Gasco Energy 10Q 2008 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, 2008


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 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	Smaller reporting company o
	(Do not check if a smaller reporting company)

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 6, 2008: 107,230,419

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
First Amendment to the Credit Agreement
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications

ITEM I — FINANCIAL STATEMENTS

PART 1 — FINANCIAL INFORMATION

GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)


	March 31,			December 31,
	2008			2007
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	2,412,332		$	1,843,425
Accounts receivable
Joint interest billings		4,724,037			5,639,174
Revenue		4,552,178			3,872,959
Inventory		2,428,328			1,160,325
Prepaid expenses		219,099			327,030

Total		14,335,974			12,842,913


PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved mineral interests		220,362,367			215,273,593
Unproved mineral interests		40,409,506			41,644,348
Wells in progress		1,202,792			1,058,727
Gathering assets		15,832,449			15,708,353
Facilities and equipment		9,739,600			9,680,010
Furniture, fixtures and other		295,264			284,791

Total		287,841,978			283,649,822
Less accumulated depletion, depreciation, amortization and impairment		(178,453,713	)		(175,973,720	)

Total		109,388,265			107,676,102


OTHER ASSETS
Deposit		139,500			139,500
Deferred financing costs		1,723,716			1,853,274

Total		1,863,216			1,992,774


TOTAL ASSETS	$	125,587,455		$	122,511,789

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

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


	March 31,			December 31,
	2008			2007
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	7,700,952		$	13,206,767
Revenue payable		2,856,872			1,477,268
Advances from joint interest owners		6,770,930			5,718,234
Derivative instruments		4,571,404			343,759
Accrued interest		1,760,594			844,094
Accrued expenses		487,000			583,000

Total		24,147,752			22,173,122


NONCURRENT LIABILITIES
5.5% Convertible Senior Notes		65,000,000			65,000,000
Long-term debt		12,000,000			9,000,000
Derivative instruments		1,705,537			—
Asset retirement obligation		1,053,739			1,030,283
Deferred rent expense		56,838			60,593

Total		79,816,114			75,090,876


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; 107,304,119 shares issued and 107,230,419 outstanding as of March 31, 2008 and 107,290,471 shares issued and 107,216,771 outstanding as of December 31, 2007		10,730			10,729
Additional paid-in capital		215,880,185			215,094,271
Accumulated deficit		(194,137,031	)		(189,726,914	)
Less cost of treasury stock of 73,700 common shares		(130,295	)		(130,295	)

Total		21,623,589			25,247,791


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	125,587,455		$	122,511,789

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

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


	Three Months Ended
	March 31,
	2008			2007
REVENUES
Gas	$	7,897,480		$	5,471,938
Oil		587,637			380,767
Gathering		908,356			486,666
Rental income		362,250			—
Derivative losses		(6,372,452	)		—
Interest income		15,222			100,360

Total		3,398,493			6,439,731


OPERATING EXPENSES
Lease operating		1,266,727			596,262
Gathering operations		656,499			354,720
Depletion, depreciation, amortization and accretion		2,449,802			2,336,118
General and administrative		2,188,033			2,326,077
Interest expense		1,247,549			1,002,728

Total		7,808,610			6,615,905


NET LOSS	$	(4,410,117	)	$	(176,174	)


NET LOSS PER COMMON SHARE — BASIC AND DILUTED	$	(0.04	)	$	(0.00	)


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING — BASIC AND DILUTED		106,903,548			85,734,095

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

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


	Three Months Ended
	March 31,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(4,410,117	)	$	(176,174	)
Adjustment to reconcile net loss to net cash provided by operating activities
Depletion, depreciation, amortization and impairment expense		2,426,412			2,314,603
Accretion of asset retirement obligation		23,390			21,515
Stock-based compensation		721,260			957,344
Unrealized derivative loss		5,933,182			—
Amortization of deferred rent		(3,755	)		(4,932	)
Amortization of deferred financing costs		129,558			129,558
Changes in operating assets and liabilities:
Accounts receivable		235,918			2,891,823
Inventory		(1,268,003	)		(820,478	)
Prepaid expenses		107,931			149,528
Accounts payable		(1,269,339	)		(2,454,844	)
Revenue payable		1,379,604			(164,665	)
Advances from joint interest owners		1,052,696			(1,773,078	)
Accrued interest		916,500			893,751
Accrued expenses		(96,000	)		(249,265	)

Net cash provided by operating activities		5,879,237			1,714,686


CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(10,473	)		(8,239	)
Cash paid for acquisitions, development and exploration		(8,336,355	)		(26,085,541	)
Proceeds from sale of short-term investments		—			6,000,000

Net cash used in investing activities		(8,346,828	)		(20,093,780	)


CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit		12,000,000			12,000,000
Repayment of borrowings		(9,000,000	)		—
Exercise of options to purchase common stock		36,498			—

Net cash provided by financing activities		3,036,498			12,000,000


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		568,907			(6,379,094	)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD		1,843,425			12,876,879

END OF PERIOD	$	2,412,332		$	6,497,785

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

GASCO ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
THREE MONTHS ENDED MARCH 31, 2008 AND 2007
(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. 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.

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 Form 10-K filed with the Securities and Exchange Commission for the year ended December 31, 2007. 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 Form 10-K for the year ended December 31, 2007.

The results of operations for the three months ended March 31, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008. 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.

Oil and Gas Properties

The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, overhead directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $19,538 and $56,690 of internal costs during the three months ended March 31, 2008 and 2007, respectively. Costs associated with production and general

corporate activities are expensed in the period incurred. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs 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 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.

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes (full cost pool) may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued in the balance sheet plus the cost, or estimated fair value, if lower of unproved properties and the costs of any properties not being amortized, if any. Should the full cost pool exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues is computed by applying current oil and gas prices to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. However, subsequent commodity price increases may be utilized to calculate the ceiling value.

As of March 31, 2007, oil and gas prices were $60.75 per barrel and $4.51 per mcf and the full cost pool would have exceeded the above described ceiling by $17,700,000. However, subsequent to quarter end, oil and gas prices increased; and using these prices our full cost pool would not have exceeded the ceiling limitation. As a result of the increase in the ceiling amount using subsequent prices, we did not record an impairment of our oil and gas properties as of March 31, 2007. As of March 31, 2008 our full cost pool did not exceed our ceiling limitation.

Capitalized Interest

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended

use. No interest costs were capitalized during the three months ended March 31, 2008 as we did not engage in such activities; however, $86,524 of interest costs were capitalized during the first quarter of 2007.

Wells in Progress

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

Facilities and Equipment

The Company constructed two evaporation pits in the Riverbend area of Utah to be used for the disposal of produced water from the wells that Gasco operates in the area. The pits 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, net revenue attributable to the outside working interest owners from the evaporation pits of $181,960 and $38,803 was recorded as a credit to proved properties during the three months ended March 31, 2008 and 2007, respectively.

The other oil and gas equipment and facilities owned by the Company are 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 some of the equipment and facilities owned by Gasco is charged to the wells that are operated by Gasco and therefore, a portion of the net revenue attributable to the outside working interest owners from the equipment and facilities rental of $23,590 and $887,080 was recorded as a credit to proved properties during the three months ended March 31, 2008 and 2007, respectively.

Derivatives

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

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

As of March 31, 2008, natural gas derivative instruments consisted of four swap agreements and two costless collar agreements for 2008 and 2009 production. The fair market value of the agreements was a current liability of $4,571,404 and $343,759 as of March 31, 2008 and December 31, 2007, respectively, and a long term liability of $1,705,537 as of March 31, 2008. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our production. Our derivative contracts are described below:

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

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

The table below summarizes the realized and unrealized gains and losses related to our derivative instruments for the first quarter of 2008. We had no derivative transactions during the same period during 2007.


	Three Months Ended
	March 31, 2008

Realized losses on derivative instruments	$	439,270
Unrealized losses on derivative instruments		5,933,182


Total realized and unrealized losses recorded	$	6,372,452

Realized losses are included in cash flows from operating activities in the accompanying consolidated statements of cash flows.

Our swap agreements for 2008 and 2009 are summarized in the table below:

Remaining

Fixed Price

Floating Price (b)

Agreement Type

Term

Quantity

Counterparty payer

Gasco payer

Swap (a)

4/08 — 12/08

3,000 Mmbtu/day

$6.11/Mmbtu

NW Rockies

Swap

4/08 — 12/08

2,000 Mmbtu/day

$6.91/Mmbtu

NW Rockies

Swap

1/09 — 12/09

3,000 Mmbtu/day

$7.025/Mmbtu

NW Rockies

Swap

1/09 — 12/09

3,000 Mmbtu/day

$7.015/Mmbtu

NW Rockies

Our costless collar agreements for 2008 and 2009 are summarized in the table below:

Index

Call Price

Put Price

Agreement Type

Term

Quantity

Price (b)

Counterparty buyer

Gasco buyer

Costless collar

2/08 — 12/08

3,000 Mmbtu/day

NW Rockies

$6.90/Mmbtu

$6.00/Mmbtu

Costless collar

1/09 — 12/09

3,000 Mmbtu/day

NW Rockies

$7.50/Mmbtu

$6.50/Mmbtu


(a)		Contract was initiated in December 2007 and was included in the accompanying consolidated balance sheets at fair market value as a liability of $343,759 as of December 31, 2007.

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

We have established the fair value of our derivative instruments using estimates of fair value reported by our counterparty and subsequently evaluated internally using established index price and other sources. In addition, the estimated fair value of the collars requires the use of an option-pricing model and factors including volatility and time value. The actual contribution to our future results of operations will be based on the market prices at the time of settlement and may be more or less than the value estimates used at March 31, 2008.

The Company is exposed to credit risk to the extent of non performance by the counterparty in the derivative contracts described above. We have reviewed the credit quality of our counterparty and do not anticipate such non performance.

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 accompanying consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs using the units-of-production method. Gasco’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties and gathering assets. The asset retirement liability is allocated to operating expense using a systematic and rational method. The information below reconciles the value of the asset retirement obligation for the periods presented.


	Three Months Ended
	March 31,
	2008			2007

Balance beginning of period	$	1,030,283		$	908,543
Liabilities incurred		10,245			27,576
Liabilities settled		(10,179	)		—
Revisions		—			—
Accretion expense		23,390			21,515

Balance end of period	$	1,053,739		$	957,634

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, 2008, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

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 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 March 31, 2008, common stock equivalents of 27,421,958 have been excluded from the computation of diluted net income (loss) per share.

Use of Estimates

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

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

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. On January 1, 2008, we adopted without material impact on our consolidated financial statements the provisions of SFAS No. 157 related to financial assets and liabilities and to nonfinancial assets and liabilities measured at fair value on a recurring basis. Beginning January 1, 2009, we will adopt 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 will include, among others, those nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. We do not expect the provisions of SFAS No. 157 related to these items to have a material impact on our consolidated financial statements (see Note 6).

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

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired, and establishes that acquisition costs will be generally expensed as incurred. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008, which will be Gasco’s year beginning January 1, 2009. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 141R on our future financial reporting.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated

Financial Statements—amendments of ARB No. 51”. SFAS No. 160 states that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which corresponds to our year beginning January 1, 2009. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 160 on our future financial reporting.

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

On March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” which amends SFAS No. 133 by requiring expanded disclosures about an entity’s derivative instruments and hedging activities, but does not change SFAS No. 133’s scope or accounting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption permitted. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 161 on our future financial reporting.

In March 2008, the FASB, affirmed the consensus of FSP APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)”, which applies to all convertible debt instruments that have a “net settlement feature’’; which means that such convertible debt instruments, by their terms, may be settled either wholly or partially in cash upon conversion. FSP APB 14-a requires issuers of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuer’s nonconvertible debt borrowing rate. Previous guidance provided for accounting for this type of convertible debt instrument entirely as debt. FSP APB 14-a is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We are currently evaluating the impact adoption of FSP APB 14-a may have on our consolidated financial statements.

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 Form 10-K for the year ended December 31, 2007 for additional information. The Company accounts for stock option grants and restricted stock awards in accordance with SFAS No. 123(R), “Accounting for Stock-Based Compensation.”

During the three months ended March 31, 2008 and 2007, the Company recognized stock-based compensation as follows:


	Three Months Ended
	March 31,
	2008			2007
Stock-based compensation	$	749,417		$	961,559
Consultant compensation capitalized as proved property		(28,157	)		(4,215	)

Total stock-based compensation expense	$	721,260		$	957,334

We account for stock compensation arrangements with non-employees in accordance with SFAS No. 123(R) and Emerging Issues Task Force, or EITF, No. 96-18, “Accounting of Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services,” using a fair value approach. Stock-based non-employee compensation expense was $62,182 and $5,532 for the three months ending March 31, 2008 and 2007, respectively. Of this $62,182 and $5,532 of total calculated compensation expense for non-employees for the three months ending March 31, 2008 and 2007, $34,025 and $1,317 was expensed and $28,157 and $4,215 was capitalized relating to drilling personnel, respectively.

Stock Options

The Company granted options to purchase 382,500 shares of common stock to its employees, at exercise prices ranging from $1.99 per share to $2.65 per share. The options vest 16 2/3% at the end of each four-month period after the issuance date.

The following table summarizes the stock option activity in the equity incentive plans from January 1, 2007 through March 31, 2008:


				Weighted-Average
	Stock Options			Exercise Price
Outstanding at January 1, 2008		10,729,138		$	2.58
Granted		382,500		$	2.07
Exercised		(16,666	)	$	2.19
Forfeited		(113,334	)	$	2.11
Cancelled		(122,500	)	$	3.19
Outstanding at March 31, 2008		10,859,138		$	2.56
Exercisable at March 31, 2008		8,261,805		$	2.44

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


	Outstanding Options		Vested options
Number of shares		10,859,138		8,261,805
Weighted Average Remaining Contractual Life		6.27		5.38
Weighted Average Exercise Price	$	2.56	$	2.44
Aggregate intrinsic value	$	5,469,809	$	4,610,692

The aggregate intrinsic value in the table above represents the total pretax intrinsic value, based on the Company’s closing common stock price of $2.44 as of March 31, 2008, which would have been received by the option holders had all option holders exercised their options as of that date.

The total intrinsic value of the options exercised during the three months ended March 31, 2008 was $4,000. The total cash received from employees as a result of employee stock option exercises during the three months ended March 31, 2008 was $36,498.

The total grant date fair value of the shares vested during the three months ended March 31, 2008 was $153,302.

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

As of March 31, 2008, there was $3,864,232 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 4.49 years.

Restricted Stock

During the three months ended March 31, 2008, the Company’s Board of Directors approved the issuance of 15,000 shares of common stock, under the Gasco Energy, Inc. Amended and Restated 2003 Restricted Stock Plan, to certain of the Company’s employees. The restricted shares vest at varying schedules within three to five years of the grant date. The shares fully vest upon certain events, such as a change in control of the Company, expiration of the individual’s employment agreement and termination by the Company of the individual’s employment without cause. Any unvested shares are forfeited upon termination of employment for any other reason. The compensation expense related to the restricted stock was measured on the issuance date using the trading price of the Company’s common stock on that date and is amortized over the vesting period.

The following table summarizes the restricted stock activity from January 1, 2008 through March 31, 2008:


				Weighted-Average
	Restricted			Grant Date
	Stock			Fair Value
Outstanding at January 1, 2008		308,820		$	2.36
Granted		15,000		$	2.11
Vested		—			—
Forfeited		(11,000	)	$	2.21
Outstanding at March 31, 2008		312,820		$	2.41

As of March 31, 2008, there was $603,417 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 4.5 years.

NOTE 4 — CREDIT FACILITY

On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered into a $250,000,000 Credit Agreement (the “Credit Agreement”) with JPMorgan Chase Bank, N.A., as Administrative Agent and the other lenders named therein. Borrowings made under the Credit Agreement are guaranteed by our subsidiaries except for the subsidiaries acquired in our purchase of Brek Energy Corporation (“Brek Acquisition”) during December, 2007 and secured by a pledge of the capital stock of such subsidiaries and mortgages on substantially all of our oil and gas properties.

The initial aggregate commitment of the lenders under the Credit Agreement is $250,000,000, subject to a borrowing base which was increased to $40,000,000 as of December 31, 2007 and in April 2008, it was increased to $45,000,000. The Credit Agreement also provides for a $10,000,000 sublimit for letters of credit which we may use for general corporate purposes. As of March 31, 2008, there were loans of $12,000,000 outstanding at an interest rate of 4.5% and a $6,564,000 letter of credit which is considered usage for purposes of calculating availability and commitment fees. Our aggregate borrowings and outstanding letters of credit under the Credit Agreement may not at any time exceed the borrowing base. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2010. 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.

Interest on borrowings under the Credit Agreement accrues at variable interest rates at either, at our election, a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies from 1.25% (for periods in which we have utilized less than 50% of the borrowing base) to 2.00% (for periods in which we have utilized greater than 90% of the borrowing base). The alternate base rate is calculated as (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus 0.50%, plus (2) an applicable margin that varies from 0% (for periods in which we have utilized less than 50% of the borrowing base) to 0.75% (for periods in which we have utilized greater than 90% of the borrowing base). We elect the basis of the interest rate at the time of each borrowing. In addition, we are obligated to pay a commitment fee under the Credit Agreement quarterly in arrears based on a percentage multiplied by the daily amount that the aggregate commitments exceed borrowings under the agreement. The commitment fee percentage varies from 0.30% to 0.50% based on the percentage of the borrowing base utilized.

The Credit Agreement requires us to comply with financial covenants that require us to maintain (1) a Current Ratio (defined as current assets plus unused availability under the Credit Facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Agreement) for the most recent quarter multiplied by four not to be greater than 3.5:1 for each fiscal quarter. In addition, the Credit Agreement contains covenants that restrict our

ability to incur other indebtedness, create liens or sell our assets, pay dividends on our common stock and make certain investments. As of March 31, 2008, the Company was and the Company is currently, in compliance with each of the covenants contained in the Credit Agreement.

NOTE 5 — FAIR VALUE MEASUREMENTS

On January 2, 2008, we adopted SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The Statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

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

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

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

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


	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Assets	$	—	$	—	$	—
Liabilities:
Derivative instruments	$	—	$	4,160,522	$	2,116,419

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

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


	Derivatives			Total
Balance as of January 1, 2008	$	—		$	—
Total losses (realized or unrealized):
Included in earnings		(2,231,409	)		(2,231,409	)
Included in other comprehensive income		—			—
Purchases, issuances and settlements		114,990			114,990
Transfers in and out of level 3		—			—


Balance as of March 31, 2008	$	(2,116,419	)	$	(2,116,419	)


Change in unrealized losses included in earnings relating to derivatives still held as of March 31, 2008	$	(2,116,419	)	$	(2,116,419	)

NOTE 6- STATEMENT OF CASH FLOWS

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.

During the three months ended March 31, 2007, 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 $27,576.

	•		Stock-based compensation of $4,215 capitalized as proved property.

	•		Additions to oil and gas properties included in accounts payable of $4,574,207.

	•		Capitalization of interest expense of $86,524.

Cash paid for interest during the three months ended March 31, 2008 and 2007 was $163,713 and $65,644, respectively. There was no cash paid for income taxes during the three months ended March 31, 2008 and 2007.

NOTE 7 — CONSOLIDATING FINANCIAL STATEMENTS

On September 23, 2005, Gasco filed a Form S-3 shelf registration statement with the Securities Exchange Commission which was subsequently amended by a Form S-3/A that was filed on October 27, 2005. Under this registration statement, which was declared effective on November 1, 2005, we may from time to time offer and sell common stock, preferred stock, depositary shares and debt securities that may be fully, irrevocably and unconditionally guaranteed by all of our subsidiaries, except for the subsidiaries acquired in the Brek Acquisition during December 2007: Gasco Production Company, San Joaquin Oil & Gas, Ltd., Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (“Guarantor Subsidiaries”). Set forth below are the condensed consolidating financial statements of Gasco, which is referred to as the parent, and the Guarantor Subidiaries.

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


				Guarantor			Non-guarantor
	Parent			Subsidiaries			Subsidiary			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,372,603		$	39,729		$	—		$	2,412,332
Accounts receivable		—			9,276,215			—			9,276,215
Inventory		—			2,428,328			—			2,428,328
Prepaid expenses		219,099			—			—			219,099

Total		2,591,702			11,744,272			—			14,335,974

PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved mineral interests		68,151			217,783,779			2,510,437			220,362,367
Unproved mineral interests		1,054,096			11,135,072			28,220,338			40,409,506
Wells in progress		—			1,202,792			—			1,202,792
Gathering assets		—			15,832,449			—			15,832,449
Facilities and equipment		—			9,739,600			—			9,739,600
Furniture, fixtures and other		295,264			—			—			295,264

Total		1,417,511			255,693,692			30,730,775			287,841,978
Less accumulated depreciation, depletion and amortization		(178,975	)		(178,274,738	)		—			(178,453,713	)

Total		1,238,536			77,418,954			—			109,388,265

OTHER ASSETS
Deposit		139,500			—			—			139,500
Deferred financing costs		1,723,716			—			—			1,723,716
Intercompany		231,365,894			(200,685,460	)		(30,680,434	)		—

Total		233,229,110			(200,685,460	)		(30,680,434	)		1,863,216

TOTAL ASSETS	$	237,059,348		$	(111,522,234	)	$	50,341		$	125,587,455


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	341,499		$	7,359,453		$	—		$	7,700,952
Revenue payable		—			2,856,872			—			2,856,872
Advances from joint interest owners		—			6,770,930			—			6,770,930
Derivative instruments		4,571,404			—			—			4,571,404
Accrued interest		1,760,594			—			—			1,760,594
Accrued expenses		487,000			—			—			487,000

Total		7,160,497			16,987,255			—			24,147,752

NONCURRENT LIABILITIES
5.5% Convertible Senior Notes		65,000,000			—			—			65,000,000
Long-term debt		12,000,000			—			—			12,000,000
Derivative instruments		1,705,537			—			—			1,705,537
Asset retirement obligation		—			1,053,739			—			1,053,739
Deferred rent expense		56,838			—			—			56,838

Total		78,762,375			1,053,739			—			79,816,114

STOCKHOLDERS’ EQUITY
Common stock		10,730			—			—			10,730
Other		151,125,746			(129,563,228	)		50,341			21,612,859

Total		151,136,476			(129,563,228	)		50,341			21,623,589

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	237,059,348		$	(111,522,234	)	$	50,341		$	125,587,455

Condensed Consolidating Balance Sheet
As of December 31, 2007
(Unaudited)


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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

Consolidating Statements of Operations
(Unaudited)


				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
Derivative loss		(6,372,452	)		—		—		(6,372,452	)
Interest income		15,218			4		—		15,222

Total		(6,357,234	)		9,667,128		88,599		3,398,493


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
Interest expense		1,247,549			—		—		1,247,549

Total		3,449,844			4,320,508		38,258		7,808,610


NET INCOME (LOSS)	$	(9,807,078	)	$	5,346,620	$	50,341	$	(4,410,117	)


				Guarantor		Non-guarantor
For the Three Months Ended March 31, 2007	Parent			Subsidiaries		Subsidiary		Consolidated
REVENUES
Oil and gas	$	—		$	5,852,705	$	—	$	5,852,705
Gathering		—			486,666		—		486,666
Interest income		100,336			24		—		100,360

Total		100,336			6,339,395		—		6,439,731


OPERATING EXPENSES
Lease operating		—			596,262		—		596,262
Gathering operations		—			354,720		—		354,720
Depletion, depreciation, amortization and accretion		14,603			2,321,515		—		2,336,118
General and administrative		2,326,077			—		—		2,326,077
Interest expense		1,002,728			—		—		1,002,728

Total		3,343,408			3,272,497		—		6,615,905


NET INCOME (LOSS)	$	(3,243,072	)	$	3,066,898	$	—	$	(176,174	)

Consolidating Statements of Cash Flows
(Unaudited)


				Guarantor			Non-guarantor
For the Three Months Ended March 31, 2008	Parent			Subsidiaries			Subsidiary			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(1,941,428	)	$	7,770,324		$	50,341		$	5,879,237

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	)

Net cash used in investing activities		(10,473	)		(8,322,018	)		(14,337	)		(8,346,828	)


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 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


				Guarantor			Non-guarantor
For the Three Months Ended March 31, 2007	Parent			Subsidiaries			Subsidiary		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(1,867,871	)	$	3,582,557		$	—	$	1,714,686

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(8,239	)		—			—		(8,239	)
Cash paid for acquisitions, development and exploration		—			(26,085,541	)		—		(26,085,541	)
Proceeds from sale of short-term investments		6,000,000			—			—		6,000,000

Net cash provided by (used in) investing activities		5,991,761			(26,085,541	)		—		(20,093,780	)


CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit		12,000,000			—			—		12,000,000
Intercompany		(22,451,529	)		22,451,529			—		—

Net cash provided by (used in) financing activities		(10,451,529	)		22,451,529			—		12,000,000


NET DECREASE IN CASH AND CASH EQUIVALENTS		(6,327,639	)		(51,455	)		—		(6,379,094	)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD		10,831,082			2,045,797			—		12,876,879

END OF PERIOD	$	4,503,443		$	1,994,342		$	—	$	6,497,785

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 by us.

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

Drilling Activity

During the three months ended March 31, 2008, we spudded 5 gross wells (approximately 1.6 net wells) and reached total depth on 2 gross wells (approximately 0.67 net wells) in the Riverbend area. All of the wells were drilled to the Upper Mancos shale. We also conducted initial completion operations on four gross operated wells (1.3 net wells) and re-entered five gross operated wells (2.9 net wells) to complete pay zones that were behind pipe. Three other wells were undergoing initial completion operations in the Upper Mancos at the end of the quarter. As of March 31, 2008, we operated 116 gross producing wells. We have an inventory of 31 operated wells with up-hole recompletion opportunities and two wells awaiting completion activities. We currently have two drilling rigs operating in the Uinta Basin Riverbend project. The average drilling time to total depth from the base of surface casing on the past seven Mancos wells is 28.8 days, as compared with our Company’s 25-day target for the Upper Mancos. We have drilled an Upper Mancos well in as little as 16 days from the same marker, but cold weather and mechanical issues on the rigs increased the average days to drill.

Oil and Gas Production Summary

The following table presents Gasco’s production and price information during the three months ended March 31, 2008 and 2007. The Mcfe calculations assume a conversion of 6 Mcf for each Bbl of oil.


	For the Three Months Ended
	March 31,
	2008		2007
Natural gas production (Mcf)		1,037,966		1,000,317
Average sales price before hedging transactions per Mcf	$	7.61	$	5.47

Oil production (Bbl)		7,806		8,391
Average sales price per Bbl	$	75.28	$	45.38

Production (Mcfe)		1,084,802		1,050,663

During the three months ended March 31, 2008, the Company’s oil and gas production increased by approximately 4% primarily due to the Company’s drilling projects, completions, and recompletions that took place during 2007 and 2008. The production increase during 2008 was partially offset by normal production declines on wells drilled during earlier periods.

Liquidity and Capital Resources

As of March 31, 2008, we had a working capital deficit of $9,811,778 of which $4,571,404 represented the fair value of our derivative instruments; however, a combination of cash from operating activities and borrowings from our current unused borrowing base of $26,436,000 is expected to be used to fund our working capital during the next year.

The following table summarizes Gasco’s sources and uses of cash for each of the three months ended March 31, 2008 and 2007.


	For the Three Months Ended
	March 31,
	2008			2007
Net cash provided by operations	$	5,879,237		$	1,714,686
Net cash used in investing activities		(8,346,828	)		(20,093,780	)
Net cash provided by financing activities		3,036,498			12,000,000
Net increase (decrease) in cash		568,907			(6,379,094	)

Cash provided by operations increased by $4,164,551 from March 31, 2007 to March 31, 2008. The increase in cash provided by operations was due primarily to the 39% increase in gas prices and the 65% increase in oil prices as well as the 3% increase in equivalent oil and gas production during 2008. The production increase is due primarily to our drilling, completion and recompletion activity during 2007 and 2008.

Our investing activities during the three months ending March 31, 2008 and 2007 related primarily to our development and exploration activities. The 2007 activity also included proceeds from the sale of short-term investments of $6,000,000.

The financing activity during 2008 is comprised of borrowings under our line of credit of $12,000,000 and the repayment of $9,000,000. The 2007 activity is comprised of borrowings under our line of credit of $12,000,000.

Capital Budget

The Board of Directors of Gasco approved a budget of approximately $34,000,000 for our 2008 capital expenditure program. The program will cover primarily the drilling and completion of approximately 24 gross wells (7 net wells) on our Riverbend Project and the drilling and completion costs on our deep Dakota test in the Gate Canyon area (25% working interest). The budget also includes expenditures for the installation of associated pipeline infrastructure, distribution facilities and geophysical operations.

This budget is expected to be funded primarily from cash on hand, cash flow from operations and borrowings under our credit facility.

Management believes it has sufficient capital for its 2008 operational budget, but may need to raise additional funds for its capital budget in 2009. The Company may consider several options for raising additional funds such as selling securities, selling assets or farm-outs or similar type arrangements. Any financing obtained through the sale of Gasco equity will likely result in substantial dilution to the Company’s stockholders.

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 Reserves

We follow the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance

sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment would be recognized.

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

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

The most accurate method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Since most of our wells have been producing less than six years, their production history is relatively short, so other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir were used in conjunction with the decline analysis method to determine the 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, 2007 present value of future net cash flows of approximately $5,458,600. In addition, we may adjust estimates of proved reserves to reflect production history, acquisitions, divestitures, ownership interest revisions, results of exploration and development and prevailing gas and oil prices. Our reserves may also be susceptible to drainage by operators on adjacent properties.

Impairment of Long-lived Assets

The cost of our unproved properties is withheld from the depletion base as described above, until it is determined whether or not proved reserves can be assigned to the properties. These properties are reviewed periodically for possible impairment. Our management reviews all unproved property each quarter. If a determination is made that acreage will be expiring or that we do not plan to develop

some of the acreage that is no longer considered to be prospective, we record an impairment of the acreage and reclassify the costs to the full cost pool. We estimate the value of these acres for the purpose of recording the related impairment. The impairments that we have recorded were estimated by calculating a per acre value from the total unproved costs incurred for the applicable acreage divided by the total net acres owned by Gasco. This per acre estimate is then applied to the acres that we do not plan to develop in order to calculate the impairment. A change in the estimated value of the acreage could have a material impact on the total of the impairment recorded by Gasco.

Stock-Based Compensation

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

Derivatives

During 2007 and 2008, we entered into certain derivative instruments to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. We account for our derivatives and hedging activities under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133, we are required to record our derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in current earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. Management has decided not to use cash flow hedge accounting for our derivatives. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair market value are recognized in earnings. We recorded an unrealized loss on derivative instruments of $5,933,182 during the first quarter of 2008.

As of March 31, 2008, we had a net derivative liability of $6,276,941, of which $2,116,419 was measured based upon our valuation model and, as such, is classified as a Level 3 fair value measurement. We value these contracts using a model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors (d) notional quantities and (e) current market and contractual prices for the underlying instruments. Please see Note 5, “Fair Value Measurements.”

Results of Operations

The First Quarter of 2008 compared to the First Quarter of 2007

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,
	2008		2007
Natural gas production (Mcf)		1,037,966		1,000,317
Average sales price per Mcf	$	7.61	$	5.47
Natural gas revenue	$	7,897,480	$	5,471,938

Oil production (Bbl)		7,806		8,391
Average sales price per Bbl	$	75.28	$	45.38
Oil revenue	$	587,637	$	380,767

The increase in oil and gas revenue of $2,632,412 during the first quarter of 2008 compared with the first quarter of 2007 is comprised of an increase in the average oil and gas prices of $29.99 per Bbl and $2.14 per Mcf and a 3% increase in oil and gas production. The production increase is primarily due to the drilling and completion activity during 2007 and 2008 partially offset by normal production declines on existing wells. We experienced extreme cold weather in the field during January and February 2008 which also affected production rates as wellheads and flow lines froze and reduced production on the coldest days in the quarter. Fewer completions were scheduled and others were delayed due to the cold weather resulting in fewer wells being brought online during the quarter. The $2,632,412 increase in oil and gas revenue during the first quarter of 2008 represents an increase of $2,390,140 related to the increase in oil and gas prices and an increase of $242,272 related to the production increase.

Derivative Loss

The Company began hedging its production in December 2007 for 2008 and 2009 production. Derivative losses during the first quarter of 2008 were $6,372,452. The loss is comprised of a realized loss of $439,270 and an unrealized loss of $5,933,182. Realized derivative losses represent the net settlement due to our counterparty based on each month’s settlement during the quarter. Realized hedging losses during the first quarter of 2008 would have the effect of reducing our net gas price by $0.42 per Mcf. Unrealized losses represent the change in mark to market values for each active commodity hedge contract. There were no hedges in place during the first quarter of 2007.

Gathering Revenue and Expenses

Gathering revenue and expense represents the income earned from the third party working interest owners in the wells we operate (our share of gathering revenue is eliminated against the transportation expense included in our lease operating costs) and the expenses incurred from the Riverbend area pipeline that we constructed during 2004 and 2005.The gathering income increased by $421,690 during the first quarter of 2008 as compared with the first quarter of 2007 due to the increased production resulting from our drilling activity in this area. The increase in gathering expense of $301,779 during the first quarter of 2007 is primarily due to the addition of compression in early 2008.

Rental Income

Rental income is comprised of the lease payments received from a third party’s use of the Company’s drilling rig. Rental income is eliminated against the full cost pool when the rig is used to drill Company operated wells and rental income is recognized when the rig is used to drill third party wells. The rig has been used for drilling third party wells only since April 2007. In the first quarter of 2008 rental income was $362,250 and there was no rig rental income recognized in the first quarter of 2007.

Interest Income

Interest income decreased $85,138 during the first quarter of 2008 compared with the first quarter of 2007 primarily due to lower average cash and cash equivalent balances during 2008 resulting from our investment in oil and gas properties.

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,
	2008		2007
Direct operating expenses and overhead	$	948,039	$	352,393
Workover expense		6,120		81,706

Total operating expenses	$	954,159	$	434,099

Operating expenses per Mcfe	$	0.88	$	0.41

Production and property taxes	$	312,568	$	162,163

Production and property taxes per Mcfe	$	0.29	$	0.15

Total lease operating expense per Mcfe	$	1.17	$	0.57

Lease operating expense increased $670,465 during the first quarter of 2008 compared with the first quarter of 2007. The increase is comprised of a $520,060 increase in operating expenses combined with a $150,405 increase in production taxes primarily due to the increase in natural gas prices as well as an increase in the number of producing wells from 95 wells at March 31, 2007 to 116 wells at March 31, 2008. The increase in operating expenses is comprised of an increase in water hauling and disposal costs of $107,200 due to increased trucking costs which were driven by increased fuel costs. Additionally, chemical treating costs increased by $160,400 compared to the first quarter of 2007 due to an increase in the amount of chemicals used as well as increased chemical prices.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation and amortization expense during the first quarters of 2008 and 2007 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 $113,684 is due to the increase in the full cost pool resulting from the acquisition of Brek Energy Corporation during December 2007 and the additional drilling and completion costs incurred during 2008.

General and Administrative Expense

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


	For the Three
	Months Ended
	March 31,
	2008			2007
Total general and administrative costs	$	1,771,250		$	1,617,778

General and administrative costs allocated to drilling, completion and operating activities		(304,477	)		(249,045	)

General and administrative expense	$	1,466,773		$	1,368,733

General and administrative expenses per Mcfe	$	1.35		$	1.30


Total stock-based compensation costs	$	749,417		$	961,559
Stock-based compensation costs capitalized		(28,157	)		(4,215	)

Stock-based compensation	$	721,260		$	957,344

Stock-based compensation per Mcfe	$	0.67		$	0.91


Total general and administrative expense including stock-based compensation	$	2,188,033		$	2,326,077


Total general and administrative expense per Mcfe	$	2.02		$	2.21

General and administrative expense decreased by $138,044 during the first quarter of 2008 as compared with the first quarter of 2007. The decrease is primarily caused by the 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 2008. Additionally the allocation of certain drilling, completion and production overhead related to specific projects increased during the first quarter of 2008 due primarily to the increase in the number of wells we operate. These decreased expenses were partially offset by increased salary and office expenses due to the hiring of additional employees during the fourth quarter of 2007.

Interest Expense

Interest expense increased $244,821 during the first quarter of 2008 as compared with the first quarter of 2007 due to a higher average outstanding debt balance during the first quarter of 2008 as compared with the first quarter of 2007, partially offset by lower interest rates during 2008.

Off Balance Sheet Arrangements

Recently Issued Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—amendments of ARB No. 51”. SFAS No. 160 states that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which corresponds to our year beginning January 1, 2009. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 160 on our future financial reporting.

In March 2008, the FASB, affirmed the consensus of FSP APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)”, which applies to all convertible debt instruments that have a ''net settlement feature’’; which means that such convertible debt instruments, by their terms, may be settled either wholly or partially in cash upon conversion. FSP APB 14-a requires issuers of convertible debt instruments that may be settled wholly or partially in cash upon conversion to separately account for the liability and equity components in a manner reflective of the issuer’s nonconvertible debt borrowing rate. Previous guidance provided for accounting for this type of convertible debt instrument entirely as debt. FSP APB 14-a is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. We are currently evaluating the impact adoption of FSP APB 14-a may have on our consolidated financial statements.

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

Although any forward-looking statements contained in this Form 10-Q or otherwise expressed by or on behalf of the Company are, to the knowledge and in the judgment of the officers and directors of the Company, believed to be reasonable, there can be no assurances that any of these expectations will prove correct or that any of the actions that are planned will be taken. Forward-looking statements involve and can be affected by inaccurate assumptions or by known and unknown risks and uncertainties which may cause the Company’s actual performance and financial results in future periods to differ materially from any projection, estimate or forecasted result. Important factors that could cause actual results to differ materially from expected results include those discussed under the caption “Risk Factors” in the Company’s annual report on Form 10-K for the year ended December 31, 2007. Any of these factors could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. We cannot assure you that our future results will meet our expectations. When you consider these forward-looking statements, you should keep in mind these factors. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by these factors. Our forward-looking statements speak only as of the date made. The Company assumes no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.

GLOSSARY OF NATURAL GAS AND OIL TERMS

The following is a description of the meanings of some of the natural gas and oil industry terms used 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.

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

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

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

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

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

Mcf. Thousand cubic feet of natural gas.

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

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

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcf/d. One MMcf per day.

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

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

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

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

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

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

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

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

Proved oil and gas reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions,i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic 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 estimates attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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

Service well.A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam

injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

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

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

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

Unproved properties. Properties with no proved reserves.

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

ITEM 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, 2008, natural gas derivative instruments consisted of four swap agreements and two costless collar agreements for 2008 and 2009 production. The fair market value of the agreements was a current liability of $4,571,404 and $343,759 as of March 31, 2008 and December 31, 2007, respectively, and a long term liability of $1,705,537 as of March 31, 2008. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our hedged production. Our derivative contracts are described below:

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

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

Our swap agreements for 2008 and 2009 are summarized in the table below:

Agreement

Remaining

Fixed Price

Floating Price (b)

Type

Term

Quantity

Counterparty payer

Gasco payer

Swap (a)

4/08 — 12/08

3,000 Mmbtu/day

$6.11/Mmbtu

NW Rockies

Swap

4/08 — 12/08

2,000 Mmbtu/day

$6.91/Mmbtu

NW Rockies

Swap

1/09 — 12/09

3,000 Mmbtu/day

$7.025/Mmbtu

NW Rockies

Swap

1/09 — 12/09

3,000 Mmbtu/day

$7.015/Mmbtu

NW Rockies

Our costless collar agreements for 2008 and 2009 are summarized in the table below:

Index

Call Price

Put Price

Agreement Type

Term

Quantity

Price (b)

Counterparty buyer

Gasco buyer

Costless collar

2/08 — 12/08

3,000 Mmbtu/day

NW Rockies

$6.90/Mmbtu

$6.00/Mmbtu

Costless collar

1/09 — 12/09

3,000 Mmbtu/day

NW Rockies

$7.50/Mmbtu

$6.50/Mmbtu


(a)		Contract was initiated in December 2007 and was included in the accompanying consolidated balance sheets at fair market value as a liability of $343,759 as of December 31, 2007.

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

We have established the fair value of our derivative instruments using estimates of fair value

reported by our counterparty and subsequently evaluated internally using established index price and other sources. The actual contribution to our future results of operations will be based on the market prices at the time of settlement and may be more or less than the value estimates used at March 31, 2008. Our hedging contracts have no requirements for us to post additional collateral based upon the changes in the market value of our hedge instruments.

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.

ITEM 4 — CONTROLS AND PROCEDURES

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

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

over financial reporting.

PART II — OTHER INFORMATION

Item 1 — Legal Proceedings

Information about legal proceedings for the three months ended March 31, 2008, does not materially differ from that set out in Part I, Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

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, 2008, does not materially differ from that set out in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

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

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


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

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

2.5		Purchase and Sale Agreement between ConocoPhillips and the Company relating to the Riverbend Field, Uintah and Duchesne Counties, Utah, Effective January 1, 2004 (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 9, 2004, filed on March 15, 2004, File No. 000-26321)).
2.6		Net Profits Purchase Agreement between Gasco Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 6, 2004 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed September 7, 2004, File No. 000-26321)).

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

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

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

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

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


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

3.5		Certificate of Designation for Series B 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).

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

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

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

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

4.5		Subsidiary Guaranty Agreement, dated October 15, 2003 between San Joaquin Oil and Gas, Ltd. And Renn Capital Group, Inc (incorporated by


Exhibit Number		Exhibit
		reference to Exhibit 4.9 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

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

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

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

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

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

4.11		Pledge and Security Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K dated March 29, 2006, filed March 30, 2006, File No. 001-32369).

4.12		Credit Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated March 29, 2006, filed March 30, 2006, File No. 001-32369).

*4.13		First Amendment to the Credit Agreement dated April 22, 2008 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc.

4.14		Voting Agreement dated September 20, 2006 by and among Gasco Energy, Inc., Richard N. Jeffs, Gregory Pek, Ian Robinson, Michael L. Nazmack, Eugene Sweeney and Shawne Malone (incorporated by reference to Exhibit


Exhibit Number		Exhibit
		4.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).

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

#10.1		1999 Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-KSB for the fiscal year ended December 31, 1999, filed on April 14, 2000).

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

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

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

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

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

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

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

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


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

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

*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.

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 6, 2008	By:	/s/ W. King Grant
		W. King Grant, Executive Vice President
		Chief Financial Officer

Exhibit Index


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

2.2		Agreement and Plan of Reorganization dated December 15, 1999 by and between LEK International, Inc. and San Joaquin Oil & Gas Ltd. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321)).
2.3		Property Purchase Agreement dated as of April 23, 2002, between the Company and Shama Zoe Limited Partnership (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated May 1, 2002, filed on May 9, 2002, File No. 000-26321)).

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

2.5		Purchase and Sale Agreement between ConocoPhillips and the Company relating to the Riverbend Field, Uintah and Duchesne Counties, Utah, Effective January 1, 2004 (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 9, 2004, filed on March 15, 2004, File No. 000-26321)).
2.6		Net Profits Purchase Agreement between Gasco Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 6, 2004 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed September 7, 2004, File No. 000-26321)).

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

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

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

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

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


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

3.5		Certificate of Designation for Series B 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).

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

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

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

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

4.5		Subsidiary Guaranty Agreement, dated October 15, 2003 between San Joaquin Oil and Gas, Ltd. And Renn Capital Group, Inc (incorporated by


Exhibit Number		Exhibit
		reference to Exhibit 4.9 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).

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

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

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

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

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

4.11		Pledge and Security Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K dated March 29, 2006, filed March 30, 2006, File No. 001-32369).

4.12		Credit Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated March 29, 2006, filed March 30, 2006, File No. 001-32369).

*4.13		First Amendment to the Credit Agreement dated April 22, 2008 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc.

4.14		Voting Agreement dated September 20, 2006 by and among Gasco Energy, Inc., Richard N. Jeffs, Gregory Pek, Ian Robinson, Michael L. Nazmack, Eugene Sweeney and Shawne Malone (incorporated by reference to Exhibit


Exhibit Number		Exhibit
		4.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).

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

#10.1		1999 Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-KSB for the fiscal year ended December 31, 1999, filed on April 14, 2000).

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

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

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

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

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

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

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

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

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

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

*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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Avg

Gasco Energy (GSXN) Inactive 10-Q2008 Q1 Quarterly report

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