the commitment fee was changed to 0.50% from a variable grid between 0.30% and 0.50%. Guarantee Bank and Trust Company was also added as a Lender to the Credit Agreement and is currently committed for $5.0 million of the $45.0 million borrowing base. The other commercial terms are substantially unchanged. As of March 31, 2009, there were loans of $44,000,000 outstanding at an average interest rate of 3.59% and letters of credit in the amount of $139,000, which are considered usage for purposes of calculating availability and commitment fees. The Company’s aggregate borrowings and outstanding letters of credit under the Credit Agreement may not at any time exceed the borrowing base. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2011.

Interest on borrowings under the Credit Agreement accrues at variable interest rates at either, at the Company’s election, a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies from 1.50% (for periods in which the Company has utilized less than 50% of the borrowing base) to 2.25% (for periods in which the Company has utilized greater than 90% of the borrowing base). The alternate base rate is calculated as (1) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.50% or (c) the adjusted LIBOR Rate for a one month interest period on such day plus 1.00%, plus (2) an applicable margin

17

that varies from 0.25% (for periods in which the Company has utilized less than 50% of the borrowing base) to 1.00% (for periods in which the Company has utilized greater than 90% of the borrowing base). The Company elects the basis of the interest rate at the time of each borrowing; however, under certain circumstances, the lender may require the Company to use the non-elected basis in the event the elected basis does not adequately and fairly reflect the cost of making such loans. In addition, the Company is obligated to pay a commitment fee under the Credit Agreement quarterly in arrears based on 0.50% of unused commitments.

The Credit Agreement 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 Agreement divided by current liabilities excluding the current portion of the Credit Agreement), determined at the end of each quarter, of not less than 1.0:1; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Agreement) for the most recent four quarters not to be greater than 3.5:1 for each fiscal quarter. In addition, the Credit Agreement contains covenants that restrict 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 could reduce the Company’s ability to maintain existing levels of Senior Debt or incur additional indebtedness. Additionally, at current commodity prices, EBITDAX will be reduced for the four quarters beginning with the quarter ended March 31, 2009 by the payment of approximately $4.7 million for early termination of the Company’s drilling contract in February 2009, resulting in a corresponding reduction in the levels of senior debt that the Company may have outstanding going forward without violating its senior debt to EBITDAX ratio. Any failure to be in compliance with any material provision or covenant of the Credit Agreement could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under the Credit Agreement. Additionally, should the Company’s obligation to repay indebtedness under the Credit Agreement be accelerated, the Company would be in default under the indenture governing the 5.50% Convertible Senior Notes due 2011, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes. To the extent it becomes necessary to address any anticipated covenant compliance issues, the Company will seek to obtain a waiver or amendment of the Credit Agreement from the lenders thereunder, and in the event that such waiver or amendment is not granted, the Company may be required to sell a portion of its assets or issue additional securities, which would be dilutive to the Company’s shareholders. Given the condition of current credit and capital markets, any sale of assets or issuance of additional securities may not be on terms acceptable to the Company. As of March 31, 2009, the Company was in compliance with each of the covenants contained in the Credit Agreement.

The Credit Agreement provides for semi-annual evaluation of the borrowing base, which will be determined as a percentage of the discounted present value of the Company’s oil and natural gas reserves. The Company’s expects to be notified of the results from the April 2009 borrowing base redetermination in May 2009 and, based on the decline in commodity prices, the Company believes that it will be reduced. If the Company’s borrowing base is reduced as a result of a redetermination to a level below its then current outstanding borrowings, it will be required to repay the amount by which such outstanding borrowings exceed the borrowing base within 60 days of notification by the lenders, and the Company will have less or no access to borrowed capital going forward. If the Company does not have sufficient funds on hand for repayment, it will be required to seek a waiver

18

or amendment from its lenders, refinance its Credit Agreement or sell assets or additional shares of common stock. The Company may not be able to refinance or complete such transactions on terms acceptable to it, or at all. In the event that the Company is unable to repay the amount owed within 60 days, the Company will be in default under the Credit Agreement, and as such the lenders party thereto will have the right to terminate their aggregate commitment under the Credit Agreement and declare the outstanding borrowings of the Company immediately due and payable in whole. An acceleration of the outstanding indebtedness under the Credit Agreement in this manner would additionally constitute an event of default under the indenture governing to the Convertible Notes. Should an event of default occur and continue under the indenture governing to the Convertible Notes, the Convertible Notes may be declared immediately due and payable at their principal amount together with accrued interest and liquidated damages, if any. As such, should the Company anticipate that it will not be able to repay all amounts owed under the Credit Agreement as a result of the anticipated borrowing base redetermination, it will consider, along with previously discussed refinancing and sales, a sale of the Company or its assets as well as a voluntary reorganization in bankruptcy. Additionally, if the Company is unable to repay amounts owed under the Credit Agreement, it may be forced into an involuntary reorganization in bankruptcy. The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments, if any, that might result form the effects of the borrowing base redetermination and subsequent transactions.

NOTE 5 — FAIR VALUE MEASUREMENTS

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

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

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

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

SFAS No. 157 requires financial assets and liabilities to be classified based on the lowest level of input that is significant to the fair value measurement. 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.

19

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, 2009 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
Assets
Derivative instruments	$	—	$	6,617,765	$	2,926,998	$	9,544,763
Liabilities:	$	—	$	—	$	—	$	—

The Company’s derivative financial instruments are comprised of natural gas swap and costless collar agreements. The fair values of the swap agreements are determined based primarily on inputs that are derived from observable data at commonly quoted intervals for the full term of the derivatives and are therefore considered level 2 in the fair value hierarchy. The fair value of the costless collar agreement was determined based on both observable and unobservable pricing inputs and therefore, the data sources utilized in this valuation model is considered level 3 inputs in the fair value hierarchy. The counterparty in all of the Company’s derivative financial instruments is the Administrative Agent under our Credit Agreement (Note 4).

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

	Derivatives as of March 31,
	2009			2008
Balance as of January 1	$	2,644,534		$	—
Total gains (losses) (realized or unrealized):
Included in earnings		1,140,134			(2,231,409	)
Included in other comprehensive income		—			—
Purchases, issuances and settlements		(857,670	)		114,990
Transfers in and out of level 3		—			—
Balance as of March 31	$	2,926,998		$	(2,116,419	)
Change in unrealized gains (losses) included in earnings relating to derivatives still held as of March 31	$	2,926,998		$	(2,116,419	)

NOTE 6 — STATEMENT OF CASH FLOWS

During the three months ended March 31, 2009, the Company’s non-cash investing and financing activities consisted of the following transactions:

• Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $225.

• Stock-based compensation of $1,991 capitalized as proved property.

20

• Additions to oil and gas properties included in accounts payable of $3,360,300.

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

• Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $10,245.

• Stock-based compensation of $28,157 capitalized as proved property.

• Additions to oil and gas properties included in accounts payable of $4,236,476.

Cash paid for interest during the three months ended March 31, 2009 and 2008 was $372,243 and $163,713, respectively. There was no cash paid for income taxes during the three months ended March 31, 2009 and 2008.

NOTE 7 — LEGAL PROCEEDINGS

In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), a wholly owned subsidiary of the Company, that was preparing air emission calculations for possible future capacity expansions, preliminarily determined that Riverbend may have not accurately calculated the amount of air pollutants that could be emitted from certain existing equipment at its Riverbend Compressor Station in Uintah County, Utah. Riverbend thereafter undertook a more detailed assessment, which confirmed that Riverbend had not obtained certain air permits nor complied with certain air pollution regulatory programs that were applicable to its operations at the Riverbend Compressor Station. On June 22, 2007, Riverbend sent a letter to the United States Environmental Protection Agency (“EPA”) Region 8 office in Denver, Colorado, which—because the Riverbend Compressor Station is located in Indian Country—is the agency that has jurisdiction over federal air permitting and air pollution regulatory programs. Riverbend’s June 22 letter voluntarily disclosed the potential violations to EPA and informed the agency of the steps that Riverbend had taken and planned to take to achieve compliance. In November 2007, Riverbend met with EPA Region 8 personnel and discussed the disclosed violations, its plans to bring the Riverbend Compressor Station into compliance, and possible resolution of the disclosed violations. In a letter to EPA dated January 23, 2008, Riverbend confirmed its willingness to sign a consent decree with the United States that resolves the apparent violations, specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that will effectively authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented. Riverbend has continued to work with EPA and the Department of Justice on a settlement of this matter, and it anticipates that such a resolution will be achieved during 2009. Riverbend believes that all necessary pollution control and other equipment likely to be required by such a resolution is already installed at the site or accounted for in the Company’s capital budget, and that any civil penalty that may be assessed in conjunction with a resolution of this matter will not materially affect the Company’s financial position.

21

On December 5, 2008, a lawsuit was filed in state court in Cook County, Illinois. The lawsuit alleges that Defendants Richard N. Jeffs, Marc Bruner and Gasco Energy, Inc. through its agency with Mr. Bruner, made misrepresentations, committed fraud, aided and abetted a scheme to defraud, and conspired to defraud in connection with the plaintiffs’ investment in Brek Energy Corporation (“Brek”). The complaint alleges that plaintiffs’ relied on various misrepresentations and omissions by the individual defendants when making the decision to invest in Brek, which merged into Gasco in December of 2007. Gasco removed the case to the United States District Court for the Northern District of Illinois, Eastern Division, on January 7, 2009 and answered the Complaint, denying all liability, on February 13, 2009. Gasco intends to vigorously defend the claims filed against it. A scheduling conference was held on April 1, 2009. The judge ordered fact discovery in the case to be completed by December 15, 2009 and set the trial for June 7, 2010. Given the early stage of the proceedings, we have not yet formed an opinion as to the likelihood of an unfavorable outcome or any estimate of the amount or range of potential loss.

NOTE 8 — CONSOLIDATING FINANCIAL STATEMENTS

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, San Joaquin Oil & Gas, Ltd., Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (collectively, the “Guarantor Subsidiaries”). Set forth below are the condensed consolidating financial statements of Gasco, which is referred to as the Parent, and the Guarantor Subsidiaries. In accordance with generally accepted accounting principles the financial statements of the Parent would include an investment in its subsidiaries. These condensed statements are presented for information purposes only and do not purport the Parent’s balance sheet or statement of operations are prepared under generally accepted accounting principles.

22

Condensed Consolidating Balance Sheet
As of March 31, 2009
(Unaudited)

				Guarantor
	Parent			Subsidiaries			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	6,866,994		$	2,260,517		$	9,127,511
Accounts receivable		1,212,720			6,870,124			8,082,844
Inventory		—			2,384,659			2,384,659
Derivative instruments		9,544,763			—			9,544,763
Prepaid expenses		109,574			—			109,574
Total		17,734,051			11,515,300			29,249,351
PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved properties		73,012			251,686,491			251,759,503
Unproved properties		1,054,096			38,624,552			39,678,648
Gathering assets		—			17,625,895			17,625,895
Facilities and equipment		—			8,596,580			8,596,580
Furniture, fixtures and other		371,605			—			371,605
Total		1,498,713			316,533,518			318,032,231
Less accumulated depreciation, depletion and amortization		(246,201	)		(228,954,290	)		(229,200,491	)
Total		1,252,512			87,579,228			88,831,740
OTHER ASSETS
Deposit		139,500			—			139,500
Deferred financing costs		1,350,609			—			1,350,609
Intercompany		246,592,410			(246,592,410	)		—
Total		248,082,519			(246,592,410	)		1,490,109
TOTAL ASSETS	$	267,069,082		$	(147,497,882	)	$	119,571,200
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	89,504		$	3,060,412		$	3,149,916
Revenue payable		—			2,133,904			2,133,904
Advances from joint interest owners		—			352,877			352,877
Accrued interest		1,890,534			—			1,890,534
Accrued expenses		1,142,000			—			1,142,000
Total		3,122,038			5,547,193			8,669,231
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes		65,000,000			—			65,000,000
Long-term debt		44,000,000			—			44,000,000
Asset retirement obligation		—			1,176,939			1,176,939
Deferred rent expense		40,080			—			40,080
Total		109,040,080			1,176,939			110,217,019
STOCKHOLDERS’ EQUITY
Common stock		10,783			—			10,783
Other		154,896,181			(154,222,014	)		674,167
Total		154,906,964			(154,222,014	)		684,950
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	267,069,082		$	(147,497,882	)	$	119,571,200

23

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

				Guarantor
	Parent			Subsidiaries			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	501,511		$	551,705		$	1,053,216
Accounts receivable		451,050			8,813,536			9,264,586
Inventory		—			4,177,967			4,177,967
Derivative instruments		8,855,947			—			8,855,947
Prepaid expenses		188,485			325			188,810
Total		9,996,993			13,543,533			23,540,526
PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved properties		71,021			247,905,833			247,976,854
Unproved properties		1,054,096			38,260,310			39,314,406
Wells in progress		—			644,688			644,688
Gathering assets		—			17,440,680			17,440,680
Facilities and equipment		—			8,549,928			8,549,928
Furniture, fixtures and other		371,605			—			371,605
Total		1,496,722			312,801,439			314,298,161
Less accumulated depreciation, depletion and amortization		(229,318	)		(185,356,264	)		(185,585,582	)
Total		1,267,404			127,445,175			128,712,579
OTHER ASSETS
Deposit		139,500			—			139,500
Deferred financing costs		1,492,903			—			1,492,903
Intercompany		244,524,964			(244,524,964	)		—
Total		246,157,367			(244,524,964	)		1,632,403
TOTAL ASSETS	$	257,421,764		$	(103,536,256	)	$	153,885,508
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	212,172		$	5,666,978		$	5,879,150
Revenue payable		—			3,840,985			3,840,985
Advances from joint interest owners		—			612,222			612,222
Accrued interest		1,187,495			—			1,187,495
Accrued expenses		1,126,000			—			1,126,000
Total		2,525,667			10,120,185			12,645,852
NONCURRENT LIABILITES
5.5% Convertible Senior Notes		65,000,000			—			65,000,000
Long-term debt		31,000,000			—			31,000,000
Asset retirement obligation		—			1,150,179			1,150,179
Deferred rent expense		46,589			—			46,589
Total		96,046,589			1,150,179			97,196,768
STOCKHOLDERS’ EQUITY
Common stock		10,783			—			10,783
Other		158,838,725			(114,806,620	)		44,032,105
Total		158,849,508			(114,806,620	)		44,042,888
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	257,421,764		$	(103,536,256	)	$	153,885,508

24

Consolidating Statements of Operations
(Unaudited)

				Guarantor
For the Three Months Ended March 31, 2009	Parent			Subsidiaries			Consolidated
REVENUES
Oil and gas	$	—		$	4,172,022		$	4,172,022
Gathering		—			875,201			875,201
Rental income		—			366,399			366,399
Total		—			5,413,622			5,413,622
OPERATING EXPENSES
Lease operating		—			691,937			691,937
Gathering operations		—			707,514			707,514
Depletion, depreciation, amortization and accretion		16,883			2,566,087			2,582,970
Impairment		—			41,000,000			41,000,000
Inventory loss		—			121,000			121,000
Contract termination fee		4,701,000			—			4,701,000
General and administrative		1,860,046			—			1,860,046
Total		6,577,929			45,086,538			51,664,467
OTHER INCOME (EXPENSE)
Interest expense		(1,158,729	)		—			(1,158,729	)
Derivative gain		3,542,626			—			3,542,626
Interest income		587			1,115			1,702
Total		2,384,484			1,115			2,385,599
NET INCOME (LOSS)	$	(4,193,445	)	$	(39,671,801	)	$	(43,865,246	)

				Guarantor		Non-guarantor
For the Three Months Ended March 31, 2008	Parent			Subsidiaries		Subsidiary		Consolidated
REVENUES
Oil and gas	$	—		$	8,396,518	$	88,599	$	8,485,117
Gathering		—			908,356		—		908,356
Rental income		—			362,250		—		362,250
Total		—			9,667,124		88,599		9,755,723
OPERATING EXPENSES
Lease operating		—			1,228,469		38,258		1,266,727
Gathering operations		—			656,499		—		656,499
Depletion, depreciation, amortization and accretion		14,262			2,435,540		—		2,449,802
General and administrative		2,188,033			—		—		2,188,033
Total		2,202,295			4,320,508		38,258		6,561,061
OTHER INCOME (EXPENSE)
Interest expense		(1,247,549	)		—		—		(1,247,549	)
Derivative loss		(6,372,452	)		—		—		(6,372,452	)
Interest income		15,218			4		—		15,222
Total		(7,604,783	)		4		—		(7,604,779	)
NET INCOME (LOSS)	$	(9,807,078	)	$	5,346,620	$	50,341	$	(4,410,117	)

25

Consolidating Statements of Cash Flows
(Unaudited)

				Guarantor
For the Three Months Ended March 31, 2009	Parent			Subsidiaries			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(4,567,071	)	$	6,934,391		$	2,367,320
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for acquisitions, development and exploration		—			(7,033,680	)		(7,033,680	)
Advances from joint interest owners		—			(259,345	)		(259,345	)
Net cash used in investing activities		—			(7,293,025	)		(7,293,025	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit		13,000,000			—			13,000,000
Intercompany		(2,067,446	)		2,067,446			—
Net cash provided by financing activities		10,932,554			2,067,446			13,000,000
NET INCREASE IN CASH AND CASH EQUIVALENTS		6,365,483			1,708,812			8,074,295
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD		501,511			551,705			1,053,216
END OF PERIOD	$	6,866,994		$	2,260,517		$	9,127,511

				Guarantor			Non-guarantor
For the Three Months Ended March 31, 2008	Parent			Subsidiaries			Subsidiary			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(1,941,428	)	$	6,717,628		$	50,341		$	4,826,541
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(10,473	)		—			—			(10,473	)
Cash paid for acquisitions, development and exploration		—			(8,322,018	)		(14,337	)		(8,336,355	)
Advances from joint interest owners		—			1,052,696			—			1,052,696
Net cash used in investing activities		(10,473	)		(7,269,322	)		(14,337	)		(7,294,132	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit		12,000,000			—			—			12,000,000
Repayment of borrowings		(9,000,000	)		—			—			(9,000,000	)
Exercise of options to purchase common stock		36,498			—			—			36,498
Intercompany		(515,690	)		551,694			(36,004	)		—
Net cash provided by (used in) financing activities		2,520,808			551,694			(36,004	)		3,036,498
NET INCREASE IN CASH AND CASH EQUIVALENTS		568,907			—			—			568,907
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD		1,843,425			—			—			1,843,425
END OF PERIOD	$	2,412,332		$	—		$	—		$	2,412,332

26

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS

Forward Looking Statements

Please refer to the section entitled “Cautionary Statement Regarding Forward-Looking Statements” at the end of this section for a discussion of factors which could affect the outcome of forward-looking statements used in this report.

Overview

Gasco Energy, Inc. (“Gasco,” “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. Our principal business strategy is to enhance stockholder value by using technologies new to a specific area to generate and develop high-potential exploitation resources in this area. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. We are currently focusing our drilling efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.

Recent Developments

Impact of Current Credit Markets and Commodity Prices

The credit markets and the financial services industry have been experiencing a period of upheaval characterized by the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the United States federal government. During the fourth quarter of 2008 and the first quarter of 2009, the severe disruptions in the credit markets and reductions in global economic activity had significant adverse impacts on stock markets and oil and gas-related commodity prices, which contributed to a significant decline in our stock price and are expected to negatively impact our future liquidity. The following discussion outlines the potential impacts that the current credit markets and commodity prices could have on our business, financial condition and results of operations.

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

Our $250 million Credit Agreement (the “Credit Agreement”) limits our borrowings to the borrowing base less our total outstanding letters of credit issued there under. Currently, our borrowing base is $45.0 million and our outstanding letter of credit sublimit is $10.0 million. We currently have loans of $44.0 million outstanding under our Credit Agreement. Under the terms of our Credit Agreement, our borrowing base is subject to semi-annual redetermination by our lenders based on their valuation of our proved reserves and their internal criteria. In addition to such semi-annual determinations, our lenders may request one additional borrowing base redetermination between each semi-annual calculation. We expect to be notified of the results from the April 2009 borrowing base redetermination in May 2009 and, based on the decline in commodity prices, we believe that it will be reduced. If our borrowing base is reduced as a result of a redetermination to a

27

level below our then current outstanding borrowings, we will be required to repay the amount by which such outstanding borrowings exceed the borrowing base within 60 days of notification by the lenders and we will have less or no access to borrowed capital going forward. If we do not have sufficient funds on hand for repayment, we will be required to seek a wavier or amendment from our lenders, refinance our Credit Agreement or sell assets or additional shares of common stock. We may not be able to refinance or complete such transactions on terms acceptable to us, or at all. In the event that we are unable to repay the amount owed within 60 days, we will be in default under the Credit Agreement, and as such the lenders party thereto will have the right to terminate their aggregate commitment under the Credit Agreement and declare our outstanding borrowings immediately due and payable in whole. An acceleration of the outstanding indebtedness under the Credit Agreement in this manner would additionally constitute an event of default under the indenture governing to the Convertible Notes. Should an event of default occur and continue under the indenture governing to the Convertible Notes, the Convertible Notes may be declared immediately due and payable at their principal amount together with accrued interest and liquidated damages, if any. As such, should we anticipate that we will not be able to repay all amounts owed under the Credit Agreement as a result of the anticipated borrowing base redetermination, we will consider, along with previously discussed refinancing and sales, a sale of our company or our assets as well as a voluntary reorganization in bankruptcy. Additionally, if we are unable to repay amounts owed under the Credit Agreement, we may be forced into an involuntary reorganization in bankruptcy. The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments, if any, that might result form the effects of the borrowing base redetermination and subsequent transactions.

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

Oil and gas prices have declined significantly since historic highs in July 2008 and continued to decline through April of 2009. Further, the decline in commodity prices has outpaced the decline in the prices of goods and services that we use to drill, complete and operate our wells, reducing our cash flow from operations. To mitigate the impact of lower commodity prices on our cash flows, we have entered into commodity derivative instruments for 2008 through the first quarter of 2011 (see Note 2 of the accompanying consolidated financial statements). In the event that commodity prices stay depressed or decline further, our cash flows from operations would be reduced even taking into account our commodity derivative instruments for 2009, 2010 and 2011 and may not be sufficient when coupled with available capacity under our Credit Agreement to meet our working capital needs or fund our initial 2009 capital expenditure budget. This could cause us to alter our business plans, including further reducing our exploration and development plans.

Given the decline in commodity prices and the weak global economic projections for 2009, the Board of Directors approved a revised capital budget of $10,000,000 on January 22, 2009. Based on current expectations, we intend to fund our budget entirely through cash flow from operations. Consequently, we will monitor spending and cash flow throughout the year and may accelerate or delay investment depending on commodity prices, cash flow expectations and changes in our borrowing capacity. At year end we were operating a single drilling rig. This rig was released in late February 2009, which significantly reduced our fixed commitments in 2009 and in subsequent periods. At rig release, we were obligated to pay the rig contractor approximately $4.7 million for

28

early termination of the drilling contract (as calculated at $12,000/day from rig release through March 15, 2010, the expiration date of the contract).

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

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

Our Credit Agreement contains covenants including those that require us to maintain (1) a current ratio (defined as current assets plus unused availability under the credit facility divided by current liabilities excluding the current portion of the Credit Agreement), determined at the end of each quarter, of not less than 1.0:1; and (2) a ratio of senior debt to EBITDAX (as such term is defined in the revolving credit facility) for the most recent four quarters not to be greater than 3.5:1 for each fiscal quarter. In addition, the Credit Agreement contains covenants that restrict our ability to incur other indebtedness, create liens or sell our assets, pay dividends on our common stock and make certain investments. As of March 31, 2009, our current and senior debt to EBITDAX ratios were 2.4:1 and 2.1:1, respectively, and we were in compliance with each of the covenants as of March 31, 2009 through May 4, 2009. Sustained or lower oil and natural gas prices could reduce our consolidated EBITDAX and thus could reduce our ability to maintain existing levels of senior debt or incur additional indebtedness. Additionally, at current commodity prices, EBITDAX will be reduced for the four quarters beginning with the quarter ended March 31, 2009 and further reduced by the payment of approximately $4.7 million for early termination of our drilling contract in February 2009, resulting in a corresponding reduction in the levels of senior debt that we may have outstanding going forward without violating our senior debt to EBITDAX ratio.

Any failure to be in compliance with any material provision or covenant of our Credit Agreement could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under our Credit Agreement. Additionally, should our obligation to repay indebtedness under our Credit Agreement be accelerated, we would be in default under the indenture governing our Convertible Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such Convertible Notes. To the extent it becomes necessary to address any anticipated covenant compliance issues, we may be required to sell a portion of our assets or issue additional securities, which would be dilutive to our shareholders. Given the condition of current credit and capital markets, any sale of assets or issuance of additional securities may not be on terms acceptable to us.

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

As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf (Note 2). Therefore, impairment expense of $41,000,000 was recorded during the quarter ended March 31, 2009.

29

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

Investments in unproved properties, including capitalized interest costs, are also assessed periodically to ascertain whether impairment has occurred. Our evaluation of impairment of unproved properties incorporates our expectations of developing unproved properties given current and forward-looking economic conditions and commodity prices. As of March 31, 2009, we did not record an impairment related to unproved properties, as we believe we will be able to successfully develop these properties in the future.

Reduced Commodity Prices May Impact Our Ability to Produce Economically

Significant or extended price declines may adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

Drilling Activity

During the three months ended March 31, 2009, we reached total depth on two gross wells (0.84 net), one of which was in progress at December 31, 2008. We spudded one new well during the first quarter of 2009 and upon reaching total depth on this well, we released our remaining drilling rig. We did not conduct any initial completion operations. We re-entered three gross operated wells (0.92 net wells) to complete pay zones that were behind pipe. We have an inventory of 32 operated wells with up-hole recompletion opportunities and four Upper Mancos wells awaiting initial completion activities. Due to low gas prices in the Rockies, we are selectively recompleting up-hole pay to satisfy our required volumes under our derivative contracts. As of March 31, 2009, we operated 130 gross producing wells.

We currently own a drilling rig that we have leased to operator for the drilling of wells that we do not operate. During the first quarters of 2009 and 2008 we earned rig rental income of $366,399 and $362,250, respectively. This rig was released from the last well it drilled during April 2009 and is currently not drilling.

Oil and Gas Production Summary

The following table presents our production and price information during the three months ended March 31, 2009 and 2008. The Mcfe calculations assume a conversion of 6 Mcf for each Bbl of oil.

30

	For the Three Months Ended
	March 31,
	2009		2008
Natural gas production (Mcf)		1,193,018		1,037,966
Average sales price before hedging transactions per Mcf	$	3.28	$	7.61
Oil production (Bbl)		10,254		7,806
Average sales price per Bbl	$	25.45	$	75.28
Production (Mcfe)		1,254,542		1,084,802

During the three months ended March 31, 2009, our oil and gas production increased by approximately 16% primarily due to the recompletion of three existing wells partially offset by normal production declines on wells drilled during earlier periods.

Liquidity and Capital Resources

Our Credit Agreement provides for periodic borrowing base redeterminations which affects our available borrowing base. Please see “—Recent Developments—Impact of Credit Market and Commodity Prices” above for a discussion of our liquidity and the impact of current market conditions thereon.

Sources and Uses of Funds

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

	For the Three Months Ended
	March 31,
	2009			2008
Net cash provided by operations	$	2,367,320		$	4,826,541
Net cash used in investing activities		(7,293,025	)		(7,294,132	)
Net cash provided by financing activities		13,000,000			3,036,498
Net increase in cash		8,074,295			568,907

Cash provided by operations decreased by $2,459,221 from March 31, 2008 to March 31, 2009. The decrease in cash provided by operations was due to the $4,701,000 contract termination fee that we incurred during the first quarter of 2009 to terminate our drilling contract (see Note 2 of the accompanying financial statements) as well as the reduction in oil and gas revenue primarily due to the 57% decrease in gas prices and the 66% decrease in oil prices partially offset by the 16% increase in equivalent oil and gas production during 2009. The production increase is due primarily to the recompletion of three existing wells during the first quarter of 2009 as well as the drilling, completion and recompletion activity during the remaining three quarters of 2008.

31

Our investing activities during the three months ended March 31, 2009 and 2008 related primarily to our development and exploration activities and the change in our advances from joint interest owners.

The financing activity during the first quarter of 2009 consisted of $13,000,000 of borrowings under our line of credit. The financing activity during 2008 was comprised primarily of borrowings under our line of credit of $12,000,000 and the repayment of $9,000,000.

Schedule of Contractual Obligations

At March 31, 2009, we were no longer obligated to make future payments under our drilling rig commitments as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008. For further information, please refer to “Contract Termination Fee” under Note 2 in the Notes to the accompanying consolidated financial statements.

Forward Sales Contract

For our 2008 and 2009 production, we entered into a firm sales and transportation agreement to sell 30,000 MMBtu. per day of our gross production from the Uinta Basin. During the first quarter of 2008, 18,000 MMBtu. per day of such amount was contracted at the CIG first of month price and the remaining 12,000 MMBtu. per day was priced at the NW Rockies first of month price. Beginning in the second quarter of 2008, the entire contracted amount was based on NW Rockies first of month price.

During April 2009 we entered into another firm sales and transportation agreement to sell up to 50,000 MMBtu. per day of our 2010 and 2011 gross production from the Uinta Basin. The contract contains two pricing mechanisms: (1) up to 25,000 MMBtu. per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu. per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price.

We have elected the normal purchase and sale exemption under paragraph 10(b) of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” because we anticipate that (1) we will produce the volumes required to be delivered under the terms of the contracts, (2) it is probable the delivery will be made to the counterparty and (3) the counterparty will fulfill its contractual obligations under the terms of the contracts. As such, we believe we are not required to treat the contracts as derivatives and the contracts will not be marked to market under the provisions of SFAS No. 133.

Capital Budget

On January 22, 2009 our Board of Directors approved a revised initial 2009 capital budget of $10,000,000. We have reduced our budget by $20,000,000 from our preliminary budget presented in November 2008. The change in plans is a direct result of the further weakening in commodity prices, high service costs for drilling and completing wells and limited capital markets. The revised

32

program includes the completion of one well, the drilling and completion of approximately two gross (0.84 net) wells and 12 recompletions (4 net) of up-hole zones on our Riverbend Project located in the Uinta Basin of Utah. The wells in the program will be drilled to develop the natural-gas-bearing upper Mancos shale intervals and associated up-hole pay zones in each wellbore. The budget does not include possible acquisitions, but may include installation of pipeline infrastructure, distribution facilities and certain geophysical operations.

Based on current expectations, we intend to fund our budget entirely through cash flow from operations. Consequently, we will monitor spending and cash flows throughout the year and may accelerate or delay investment depending on commodity prices and cash flow expectations. At year end we were operating a single drilling rig. This rig was released in late February 2009, which has significantly reduced our fixed commitments in 2009 and in subsequent periods. At rig release, we were obligated to pay the rig contractor approximately $4.7 million for early termination of the drilling contract (as calculated at $12,000/day from rig release through March 15, 2010, the expiration date of the contract).

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States requires management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures.

Oil and Gas Properties and Reserves

We follow the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment would be recognized. As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf. Therefore, impairment expense of $41,000,000 was recorded during the quarter ended March 31, 2009.

Estimated reserve quantities and future net cash flows have the most significant impact on us because these reserve estimates are used in providing a measure of our overall value. Estimated quantities are affected by changes in commodity prices and actual well performance. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of our proved

33

properties. If our reserve quantities change or if additional costs are reclassified from unproved properties into proved properties, depletion expense could be significantly affected.

Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the Securities and Exchange Commission (“SEC”), such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.

The most accurate method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Since most of our wells have been producing less than seven years, their production history is relatively short, so other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir were used in conjunction with the decline analysis method to determine the estimates of our proved reserves including developed producing, developed non-producing and undeveloped. As our wells are produced over time and more data is available, the estimated proved reserves will be redetermined on an annual basis and may be adjusted based on that data.

Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the quantities and present value of our reserves. For example a decrease in price of $0.10 per Mcf for natural gas and $1.00 per barrel of oil would result in a decrease in our December 31, 2008 present value of future net cash flows of approximately $5,458,600. In addition, we may adjust estimates of proved reserves to reflect production history, acquisitions, divestitures, ownership interest revisions, results of exploration and development and prevailing gas and oil prices. Our reserves may also be susceptible to drainage by operators on adjacent properties.

Impairment of Long-lived Assets

The cost of our unproved properties is withheld from the depletion base as described above, until it is determined whether or not proved reserves can be assigned to the properties. These properties are reviewed periodically for possible impairment. Our management reviews all unproved property each quarter. If a determination is made that acreage will be expiring or that we do not plan to develop some of the acreage that is no longer considered to be prospective, we record an impairment of the acreage and reclassify the costs to the full cost pool. We estimate the value of these acres for the purpose of recording the related impairment. The impairments that we have recorded were estimated

34

by calculating a per acre value from the total unproved costs incurred for the applicable acreage divided by the total net acres owned by Gasco. This per acre estimate is then applied to the acres that we do not plan to develop in order to calculate the impairment. A change in the estimated value of the acreage could have a material impact on the total impairment recorded by Gasco, calculation of depletion expense and the ceiling test analysis. During 2008, we reclassified approximately $1,250,000 and $750,000 of expiring acreage primarily in Utah and California, respectively into proved property as we do not plan to drill any new wells during 2009. This reclassification represents the value of the leases that will expire during 2009 before we are able to develop them further. Our evaluation of impairment of unproved properties incorporates our expectations of developing unproved properties given current and forward-looking economic conditions and commodity prices. As of March 31, 2009, we did not record an impairment related to unproved properties, as we believe we will be able to successfully develop these properties in the future.

We currently own a drilling rig that had a carrying value of approximately $5,500,000. In light of the current market conditions and the lower commodity prices, many oil and gas companies have cut back on their drilling plans for 2009. As a result, the demand for drilling rig services has also declined. Our rig was released after drilling its last well in early April 2009 and is currently not drilling. Based upon an independent appraisal of our drilling rig, we believed that the market value of our drilling rig decreased to approximately $2,000,000 as of December 31, 2008 and for that reason we recorded impairment expense of $3,500,000 during the year ended December 31, 2008. We do not believe any further impairment is necessary as of March 31, 2009.

Stock-Based Compensation

We account for stock option grants and restricted stock awards in accordance with SFAS No. 123(R), “Share Based Payment.” which requires companies to recognize compensation cost for stock-based awards based on the estimated fair value of the award. Compensation cost is measured at the grant date based on the fair value of the award and is recognized as an expense over the service period, which generally represents the vesting period. We use the Black-Scholes option valuation model to calculate the fair value of option awards under SFAS 123(R). This model requires us to estimate a risk free interest rate and the volatility of our common stock price. The use of a different estimate for any one of these components could have a material impact on the amount of calculated compensation expense.

Derivatives

We have entered into certain derivative instruments to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. We account for our derivatives and hedging activities under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133, we are required to record our derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in current earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other

35

comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. Management has decided not to use cash flow hedge accounting for our derivatives. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair value are recognized in earnings. We recorded an unrealized gain on derivative instruments of $688,816 during the three months ended March 31, 2009, and we recorded an unrealized loss of $5,933,182 during the three months ended March 31, 2008.

As of March 31, 2009, we had a net derivative asset of $9,544,763, of which $2,926,998 was measured based upon our valuation model and, as such, is classified as a Level 3 fair value measurement. We value this Level 3 contract using a model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors (d) notional quantities (e) current market and contractual prices for the underlying instruments and (f) the counterparty’s and our credit ratings. The unobservable inputs related to the volatility of the oil and gas commodity market are very significant in these calculations. Continued volatility in these markets could have a significant impact on the fair value of our derivative contracts. Please see Note 5, “Fair Value Measurements” in the accompanying consolidated financial statements.

Results of Operations

The First Quarter of 2009 Compared to the First Quarter of 2008

Oil and Gas Revenue and Production

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

	For the Three Months Ended
	March 31,
	2009		2008
Natural gas production (Mcf)		1,193,018		1,037,966
Average sales price per Mcf	$	3.28	$	7.61
Natural gas revenue	$	3,911,051	$	7,897,480
Oil production (Bbl)		10,254		7,806
Average sales price per Bbl	$	25.45	$	75.28
Oil revenue	$	260,971	$	587,637

The decrease in oil and gas revenue of $4,313,095 during the first quarter of 2009 compared with the first quarter of 2008 is comprised of a decrease in the average oil and gas prices of $49.83 per Bbl and $4.33 per Mcf partially offset by a 16% increase in oil and gas production. The production increase is primarily due to the drilling and completion activity during 2008 as well as the three recompletions performed during 2009, partially offset by normal production declines on existing wells. The $4,313,095 decrease in oil and gas revenue during the first quarter of 2009 represents a

36

decrease of $4,884,044 related to the decrease in oil and gas prices partially offset by an increase of $570,949 related to the production increase.

Gathering Revenue and Expenses

Gathering revenue and expense represents the income earned from the third party working interest owners in the wells we operate (our share of gathering revenue is eliminated against the transportation expense included in our lease operating costs) and the expenses incurred from the Riverbend area pipeline that we constructed during 2004 and 2005. The gathering income decreased by $33,155 during the first quarter of 2009 as compared with the first quarter of 2008 due to the decreased oil and gas prices partially offset by increased production resulting from our drilling activity in this area. The increase in gathering expense of $51,015 during the first quarter of 2009 is primarily due to increased operating expenses due to the increased production in 2009.

Rental Income

Rental income is comprised of the lease payments received from a third party’s use of our drilling rig. Rental income is eliminated against the full cost pool when the rig is used to drill our operated wells and rental income is recognized when the rig is used to drill third party wells. The rig was used for drilling third party wells during the three months ended March 31, 2009 and 2008 and the income associated with the rental of the rig was $366,399 and $362,250, respectively. The rig was released from its last drilling project during April 2009 and is currently not leased for drilling services.

Lease Operating Expenses

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

	For the Three
	Months Ended
	March 31,
	2009		2008
Direct operating expenses and overhead	$	506,000	$	948,039
Workover expense		2,896		6,120
Total operating expenses	$	508,896	$	954,159
Operating expenses per Mcfe	$	0.41	$	0.88
Production and property taxes	$	183,041	$	312,568
Production and property taxes per Mcfe	$	0.14	$	0.29
Total lease operating expense per Mcfe	$	0.55	$	1.17

Lease operating expense decreased $574,790 during the first quarter of 2009 compared with the first quarter of 2008. The decrease is comprised of a $445,263 decrease in operating expenses combined

37

with a $129,527 decrease in production taxes primarily due to the decrease in natural gas and oil prices during the first quarter of 2009. The decrease in operating expenses is due to a reduction in chemical treatment projects during 2009, a decrease in the costs that were incurred during 2008 to repair and bring older wells on to production and the implementation of cost savings measures such as the elimination of over-time worked by our employees and the elimination of contractor services.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation and amortization expense during the first quarters of 2009 and 2008 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 increase of $133,168 during the first quarter of 2009 compared to the first quarter of 2008 is due to the increase in the full cost pool resulting from the drilling projects completed during 2008 and an increase in the depletion rate due to the lower reserve volumes as of March 31, 2009.

Impairment

As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf. Therefore, impairment expense of $41,000,000 was recorded during the quarter ended March 31, 2009.

Inventory Loss

Inventory loss of $121,000 during the first quarter of 2009 represents the reduction in the value of our inventory fair value as of March 31, 2009.

Contract Termination Fee

During February 2009, we released our remaining drilling rig and paid the rig contractor $4,701,000 for early termination of the drilling contract, as calculated at $12,000 per day from the rig release date through March 15, 2010, the expiration date of the contract.

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.

38

	For the Three
	Months Ended
	March 31,
	2009			2008
Total general and administrative costs	$	1,596,559		$	1,771,250
General and administrative costs allocated to drilling, completion and operating activities		(241,830	)		(304,477	)
General and administrative expense	$	1,354,729		$	1,466,773
General and administrative expenses per Mcfe	$	1.08		$	1.35
Total stock-based compensation costs	$	507,308		$	749,417
Stock-based compensation costs capitalized		(1,991	)		(28,157	)
Stock-based compensation	$	505,317		$	721,260
Stock-based compensation per Mcfe	$	0.40		$	0.67
Total general and administrative expense including stock-based compensation	$	1,860,046		$	2,188,033
Total general and administrative expense per Mcfe	$	1.48		$	2.02

General and administrative expense decreased by $327,987 during the first quarter of 2009 as compared with the first quarter of 2008. The decrease is primarily caused by a $215,943 decrease in stock- based compensation expense due to certain stock options and restricted stock becoming fully vested and to the cancellation or forfeiture of options and restricted stock during the first quarter of 2009. The remaining decrease of $112,044 is primarily due to cost cutting measures that we implemented during the first quarter of 2009.

Interest Expense

Interest expense decreased $88,820 during the first quarter of 2009 as compared with the first quarter of 2008 primarily due to lower interest rates during 2009 partially offset by a higher average outstanding debt balance during the first quarter of 2009 as compared with the first quarter of 2008.

Derivative Gains (Losses)

Derivative gains during the first quarter of 2009 were comprised of a realized gain of $2,853,810 and an unrealized gain of $688,816. Derivative losses during the first quarter of 2008 were $6,372,452. The losses were comprised of a realized loss of $439,270 and an unrealized loss of $5,933,182. Realized derivative gains (losses) represent the net settlement due from or to our counterparty based on each month’s settlement during the quarter. The change in these gains and losses during the first quarter of 2008 as compared with the first quarter of 2009 is due to the decrease in gas prices during 2009.

39

Interest Income

Interest income decreased $13,520 during the first quarter of 2009 compared with the first quarter of 2008 primarily due to lower average cash and cash equivalent balances during 2009.

Off Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of March 31, 2009, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements and gas transportation commitments. We do not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

Recently Issued Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements.” This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure related to the use of fair value measures in financial statements. In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for that Asset is Not Active”, which clarified the application of SFAS No. 157 as it relates to the valuation of financial assets in a market that is not active for those financial assets.

On January 1, 2008, the Company adopted the provision of SFAS No. 157 related to financial assets and liabilities measured at fair value on a recurring basis. The Company also adopted FSP FAS 157-1 and FSP FAS 157-3 in 2008. The adoption of these FSPs did not have a material impact on the Company’s financial position or results of operations.

On January 1, 2009, the Company adopted the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis, which include, among others, those nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. Fair value used in the initial recognition of asset retirement obligations is determined based on the present value of expected future dismantlement costs incorporating our estimate of inputs used by industry participants when valuing similar liabilities. Accordingly, the fair value is based on unobservable pricing inputs and therefore, is considered a level 3 value input in the fair value hierarchy (Note 5). The adoption of SFAS No. 157 related to these items did not have a material impact on the Company’s financial position or results of operations.

On April 9, 2009, the FASB issued three FSPs: FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and

40

Identifying Transactions that are not Orderly,” FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-than- temporary Impairments,” and FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” The objectives of these FSPs are to: (1) provide additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased, including guidance on identifying circumstances that indicate a transaction is not orderly; (2) amend the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements and (3) require disclosures about fair value of financial instruments for interim reporting periods for publicly traded companies as well as in annual financial statements. These three FSP’s are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the provisions of these FSP’s for the period ending March 31, 2009. The adoption of these FSP’s did not have a material impact on the Company’s financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired, and establishes that acquisition costs will be generally expensed as incurred. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. On April 1, 2009 the FASB issued FSP FAS 141R-1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP FAS 141R-1”). This FSP amends and clarifies SFAS No. 141R to address application issues related to initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. We adopted SFAS No. 141R on January 1, 2009. The adoption of SFAS No. 141R did not have a material impact on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” which amends SFAS No. 133 by requiring expanded disclosures about an entity’s derivative instruments and hedging activities, but does not change SFAS No. 133’s scope or accounting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted SFAS No. 161 on January 1, 2009 and the adoption of SFAS No. 161 did not have an impact on our financial position or results of operations See Note 2,Derivativesfor required disclosures.

In June 2008, the Emerging Issues Task Force (the “EITF”) issued EITF 07-5, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock.” The objective of this Issue is to provide guidance for determining whether an equity-linked financial instrument (or embedded feature) is indexed to an entity’s own stock. The EITF reached a consensus that contingent and other adjustment features in equity-linked financial instruments are consistent with equity indexation if they are based on variables that would be inputs to a “plain vanilla” option or forward pricing model and they do not increase the contract’s exposure to those variables. Additionally, the denomination of an equity contract’s strike price in a currency other than the entity’s functional currency is inconsistent with equity indexation and precludes equity treatment. We adopted EITF

41

07-5 on January 1, 2009 and the adoption had no material effect on our financial position or results of operations.

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

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

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

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

Cautionary Statement Regarding Forward-Looking Statements

Some of the information in this Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts included in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. These statements express, or are based on, our expectations about future events. Forward-looking statements give our current expectations or forecasts of future events. Forward-looking statements generally can be identified by the use of forward looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe” or “continue” or the negative thereof or similar terminology.

Although any forward-looking statements contained in this Quarterly Report on Form 10-Q or otherwise expressed by or on behalf of us are, to the knowledge and in the judgment of our officers and directors, believed to be reasonable, there can be no assurances that any of these expectations will prove correct or that any of the actions that are planned will be taken. Forward-looking statements involve and can be affected by inaccurate assumptions or by known and unknown risks and uncertainties which may cause our actual performance and financial results in future periods to differ materially from any projection, estimate or forecasted result. Important factors that could cause actual results to differ materially from expected results include those discussed under the

42

caption “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008.

The following are among the important factors that could cause future results to differ materially from any projected, forecasted, estimated or budgeted amounts that we have discussed in this report:

• fluctuations in natural gas and oil prices;

• pipeline constraints;

• overall demand for natural gas and oil in the United States;

• changes in general economic conditions in the United States;

• our ability to manage interest rate and commodity price exposure;

• changes in our borrowing arrangements, including the impact of borrowing base redeterminations;

• our ability to generate sufficient cash flow to operate;

• the condition of credit and capital markets in the United States;

• the amount, nature and timing of capital expenditures;

• estimated reserves of natural gas and oil;

• drilling of wells;

• acquisition and development of oil and gas properties;

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

• timing and amount of future production of natural gas and oil;

• operating costs and other expenses;

• cash flow and anticipated liquidity;

• future operating results;

• marketing of oil and natural gas;

• competition and regulation; and

• plans, objectives and expectations.

43

Any of these factors could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. We cannot assure you that our future results will meet our expectations. When you consider these forward-looking statements, you should keep in mind these factors. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these factors. Our forward-looking statements speak only as of the date made. We assume no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.

GLOSSARY OF NATURAL GAS AND OIL TERMS

     The following is a description of the meanings of some of the natural gas and oil industry terms used that may be used in this report.

     Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

     Bbl/d. One Bbl per day.

     Bcf. Billion cubic feet of natural gas.

     Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

     Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

     Completion. The installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

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

     Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

     Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

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

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

44

     Farm-in or farm-out. An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

     Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

     Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

     Lead. A specific geographic area which, based on supporting geological, geophysical or other data, is deemed to have potential for the discovery of commercial hydrocarbons.

     MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

     Mcf. Thousand cubic feet of natural gas.

     Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

     MMBls. Million barrels of crude oil or other liquid hydrocarbons.

     MMBtu.. Million British Thermal Units.

     MMcf. Million cubic feet of natural gas.

     MMcf/d. One MMcf per day.

     MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

     Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells, as the case may be.

     Net feet of pay. The true vertical thickness of reservoir rock estimated to both contain hydrocarbons and be capable of contributing to producing rates.

     Present value of future net revenues or present value of discounted future net cash flows or present value or PV-10. The pretax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

45

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

     Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

     Proved area. The part of a property to which proved reserves have been specifically attributed.

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

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

     Proved properties. Properties with proved reserves.

     Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves may not include

46

estimates attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

     Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

     Service well.A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

     Standardized Measure of Discounted Future Net Cash Flows.The discounted future net cash flows relating to proved reserves based on year-end prices, costs and statutory tax rates (adjusted for permanent differences) and a 10-percent annual discount rate.

     Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (a) “exploratory type,” if not drilled in a proved area, or (b) “development type,” if drilled in a proved area.

     Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

     Unproved properties. Properties with no proved reserves.

     Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of March 31, 2009 and December 31, 2008, our natural gas derivative instruments consisted of two swap agreements and one costless collar agreement for our 2009 production. The fair market value of the agreements was a current asset of $9,544,763 and $8,855,947 as of March 31, 2009 and December 31, 2008, respectively. During April 2009, we entered into an additional swap agreement for 2010 and 2011 gas production. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our hedged production. Our derivative contracts are described below:

• For our swap instruments, Gasco receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

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

47

Our swap agreements for 2009 through March 2011 are summarized in the table below:

	Remaining		Fixed Price	Floating Price (a)
Agreement Type	Term	Quantity	Counterparty payer	Gasco payer
Swap	4/09 — 12/09	3,000 MMBtu./day	$7.025/MMBtu.	NW Rockies
Swap	4/09 — 12/09	3,000 MMBtu./day	$7.015/MMBtu.	NW Rockies
Swap	1/10 — 3/11	3,000 MMBtu./day	$4.825/MMBtu.	NW Rockies

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

			Index	Call Price	Put Price
Agreement Type	Term	Quantity	Price (a)	Counterparty buyer	Gasco buyer
Costless collar	4/09 — 12/09	3,000 MMBtu./day	NW Rockies	$7.50/MMBtu.	$6.50/MMBtu.

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

The swap contracts will allow us to predict with greater certainty the effective natural gas prices that we will receive for our hedged production and to benefit from operating cash flows when market prices are less than the fixed prices of the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for the hedged production. The collar structures provide for participation in price increases and decreases to the extent of the ceiling and floors provided in our contracts.

Interest Rate Risk

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

48

ITEM 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management has evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2009. Our disclosure controls and procedures are designed to provide us with a reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management as appropriate to allow such persons to make timely decisions regarding required disclosures.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and our CEO and CFO have concluded, as of March 31, 2009, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

Changes in Internal Controls over Financial Reporting during the First Quarter of 2009

There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated by the SEC under the Securities Exchange Act of 1934) during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

49

PART II — OTHER INFORMATION

Item 1 — Legal Proceedings

See discussion of legal proceedings as reported in Note 7 of the accompanying financial statements included herein.

Item 1A — Risk Factors

Information about material risks related to our business, financial condition and results of operations for the three months ended March 31, 2009, does not materially differ from that set out in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2008.

Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds

Working capital restrictions and other limitations upon the payment of dividends are reported in Note 4 of the accompanying financial statements included herein.

Item 3 — Defaults Upon Senior Securities

     None.

Item 4 — Submission of Matters to a Vote of Security Holders

     None.

Item 5 — Other Information

     None.

Item 6 — Exhibits

Exhibit Number	Exhibit
3.1	Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
3.2	Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).
3.3	Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).

50

Exhibit Number	Exhibit
3.4	Second Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).
3.5	Certificate of Designation for Series B Preferred Stock (incorporated by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement, filed on April 17, 2003, File No. 333-104592).
#10.1	Form of Amendment to Gasco Energy, Inc. Employment Agreement, dated as of December 31, 2008, and effective as of January 1, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated January 7, 2009, filed January 7, 2009, File No. 001-32369).
#10.2	Form of Second Amendment to Gasco Energy, Inc. Employment Agreement, dated as of January 22, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated by reference to Exhibit 10.12 to the Company’s Form 10-K dated December 31, 2008, filed March 4, 2009, File No. 001-32369).
*31	Rule 13a-14(a)/15d-14(a) Certifications.
**32	Section 1350 Certifications

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

51

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	GASCO ENERGY, INC.
Date: May 4, 2009	By:	/s/ W. King Grant
		W. King Grant, Executive Vice President
		Chief Financial Officer

52

Exhibit Index

Exhibit Number	Exhibit
3.1	Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
3.2	Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).
3.3	Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).
3.4	Second Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).
3.5	Certificate of Designation for Series B Preferred Stock (incorporated by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement, filed on April 17, 2003, File No. 333-104592).
#10.1	Form of Amendment to Gasco Energy, Inc. Employment Agreement, dated as of December 31, 2008, and effective as of January 1, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated January 7, 2009, filed January 7, 2009, File No. 001-32369).
#10.2	Form of Second Amendment to Gasco Energy, Inc. Employment Agreement, dated as of January 22, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated by reference to Exhibit 10.12 to the Company’s Form 10-K dated December 31, 2008, filed March 4, 2009, File No. 001-32369).
*31	Rule 13a-14(a)/15d-14(a) Certifications.
**32	Section 1350 Certifications

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

53