Gasco Energy 10Q 2007 Q2 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: June 30, 2007


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 0-26321

GASCO ENERGY, INC.

(Exact name of registrant as specified in its charter)


Nevada		98-0204105
(State or other jurisdiction of incorporation or organization)		(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)

No Change
(Former name, former address and former fiscal year, if changed since last report)

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. Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero Accelerated filerþ Non-accelerated filero

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

Number of Common shares outstanding as of August 1, 2007: 96,077,259

TABLE OF CONTENTS


	ITEM I — FINANCIAL INFORMATION
PART 1 — FINANCIAL STATEMENTS
	ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS
	ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	ITEM 4 — CONTROLS AND PROCEDURES
PART II OTHER INFORMATION
	Item 1 — Legal Proceedings
	Item 1A — Risk Factors
	Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds
	Item 3 — Defaults Upon Senior Securities
	Item 4 — Submission of Matters to a Vote of Security Holders
	Item 5 — Other Information
	Item 6 — Exhibits
SIGNATURES
EXHIBIT INDEX
Participation Agreement
Rule 13a-14(a)/15d-14(a) Certifications
Section 1350 Certifications

ITEM I – FINANCIAL INFORMATION

PART 1 – FINANCIAL STATEMENTS

GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2007			2006
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	4,797,465		$	12,876,879
Restricted investment		1,787,500			3,575,000
Short-term investments		2,000,000			6,000,000
Accounts receivable Joint interest billings		3,674,287			5,955,186
Revenue		1,863,191			3,081,850
Inventory		1,175,491			1,297,498
Prepaid expenses		477,357			644,490

Total		15,775,291			33,430,903


PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved mineral interests		205,192,954			159,407,481
Unproved mineral interests		9,200,692			12,538,067
Wells in progress		1,248,697			5,215,252
Gathering assets		13,812,061			12,703,346
Facilities and equipment		9,137,623			8,492,632
Furniture, fixtures and other		264,773			241,009

Total		238,856,800			198,597,787
Less accumulated depletion, depreciation, amortization and impairment		(139,054,631	)		(68,945,779	)

Total		99,802,169			129,652,008


OTHER ASSETS
Deferred financing costs		2,112,390			2,371,507


TOTAL ASSETS	$	117,689,850		$	165,454,418

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

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


	June 30,			December 31,
	2007			2006
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	4,174,366		$	16,228,056
Revenue payable		1,596,503			1,678,427
Advances from joint interest owners		1,126,241			2,955,376
Accrued interest		869,312			844,102
Accrued expenses		290,000			595,000

Total		8,056,422			22,300,961


NONCURRENT LIABILITIES
5.5% Convertible Senior Notes		65,000,000			65,000,000
Long-term debt		12,000,000			—
Asset retirement obligation		1,027,652			908,543
Deferred rent expense		68,103			72,993

Total		78,095,755			65,981,536


STOCKHOLDERS’ EQUITY
Common stock — $.0001 par value; 300,000,000 shares authorized; 96,150,959 shares issued and 96,077,259 outstanding as of June 30, 2007 and 86,173,715 shares issued and 86,100,015 outstanding as of December 31, 2006		9,615			8,617
Additional paid-in capital		183,482,162			162,646,592
Accumulated deficit		(151,823,809	)		(85,352,993	)
Less cost of treasury stock of 73,700 common shares		(130,295	)		(130,295	)

Total		31,537,673			77,171,921


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	117,689,850		$	165,454,418

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

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


	Three Months Ended
	June 30,
	2007			2006
REVENUES
Gas	$	4,535,627		$	4,312,905
Oil		588,580			297,167
Gathering		472,381			369,256
Rental income		343,875			—
Interest income		171,007			805,000

Total		6,111,470			5,784,328


OPERATING EXPENSES
Lease operating		802,712			866,749
Gathering operations		552,231			371,583
Depletion, depreciation and amortization		3,367,397			2,943,531
Impairment		64,300,000			51,000,000
General and administrative		2,220,578			2,589,007
Interest expense		1,163,194			1,049,541

Total		72,406,112			58,820,411


NET LOSS	$	(66,294,642	)	$	(53,036,083	)


NET LOSS PER COMMON SHARE – BASIC AND DILUTED	$	(0.70	)	$	(0.62	)


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING - BASIC AND DILUTED		94,468,912			85,267,977

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

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


	Six Months Ended
	June 30,
	2007			2006
REVENUES
Gas	$	10,007,565		$	10,010,020
Oil		969,347			529,729
Gathering		959,047			852,395
Rental income		343,875			—
Interest income		271,367			1,651,706

Total		12,551,201			13,043,850


OPERATING EXPENSES
Lease operating		1,398,974			1,396,764
Gathering operations		906,951			759,376
Depletion, depreciation and amortization		5,703,515			5,770,073
Impairment	��	64,300,000			51,000,000
General and administrative		4,546,655			5,273,043
Interest expense		2,165,922			2,057,834

Total		79,022,017			66,257,090


NET LOSS		(66,470,816	)		(53,213,240	)

Preferred stock dividends		—			(1,393	)


NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(66,470,816	)	$	(53,214,633	)


NET LOSS PER COMMON SHARE — BASIC AND DILUTED	$	(0.74	)	$	(0.62	)


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING – BASIC AND DILUTED		90,210,121			85,630,039

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

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


	Six Months Ended
	June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(66,470,816	)	$	(53,213,240	)
Adjustment to reconcile net loss to net cash used in operating activities
Depletion, depreciation, amortization and impairment expense		69,959,073			56,756,570
Accretion of asset retirement obligation		44,442			13,503
Stock-based compensation		1,835,766			2,276,065
Amortization of deferred rent		(4,890	)		(1,368	)
Amortization of deferred financing costs		259,117			241,048
Changes in operating assets and liabilities:
Accounts receivable		3,499,558			(436,722	)
Inventory		122,007			(2,606,071	)
Prepaid expenses		167,133			158,071
Accounts payable		(2,522,430	)		1,160,286
Revenue payable		(81,924	)		(446,064	)
Advances from joint interest owners		(1,829,135	)		488,297
Accrued interest		25,210			—
Accrued expenses		(305,000	)		(47,702	)

Net cash provided by operating activities		4,698,111			4,342,673


CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(23,764	)		(59,071	)
Cash paid for acquisitions, development and exploration		(49,735,532	)		(33,692,479	)
Increase in short-term investments		—			(15,000,000	)
Proceeds from sale of short-term investments		4,000,000			—
Cash designated as restricted		—			(71,436	)
Cash undesignated as restricted		1,787,500			8,351,500

Net cash used in investing activities		(43,971,796	)		(40,471,486	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock		19,300,000			—
Borrowings under line of credit		12,000,000			—
Cash paid for stock offering costs		(105,729	)		—
Preferred dividends		—			(1,393	)
Exercise of options to purchase common stock		—			1,275,985
Cash paid for debt issuance costs		—			(240,262	)

Net cash provided by financing activities		31,194,271			1,034,330


NET DECREASE IN CASH AND CASH EQUIVALENTS		(8,079,414	)		(35,094,483	)

CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD		12,876,879			62,661,368

END OF PERIOD	$	4,797,465		$	27,566,885

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

GASCO ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
THREE AND SIX MONTHS ENDED JUNE 30, 2007 AND 2006
(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 and Dakota/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/A filed with the Securities and Exchange Commission for the year ended December 31, 2006. 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/A for the year ended December 31, 2006.

The results of operations for the six months ended June 30, 2007 are not necessarily indicative of the results that may be expected for the year ending December 31, 2007. 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.

Restricted Investment

The restricted investment balance as of June 30, 2007 and December 31, 2006 represents an investment in U.S. government securities in an amount sufficient to provide for the payment of the semi-annual scheduled interest payments on the Company’s outstanding 5.5% Convertible Notes due 2011 (“Notes”) that are due within one year of the reporting date. This investment will be held until maturity and the cost of the investment approximates its market value.

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 $141,707 and $129,180 of internal costs during the six months ended June 30, 2007 and 2006, 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. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. During the six months ended June 30, 2007, approximately $6,230,000 of unproved leasehold costs related to our Wyoming acreage was reclassified to proved property and was included in the ceiling test and depletion calculations. Management believes that the continued low natural gas prices received in the Rockies have caused the potential resources related to our Wyoming acreage to become uneconomic.

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 June 30, 2007, based on oil and gas prices of $54.09 per barrel and $3.90 per mcf, the full cost pool exceeded the above described ceiling by $66,700,000. However, subsequent to quarter end, oil and gas prices increased; and using these prices the Company’s full cost pool exceeded the ceiling limitation by $64,300,000. Therefore, impairment expense of $64,300,000 was recorded during the six months ended June 30, 2007. The Company recorded an impairment of $51,000,000 as of June 30, 2006 based on oil and gas prices of $59.87 per barrel and $5.42 per mcf.

Capitalized Interest

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Interest costs capitalized during the six months ended June 30, 2007 were $250,228. No interest was capitalized during the six months ended June 30, 2006.

Wells in Progress

Wells in progress at June 30, 2007 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, 2006 represented the costs associated with the drilling of two wells in the Riverbend area of Utah and one well in the Greater Green River Basin in Wyoming. These costs were reclassified into proved properties.

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 began operations during the fourth quarter of 2006 and 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 $115,187 was recorded as a credit to proved properties during the six months ended June 30, 2007.

The oil and gas equipment owned by the Company is depreciated using the straight-line method over the estimated useful life of the equipment of five to ten years for the equipment and twenty years for the drilling rig. The rental of some of the equipment 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 rental of $818,125 and $194,543 was recorded as a credit to proved properties during the six months ended June 30, 2007 and 2006, respectively.

Deferred Financing Costs

Deferred financing costs include the costs associated with the Company’s issuance of $65,000,000 of Convertible Notes during October 2004, which are being amortized over the seven year life of the notes; and the debt issuance costs incurred in connection with the Company’s credit facility, further described in Note 4, which are being amortized over the four year term of the credit facility.

Asset Retirement Obligation

The Company follows Statement of Financial Accounting Standards (“SFAS”) SFAS No. 143, “Accounting for Asset Retirement Obligations, “ which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are also included in the ceiling test calculation. Gasco’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties. The asset retirement liability will be allocated to operating expense by using a systematic and rational method. The information below reconciles the carrying value of the asset retirement obligation for the periods presented.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
Balance beginning of period	$	957,634	$	243,669	$	908,543	$	223,947
Liabilities incurred		47,091		43,716		74,667		58,100
Liabilities settled		—		—		—		—
Revisions		—		69,533		—		69,533
Accretion expense		22,927		8,165		44,442		13,503

Balance end of period	$	1,027,652	$	365,083	$	1,027,652	$	365,083

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 June 30, 2007, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

Revenue Recognition

The Company records revenues from the sales of natural gas and crude oil when delivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred.

The Company records rental income associated with the lease of its drilling rig to a third party for the drilling of wells, in which the Company has no ownership interest, in accordance with the underlying lease terms.

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 only after the shares become fully vested. Diluted net income per common share includes the potential dilution that could occur upon exercise of the options to acquire common stock 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 June 30, 2007, potential common stock equivalents of 25,836,838 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.

Recently Issued Accounting Pronouncements

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

The Company adopted the provisions of FIN 48 on January 1, 2007. FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax

positions recognized in the financial statements in accordance with SFAS No. 109. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. The adoption of FIN 48 had an immaterial impact on the Company’s consolidated financial position and did not result in unrecognized tax benefits being recorded. Accordingly, no corresponding interest and penalties have been accrued. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2003 and for state and local tax authorities for years before 2002. The Company does, however, have prior year net operating losses which remain open for examination.

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

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB 108 was effective for the Company on January 1, 2007. The adoption of SAB 108 had no impact on the Company’s financial position or results from operations.

In December 2006, the FASB issued FASB Staff Position (“FSP”) EITF 00-19-2, “Accounting for Registration Payment Arrangements.” This FSP specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement should be separately recognized and measured in accordance with FASB Statement No. 5, “Accounting for Contingencies”. This FSP is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to December 21, 2006, the guidance in the FSP was effective January 1, 2006 for the Company. The adoption of this FSP had no impact on our financial position or results from operations.

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for the Company’s financial statements issued in 2008. The Company is currently evaluating the impact that the adoption of SFAS No. 159 might have on its financial position or results of operations.

Reclassifications

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

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/A for the year ended December 31, 2006 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 and six months ended June 30, 2007 and 2006, the Company recognized stock-based compensation as follows:


	Three Months Ended June 30,					Six Months Ended June 30,
	2007		2006			2007		2006
Stock-based compensation expense	$	886,498	$	1,180,360		$	1,848,057	$	2,327,536
Consultant compensation capitalized as proved property		8,076		(106,288	)		12,291		51,471

Total stock-based compensation	$	878,422	$	1,286,648		$	1,835,766	$	2,276,065

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 $8,933 and $14,465 for the three and six months ending June 30, 2007, respectively. Of this $8,933 and $14,465 of total calculated compensation expense for non-employees for the three and six months ending June 30, 2007 $857 and $2,174 was expensed and $8,076 and $12,291 was capitalized relating to drilling personnel, respectively. Stock-based non-employee compensation or (reduction in) expense was $(107,356) and $58,004 for the three and six months ending June 30, 2006, respectively. Of this $(107,356) and $58,004 of total calculated compensation expense for non-employees for the three and six months ending June 30, 2006 $(1,068) and $6,533 was expensed and $(106,288) and $51,471 was capitalized relating to drilling personnel, respectively.

Stock Options

The following table summarizes the stock option activity in the equity incentive plans from January 1, 2007 through June 30, 2007:


			Weighted-
			Average Exercise
	Stock Options		Price
Outstanding at January 1, 2007		9,878,502	$	2.74
Granted		75,000	$	1.80
Exercised		—		—
Forfeited		—		—
Cancelled		366,664	$	3.21
Outstanding at June 30, 2007		9,586,838	$	2.71
Exercisable at June 30, 2007		7,967,383	$	2.29

The following table summarizes information related to the outstanding and vested options as of June 30, 2007:


	Outstanding
	Options		Vested options
Number of shares		9,586,838		7,967,383
Weighted Average Remaining Contractual Life		6.32		5.77
Weighted Average Exercise Price	$	2.71	$	2.29
Aggregate intrinsic value	$	4,290,522	$	4,247,772

The aggregate intrinsic value in the table above represents the total pretax intrinsic value, based on the Company’s closing common stock price of $2.37 on the last trading date of the quarter which was June 29, 2007, which would have been received by the option holders had all option holders exercised their options as of that date.

The total grant date fair value of the shares vested during the three and six months ended June 30, 2007 was $1,347,927 and $1,926,798, respectively.

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

As of June 30, 2007, there was $4,332,962 of total unrecognized compensation cost related to non-vested options granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 3.8 years.

Restricted Stock

The following table summarizes the restricted stock activity from January 1, 2007 through June 30, 2007:


			Weighted-Average
	Restricted		Grant Date
	Stock		Fair Value
Outstanding at January 1, 2007		365,920	$	2.39
Granted		60,000	$	2.32
Vested		228,510	$	1.89
Forfeited		1,750	$	2.90
Outstanding at June 30, 2007		195,660	$	2.94

As of June 30, 2007, there was $473,483 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a period of 3.1 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 and secured by a pledge of the capital stock of our 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 from $25,000,000 to $37,000,000 during February 2007. 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 June 30, 2007, there were loans of $12,000,000 outstanding at an interest rate of 6.875% 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.

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 June 30, 2007, the Company was and the Company is currently, in compliance with each of the covenants contained in the Credit Agreement.

The Company incurred $240,262 in debt issuance costs associated with this facility. These costs have been recorded as deferred financing costs in the accompanying financial statements and are being amortized over the four year term of the credit facility. The credit facility is available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes. The Credit Agreement provides for semi-annual evaluation of the borrowing base, which will be determined as a percentage of the discounted present value of the Company’s oil and natural gas reserves.

NOTE 5 – STOCK TRANSACTIONS

On April 13, 2007, Gasco issued 10,000,000 shares of common stock in a public offering for gross proceeds of $19,300,000. The offering costs associated with this transaction were $105,729. Gasco is using the net proceeds from the offering for general corporate purposes.

During the second quarter of 2007, 81,006 shares of the Company’s common stock were cancelled in satisfaction of the income tax liability of $205,760 associated with the vesting of restricted stock.

During the six months ended June 30, 2007, the Company’s Board of Directors approved the issuance of 60,000 shares of common stock, under the Gasco Energy, Inc. Amended and Restated 2003 Restricted Stock Plan, to certain of the Company’s employees and consultants. The restricted shares vest 20% on the first anniversary, 20% on the second anniversary and 60% on the third anniversary of the awards. The shares fully vest upon certain events, such as a change in control of the Company, expiration of the individual’s employment agreement and termination by the Company of the individual’s employment without cause. Any unvested shares are forfeited upon termination of employment for any other reason. The compensation expense related to the restricted stock was measured on the issuance date using the trading price of the Company’s common stock on that date and is amortized over the three-year vesting period. The shares of restricted stock are considered issued and outstanding at the date of grant and are included in shares outstanding for the purposes of computing diluted earnings per share. The Company also granted 75,000 options to purchase shares of common stock to its employees, at an exercise price of $1.80 per share. The options vest 16 2/3% at the end of each four-month period after the issuance date.

NOTE 6 – COMMITMENTS

Gasco has entered into a contract with a gas purchaser to sell its production at current prices. The contract requires Gasco to deliver 18,000 MMBTU of production each day. The Company has elected the normal purchase and sale exemption under paragraph 10(b) of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” because the Company anticipates that (1) it will produce the volumes required to be delivered under the terms of the contract, (2) it is probable the delivery will be made to the counterparty and (3) the counterparty will fulfill their contractual obligations under the terms of the contracts. As such, the Company is not required to treat the contract as a derivative and the contract will not be marked to market under the provisions of SFAS No. 133.

On September 20, 2006, Gasco entered into an agreement to purchase Brek Energy Corporation (“Brek”) for equity consideration of approximately 11,000,000 shares of common stock valued at approximately $26,070,000 based on the closing price of Gasco’s stock on the last trading date of the quarter which was June 29, 2007. As a result of the acquisition, Gasco will acquire approximately 16,750 net acres in the Uinta Basin of Utah and approximately 6,807 net acres in the Green River Basin of Wyoming. The acquisition is expected to simplify Gasco’s acreage portfolio by absorbing a working interest partner that previously owned approximately 14% of Gasco’s undeveloped acreage in Utah and 11% in Wyoming. Gasco does not expect to incur any additional overhead expenses as a result of the acquisition. The boards of directors of both Brek and Gasco have each approved the terms of the transaction, which is expected to close later in 2007. The completion of the transaction is subject to the approval of the stockholders of Brek and the completion of a distribution of certain subsidiaries of Brek to its stockholders.

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

NOTE 7 – STATEMENT OF CASH FLOWS

During the six months ended June 30, 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 $74,667.

	-		Stock-based compensation of $12,291 capitalized as proved property.

	-		Additions to oil and gas properties included in accounts payable of $3,018,890.

	-		Capitalization of interest expense of $250,228.

	-		Cancellation of 81,006 shares of common stock in satisfaction of income taxes of $205,760 related to the vesting of restricted stock.

During the six months ended June 30, 2006, the Company’s non-cash investing and financing activities consisted of the following transactions:

	-		Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $127,633.

	-		Stock-based compensation of $51,471 capitalized as proved property.

	-		Additions to oil and gas properties included in accounts payable of $469,623.

	-		Conversion of 763 shares of Preferred Stock into 479,599 shares of common stock.

	-		Write-off of fully depreciated furniture and fixtures of $2,592.

Cash paid for interest during the six months ended June 30, 2007 and 2006 was $2,224,245 and $1,787,500, respectively. There was no cash paid for income taxes during the six months ended June 30, 2007 and 2006.

NOTE 8 – SUBSEQUENT EVENT

On August 1, 2007, Gasco entered into a definitive agreement with a subsidiary of NFR Energy, LLC (“NFR”) whereby the subsidiary of NFR will participate in a 30-well drilling program in Gasco’s Riverbend Project. NFR has agreed to participate in 30 wells drilled by Gasco in 2007 and into early 2008. The terms of the agreement allow for NFR to earn two-thirds of Gasco’s interest in each 40-acre drilling location, 100 feet below total depth drilled, in exchange for paying its share of the costs including a per-well location fee paid to Gasco as the operator of the project. The agreement covers substantially all of Gasco’s 2007 drilling program, retroactive for wells drilled year-to-date, and as such includes 13 gross operated wells spudded (3.5 net to Gasco’s interest and 6.9 net to NFR) in 2007. At signing, Gasco received cash consideration of $19,031,602 for the aforementioned wells and in wells expected to be spud prior to August 1, 2007.

The general terms of the agreement are as follows:

	-		The agreement consists of Gasco’s leasehold position in portions of Uintah County, Utah and does not include assets in California, Nevada or Wyoming.

	-		The drilling program targets Wasatch, Mesaverde and Blackhawk development locations.

	-		Gasco can continue to independently develop its acreage.

Upon completion of the initial 30-well program, NFR will have earned approximately 67% of Gasco’s interest in 1,200 gross acres in the Riverbend Project.

NOTE 9 – 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: 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 June 30, 2007
(Unaudited)


				Guarantor
	Parent			Subsidiaries			Eliminations		Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4,151,269		$	646,196		$	—	$	4,797,465
Restricted investment		1,787,500			—			—		1,787,500
Short-term investments		2,000,000			—			—		2,000,000
Accounts receivable		—			5,537,478			—		5,537,478
Inventory		—			1,175,491			—		1,175,491
Prepaid expenses		477,357			—			—		477,357

Total		8,416,126			7,359,165			—		15,775,291

PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved mineral interests		19,315			205,173,639			—		205,192,954
Unproved mineral interests		756,277			8,444,415			—		9,200,692
Wells in progress		—			1,248,697			—		1,248,697
Gathering assets		—			13,812,061			—		13,812,061
Facilities and equipment		—			9,137,623			—		9,137,623
Furniture, fixtures and other		264,773			—			—		264,773

Total		1,040,365			237,816,435			—		238,856,800
Less accumulated depreciation, depletion and amortization		(132,463	)		(138,922,168	)		—		(139,054,631	)

Total		907,902			98,894,267			—		99,802,169

OTHER ASSETS
Deferred financing costs		2,112,390			—			—		2,112,390
Intercompany		202,988,423			(202,988,423	)		—		—

Total		205,100,813			(202,988,423	)		—		2,112,390

TOTAL ASSETS	$	214,424,841		$	(96,734,991	)		—	$	117,689,850


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	26,557		$	4,147,809		$	—	$	4,174,366
Revenue payable		—			1,596,503			—		1,596,503
Advances from joint interest owners		—			1,126,241			—		1,126,241
Accrued interest		869,312			—			—		869,312
Accrued expenses		290,000			—			—		290,000

Total		1,185,869			6,870,553			—		8,056,422

NONCURRENT LIABILITIES								��
5.5% Convertible Senior Notes		65,000,000			—			—		65,000,000
Long-term debt		12,000,000			—			—		12,000,000
Asset retirement obligation					1,027,652			—		1,027,652
Deferred rent expense		68,103			—			—		68,103

Total		77,068,103			1,027,652			—		78,095,755

STOCKHOLDERS’ EQUITY
Common stock		8,615			—			—		8,615
Other		136,162,254			(104,633,196	)		—		31,529,058

Total		136,170,869			(104,633,196	)		—		31,537,673

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	214,424,841		$	(96,734,991	)	$	—	$	117,689,850

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


				Guarantor
	Parent			Subsidiaries			Eliminations		Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10,831,082		$	2,045,797		$	—	$	12,876,879
Restricted investment		3,575,000			—			—		3,575,000
Short-term investments		6,000,000			—			—		6,000,000
Accounts receivable		—			9,037,036			—		9,037,036
Inventory		—			1,297,498			—		1,297,498
Prepaid expenses		618,505			25,985			—		644,490

Total		21,024,587			12,406,316			—		33,430,903

PROPERTY, PLANT AND EQUIPMENT,at cost
Oil and gas properties (full cost method)
Proved mineral interests		7,024			159,400,457			—		159,407,481
Unproved mineral interests		506,049			12,032,018			—		12,538,067
Wells in progress		—			5,215,252			—		5,215,252
Gathering assets		—			12,703,346			—		12,703,346
Facilities and equipment		—			8,492,632			—		8,492,632
Furniture, fixtures and other		241,009			—			—		241,009

Total		754,082			197,843,705			—		198,597,787
Less accumulated depreciation, depletion and amortization		(101,985	)		(68,843,794	)		—		(68,945,779	)

Total		652,097			128,999,911			—		129,652,008

OTHER ASSETS
Deferred financing costs		2,371,507			—			—		2,371,507
Intercompany		154,960,689			(154,960,689	)		—		—

Total		157,332,196			(154,960,689	)		—		2,371,507

TOTAL ASSETS	$	179,008,880		$	(13,554,462	)		—	$	165,454,418


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES				��
Accounts payable	$	218,366		$	16,009,690		$	—	$	16,228,056
Revenue payable		—			1,678,427			—		1,678,427
Advances from joint interest owners		—			2,955,376			—		2,955,376
Accrued interest		844,102			—			—		844,102
Accrued expenses		595,000			—			—		595,000

Total		1,657,468			20,643,493			—		22,300,961

NONCURRENT LIABILITES
5.5% Convertible Senior Notes		65,000,000			—			—		65,000,000
Asset retirement obligation		—			908,543			—		908,543
Deferred rent expense		72,993			—			—		72,993

Total		65,072,993			908,543			—		65,981,536

STOCKHOLDERS’ EQUITY
Common stock		8,617			—			—		8,617
Other		112,269,802			(35,106,498	)		—		77,163,304

Total		112,278,419			(35,106,498	)		—		77,171,921

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	179,008,880		$	(13,554,462	)	$	—	$	165,454,418

Consolidating Statements of Operations
(Unaudited)


				Guarantor
For the Three Months Ended June 30, 2007	Parent			Subsidiaries			Eliminations			Consolidated
REVENUES
Oil, and gas	$	—		$	5,124,207		$	—		$	5,124,207
Gathering		—			1,521,961			(1,049,580	)		472,381
Rental income		—			343,875			—			343,875
Interest income		170,986			21			—			171,007

Total		170,986			6,990,064			(1,049,580	)		6,111,470


OPERATING EXPENSES
Lease operating		—			1,852,292			(1,049,580	)		802,712
Gathering operations		—			552,231			—			552,231
Depletion, depreciation, amortization and impairment		15,875			3,351,522			—			3,367,397
Impairment		—			64,300,000			—			64,300,000
General and administrative		2,220,578			—			—			2,220,578
Interest expense		1,163,194			—			—			1,163,194

Total		3,399,647			70,056,045			(1,049,580	)		72,406,112


NET LOSS	$	(3,228,661	)	$	(63,065,981	)	$	—		$	(66,294,642	)


					Guarantor
For the Three Months Ended June 30, 2006	Parent				Subsidiaries			Eliminations			Consolidated
REVENUES
Oil and gas	$	—		��	$	4,610,072		$	—		$	4,610,072
Gathering		—				880,096			(510,840	)		369,256
Interest income		804,973				27			—			805,000

Total		804,973				5,490,195			(510,840	)		5,784,328


OPERATING EXPENSES
Lease operating		—				1,377,589			(510,840	)		866,749
Gathering operations		—				371,583			—			371,583
Depletion, depreciation and amortization		13,070				2,930,461			—			2,943,531
Impairment		—				51,000,000			—			51,000,000
General and administrative		2,589,007				—			—			2,589,007
Interest expense		1,049,541				—			—			1,049,541

Total		3,651,618				55,679,633			(510,840	)		58,820,411


NET LOSS	$	(2,846,645	)		$	(50,189,438	)	$	—		$	(53,036,083	)

Consolidating Statements of Operations
(Unaudited)


				Guarantor
For the Six Months Ended June 30, 2007	Parent			Subsidiaries			Eliminations			Consolidated
REVENUES
Oil and gas	$	—		$	10,976,912		$	—		$	10,976,912
Gathering		—			2,939,510			(1,980,463	)		959,047
Rental income		—			343,875			—			343,875
Interest income		271,322			45			—			271,367

Total		271,322			14,260,342			(1,980,463	)		12,551,201


OPERATING EXPENSES
Lease operating		—			3,379,437			(1,980,463	)		1,398,974
Gathering operations		—			906,951			—			906,951
Depletion, depreciation and amortization		30,478			5,673,037			—			5,703,515
Impairment		—			64,300,000			—			64,300,000
General and administrative		4,546,655			—			—			4,546,655
Interest expense		2,165,922			—			—			2,165,922

Total		6,743,055			74,259,425			(1,980,463	)		79,022,017


NET LOSS	$	(6,471,733	)	$	(59,999,083	)	$	—		$	(66,470,816	)


				Guarantor
For the Six Months Ended June 30, 2006	Parent			Subsidiaries			Eliminations			Consolidated
REVENUES
Oil and gas	$	—		$	10,539,749		$	—		$	10,539,749
Gathering		—			1,907,435			(1,055,040	)		852,395
Interest income		1,651,652			54			—			1,651,706

Total		1,651,652			12,447,238			(1,055,040	)		13,043,850


OPERATING EXPENSES
Lease operating		—			2,451,804			(1,055,040	)		1,396,764
Gathering		—			759,376			—			759,376
Depletion, depreciation and amortization		28,611			5,741,462			—			5,770,073
Impairment		—			51,000,000			—			51,000,000
General and administrative		5,170,136			102,907			—			5,273,043
Interest expense		2,057,834			—			—			2,057,834

Total		7,256,581			60,055,549			(1,055,040	)		66,257,090


NET LOSS		(5,604,929	)		(47,608,311	)		—			(53,213,240	)
Preferred stock dividends		(1,393	)		—			—			(1,393	)


NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(5,606,322	)	$	(47,608,311	)	$	—		$	(53,214,633	)

Consolidating Statements of Cash Flows
(Unaudited)


				Guarantor
For the Six Months Ended June 30, 2007	Parent			Subsidiaries			Eliminations		Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(5,610,086	)	$	10,308,197		$	—	$	4,698,111

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(23,764	)		—			—		(23,764	)
Cash paid for acquisitions, development and exploration		—			(49,735,532	)		—		(49,735,532	)
Proceeds from sale of short-term investments		4,000,000			—			—		4,000,000
Cash undesignated as restricted		1,787,500			—			—		1,787,500

Net cash provided by (used in) investing activities		5,763,736			(49,735,532	)		—		(43,971,796	)


CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit		12,000,000			—			—		12,000,000
Proceeds from the issuance of common stock		19,300,000			—			—		19,300,000
Cash paid for offering costs		(105,729	)		—			—		(105,729	)
Intercompany		(38,027,734	)		38,027,734			—		—

Net cash provided by (used in) financing activities		(6,833,463	)		38,027,734			—		31,194,271


NET DECREASE IN CASH AND CASH EQUIVALENTS		(6,679,813	)		(1,399,601	)				(8,079,414	)
CASH AND CASH EQUIVALENTS:

BEGINNING OF PERIOD		10,831,082			2,045,797			—		12,876,879

END OF PERIOD	$	4,151,269		$	646,196		$	—	$	4,797,465


For the Six Months Ended June 30, 2006				Guarantor
	Parent			Subsidiaries			Eliminations		Consolidated
CASH FLOWS USED IN OPERATING ACTIVITIES	$	(3,178,774	)	$	7,521,447		$	—	$	4,342,673

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other		(59,071	)		—			—		(59,071	)
Cash paid for acquisitions, development and exploration		—			(33,692,479	)		—		(33,692,479	)
Investment in short-term investments		(15,000,000	)		—			—		(15,000,000	)
Cash designated as restricted		(71,436	)		—			—		(71,436	)
Cash undesignated as restricted		8,351,500			—			—		8,351,500

Net cash provided by (used in) investing activities		(6,779,007	)		(33,692,479	)		—		(40,471,486	)


CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends		(1,393	)		—			—		(1,393	)
Exercise of options to purchase common stock		1,275,985			—			—		1,275,985
Cash paid for debt issuance costs		(240,262	)							(240,262	)
Intercompany		(24,417,027	)		24,417,027			—		—

Net cash provided by financing activities		(23,382,697	)		24,417,027			—		1,034,330


NET DECREASE IN CASH AND CASH EQUIVALENTS		(33,340,478	)		(1,754,005	)				(35,094,483	)

CASH AND CASH EQUIVALENTS:

BEGINNING OF PERIOD		59,314,343			3,347,025			—		62,661,368

END OF PERIOD	$	25,973,865		$	1,593,020		$	—	$	27,566,885

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 and Dakota/Morrison formations.

Our realized gas prices during the first six months of 2007 have decreased in comparison to the average gas price realized during the year ended December 31, 2006. These low prices are due in part to gas on gas sales competition in the Rockies resulting from the region’s capacity to produce natural gas exceeding the take-away capacity of interstate pipelines that move the natural gas to other consuming regions in the United States. As a result of the seasonally low natural gas prices received, we have elected to curtail production from some of our existing gas wells and will bring this production back on line when natural gas prices improve. We continue to experience higher drilling and operating costs resulting from increased fuel and steel costs and from increased drilling activity in this area.

Recent Developments

Drilling Activity

During the six months ended June 30, 2007, we spudded 13 gross wells (approximately 10.1 net wells) and reached total depth on 13 gross wells (approximately 9.4 net wells) in the Riverbend area. We also participated in one outside-operated well in Utah (0.25 net) and one well in Nevada (0.20 net). We also conducted initial completion operations on nine operated wells (6.2 net wells) and re-entered one operated well (1.0 net well) to complete pay zones that were behind pipe. We also participated in the completion of one outside-operated well (0.25 net well). As of June 30, 2007, we operated 98 gross wells with eight additional wells awaiting completion activities. As of August 1, 2007 we have an inventory of 24 operated wells with up-hole recompletion opportunities and three drilling rigs operating in the Uinta Basin Riverbend project. The average drilling time to total depth on the last 10 Gasco-operated wells that both spud and reached total depth during the first six months of 2007 was 18.6 days with the longest taking 25 days and the shortest taking 14 days. Reducing drilling days is a cost saving component within our control that we are intently focused

upon in order to lower our per-well investment in an effort to continue improving economics in the Riverbend play.

We have drilled a well in the Muddy Creek Prospect in Wyoming to test natural gas potential in two formations to a revised proposed depth of 14,400 feet. Intermediate casing was set at approximately 9,600 feet, and the rig was released and drilling operations were suspended due to winter lease stipulations. Due to the continued low natural gas prices discussed above, management has not determined when drilling operations on this well are expected to resume because the potential reserves associated with this well are uneconomic at current prices.

Forward Sales Contract

During April 2007, we entered into a sales and firm transportation agreement for 18,000 MMBTU per day, at the first of the month IFERC CIG index price, net of transportation, marketing and fuel expenses. We have elected the normal purchase and sale exemption under paragraph 10(b) of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” because we anticipate that (1) we will produce the volumes required to be delivered under the terms of the contract, (2) it is probable the delivery will be made to the counterparty and (3) the counterparty will fulfill its contractual obligations under the terms of the contracts. As such, we are not required to treat the contract as a derivative and the contract will not be marked to market under the provisions of SFAS No. 133.

Property Impairment

Management believes that the current low natural gas prices received in the Rockies, as discussed previously, has caused the potential resources related to our Wyoming acreage to become uneconomic. During 2006, we began drilling a well in the Muddy Creek Prospect in Wyoming to test natural gas potential in two formations to a proposed depth of 14,400 feet. Intermediate casing was set at approximately 9,600 feet when drilling operations were suspended due to winter lease stipulations. Since it was our intention to continue drilling operations on this well in July 2007, this well was classified as a well in progress at December 31, 2006 and at March 31, 2007. The low natural gas prices in this area have made it difficult for us to find a partner to participate in the drilling of this well and as a result, management has revised its original plans for this well and no longer has current plans to recommence drilling operations on this well. Therefore the total well costs of approximately $3,925,000 have been reclassified from wells in progress into proved property during the second quarter of 2007. Additionally, approximately $6,230,000 of unproved leasehold costs related to our Wyoming acreage was reclassified to proved property during the quarter ended June 30, 2007. Both of these amounts totaling $10,155,000 were included in the ceiling test and depletion calculations.

We utilize the full cost method of accounting, under which capitalized oil and gas property costs less accumulated depletion, net of deferred income taxes (full cost pool) may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued in the balance sheet plus the cost, or estimated fair value, if lower of unproved properties and the costs of any properties not being amortized, if any. Should the full cost pool exceed this

ceiling, an impairment is recognized. This impairment is recorded as non-cash expense and is not permitted to be reversed in future periods in the event that oil and gas prices subsequently increase resulting in a higher ceiling. The present value of estimated future net revenues is computed by applying current prices of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. However, subsequent commodity price increases may be utilized to calculate the ceiling value.

As of June 30, 2007, based on oil and gas prices of $54.09 per barrel and $3.90 per mcf, the full cost pool exceeded the above described ceiling by $66,700,000. However, subsequent to quarter end, oil and gas prices increased; and using these prices our full cost pool exceeded the ceiling limitation by $64,300,000. Therefore, impairment expense of $64,300,000 was recorded during the six months ended June 30, 2007.

Stock Offering

On April 13, 2007, Gasco issued 10,000,000 shares of common stock in a public offering for gross proceeds of $19,300,000. The offering costs associated with this transaction were $105,729. Gasco intends to use the net proceeds from the offering for general corporate purposes.

Drilling Program

The general terms of the agreement are as follows:

	-		The agreement consists of Gasco’s leasehold position in portions of Uintah County, Utah and does not include assets in California, Nevada or Wyoming.

	-		The drilling program targets Wasatch, Mesaverde and Blackhawk development locations.

	-		Gasco can continue to independently develop its acreage.

	-		Upon completion of the initial 30-well program, NFR will have earned approximately 67% of Gasco’s interest in 1,200 gross acres in the Riverbend Project.

Proposed Acquisition

On September 20, 2006, Gasco entered into an agreement to purchase Brek Energy Corporation (“Brek”) for equity consideration of approximately 11,000,000 shares of common stock valued at approximately $26,070,000 based on the closing price of Gasco’s stock on last trading date of the quarter which was June 29, 2007. As a result of the acquisition, Gasco will acquire approximately 16,750 net acres in the Uinta Basin of Utah and approximately 6,807 net acres in the Green River Basin of Wyoming. The acquisition is expected to simplify Gasco’s acreage portfolio by absorbing a working interest partner that previously owned approximately 14% of Gasco’s undeveloped acreage in Utah and 11% in Wyoming. Gasco does not expect to incur any additional overhead expenses as a result of the acquisition. The boards of directors of both Brek and Gasco have each approved the terms of the transaction, which is expected to close later in 2007. The completion of the transaction is subject to the approval of the stockholders of Brek and the completion of a distribution of certain subsidiaries of Brek to its stockholders.

Oil and Gas Production Summary

The following table presents Gasco’s production and price information during the three and six months ended June 30, 2007 and 2006. The Mcfe calculations assume a conversion of 6 Mcf for each Bbl of oil.


	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2007		2006		2007		2006
Natural gas production (Mcf)		1,052,401		832,724		2,052,718		1,709,295
Average sales price per Mcf	$	4.31	$	5.18	$	4.88	$	5.86

Oil production (Bbl)		11,928		5,003		20,319		9,077
Average sales price per Bbl	$	49.34	$	59.40	$	47.71	$	58.36

Production (Mcfe)		1,123,969		862,742		2,174,632		1,763,757

During the three and six months ended June 30, 2007 the Company’s oil and gas production increased by approximately 30% and 23% primarily due to the Company’s drilling projects, completions, and recompletions that took place during 2006 and 2007. The increased production was partially offset by normal production declines from wells drilled during earlier periods. The production increase during 2007 was partially offset by our decision to curtail production on some of our existing wells due to the low natural gas prices as discussed above.

Liquidity and Capital Resources

The following table summarizes Gasco’s sources and uses of cash for each of the six months ended June 30, 2007 and 2006.


	For the Six Months Ended
	June 30,
	2007			2006
Net cash provided by operations	$	4,698,111		$	4,342,336
Net cash used in investing activities		(43,971,796	)		(40,471,486	)
Net cash provided by financing activities		31,194,271			1,034,330
Net decrease in cash		(8,079,414	)		(35,094,483	)

Cash provided by operations increased by $355,775 from 2006 to 2007. The 23% increase in equivalent oil and gas production during 2007 was partially offset by an 18% decrease in oil prices and a 17% decrease in gas prices. The production increase is due primarily to our drilling activity during 2006 and 2007.

Our investing activities during the six months ended June 30, 2007 and 2006 related primarily to our development and exploration activities. The 2007 activity also included proceeds from the sale of short-term investments of $4,000,000 and the release of restricted cash of $1,787,500. The 2006 investing activities also included investments in short-term investments of $15,000,000 and the release of restricted cash of $8,351,500.

The financing activity during 2007 is comprised of borrowings under our line of credit of $12,000,000 and the net proceeds of $19,194,271 from the issuance of common stock. The 2006 activity includes the exercise of options to purchase 447,911 shares of Gasco common stock for proceeds of $1,275,985 partially offset by the payment of cash for debt issuance costs of $240,262 and the payment of preferred dividends of $1,393.

Capital Budget

The budget for our 2007 capital expenditure program is $40 million, net of the proceeds received in connection with the closing of our drilling program agreement with NFR as discussed previously. The program will primarily cover the drilling and completion of at least 10 net wells on our Riverbend Project. The budget also includes expenditures for the installation of associated pipeline infrastructure, distribution facilities and geophysical operations.

Our budget for our 2007 capital program reflects our commitment to build upon our historical successes and continue our efforts to demonstrate the economic viability of our resource in the Uinta Basin of Utah. Economic viability of this resource play is a function of the price of natural gas and oil, well investment, well operating cost and well performance. If the estimated capital investment based on recent historical data to drill and complete wells in this area is not reduced materially, if the estimated well performance based on recent historical performance data in this area is not increased materially or if the prices for oil and gas do not increase materially from year end 2006 prices we will be unable to economically develop most of our acreage in the Uinta Basin of Utah.

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

Schedule of Contractual Obligations

The following table summarizes our obligations and commitments to make future payments under our notes payable, operating leases, employment contracts, consulting agreement and service contracts for the periods specified as of June 30, 2007.


	Payments due by Period
			Less than 1						More than 5
Contractual Obligations	Total		year		1-3 years		3-5 years		years
Convertible Notes
Principal	$	65,000,000	$	—	$	—	$	65,000,000	$	—
Interest		15,243,403		3,575,000		7,150,000		4,518,403		—
Long-term debt		12,000,000		—		—		12,000,000		—
Drilling Rig Contracts *		27,279,000		14,490,000		12,789,000		—		—
Operating Leases		1,077,614		422,849		654,765		—		—
Employment Contracts		274,167		274,167		—		—		—
Consulting Agreements		3,600		3,600		—		—		—

Total Contractual Cash Obligations	$	120,877,784	$	18,765,616	$	20,593,765	$	81,518,403	$	—


*		The three year drilling contract for the new-build rig contains a provision that permits us to terminate the contract for $12,000 per day for the number days remaining in the original contract.

We have not included asset retirement obligations as discussed in Note 2 of the accompanying financial statements, as we cannot determine with accuracy the timing of such payments.

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.

As of June 30, 2007, based on oil and gas prices of $54.09 per barrel and $3.90 per mcf, the full cost pool exceeded the above described ceiling by $66,700,000. However, subsequent to quarter end, oil and gas prices increased; and using these prices our full cost pool exceeded the ceiling limitation by $64,300,000. Therefore, impairment expense of $64,300,000 was recorded during the six months ended June 30, 2007.

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, 2006 present value of future net cash flows of approximately $2,180,900. 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.

During the six months ended June 30, 2007, approximately $6,230,000 of unproved leasehold costs related to our Wyoming acreage was reclassified to proved property and was included in the ceiling test and depletion calculations. Management believes that the continued low natural gas prices received in the Rockies have caused the potential resources related to our Wyoming acreage to become uneconomic.

Stock-Based Compensation

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards “SFAS” No. 123(R), “Accounting for Stock-Based Compensation” which requires companies to recognize

compensation cost for stock-based awards based on the estimated fair value of the award. Compensation cost is measured at the grant date based on the fair value of the award and is recognized as an expense over the service period, which generally represents the vesting period. 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.

Prior to the adoption of SFAS No. 123(R), we had followed Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees”, and related interpretations, through December 31, 2005 for accounting for stock option awards to employees and directors which resulted in the accounting for grants of awards to employees and directors at their intrinsic value in the consolidated financial statements. We had previously adopted the provisions of FAS No. 123, “Accounting for Stock-Based Compensation”, as amended by FAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure”, through disclosure only.

On January 1, 2006, we adopted SFAS No. 123(R), “Accounting for Stock-Based Compensation,” using the modified prospective method. Under the modified prospective method, the adoption of SFAS No. 123(R) applies to new awards and to awards modified, repurchased, or cancelled after December 31, 2005, as well as to the unvested portion of awards outstanding as of January 1, 2006. In accordance with the modified prospective method, we have not adjusted the financial statements for periods ended prior to January 1, 2006. We did not recognize any one time effects of the adoption and continued to use similar option valuation models and assumptions as were used prior to January 1, 2006. The total fair-value-based compensation expense associated with prior awards that was not vested on the date of the adoption of SFAS No. 123(R) was approximately $4,800,000 which was expected to be recognized over the weighted average remaining life of the options of approximately one year.

Results of Operations

The Second Quarter of 2007 compared to the Second Quarter of 2006

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
	June 30,
	2007		2006
Natural gas production (Mcf)		1,052,401		832,724
Average sales price per Mcf	$	4.31	$	5.18
Natural gas revenue	$	4,535,627	$	4,312,905

Oil production (Bbl)		11,928		5,003
Average sales price per Bbl	$	49.34	$	59.40
Oil revenue	$	588,580	$	297,167

The increase in oil and gas revenue of $514,135 during the second quarter of 2007 compared with the second quarter of 2006 is comprised of a 30% increase in oil and gas production primarily due to the drilling and completion activity during 2007 and 2006 partially offset by a decrease in the average gas price of $0.87 per Mcf and a decrease of $10.06 in the average oil price during 2007. The production increase during 2007 was partially offset by our decision to curtail production on some of our existing wells due to the low natural gas prices as discussed previously. The $514,135 increase in oil and gas revenue during the second quarter of 2007 represents an increase of $1,290,197 related to the production increase partially offset by a decrease of $776,062 related to the decrease in oil and gas prices.

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 $106,652 during the second quarter of 2007 as compared with the second quarter of 2006 due to the increased production resulting from our drilling activity in this area. The increase in gathering expense of $147,575 during the second quarter of 2007 is primarily due to increased operating and compression expenses related to the increased production transported through the system.

Rental Income

Rental income during the second quarter of 2007 represents the revenue from the rental of our drilling rig to outside operated wells in which we do not have an ownership interest during the last two months of the second quarter of 2007.

Interest Income

Interest income decreased $633,993 during the second quarter of 2007 compared with the second quarter of 2006 primarily due to lower average cash and cash equivalent balances during 2007 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
	June 30,
	2007		2006
Direct operating expenses and overhead	$	511,581	$	532,344
Workover expense		108,422		200,025

Total operating expenses	$	620,003	$	732,369

Operating expenses per Mcfe	$	0.55	$	0.85

Production and property taxes	$	182,709	$	134,380

Production and property taxes per Mcfe	$	0.16	$	0.15

Total lease operating expense per Mcfe	$	0.71	$	1.00

Lease operating expense decreased $64,037 during the second quarter of 2007 compared with the second quarter of 2006. The decrease is comprised of a $20,763 decrease in operating expenses primarily due to lower water disposal costs during 2007, a $91,603 decrease in workover expense due to fewer projects during 2007 combined with a $48,329 increase in production taxes primarily due to the increase in the number of producing wells from 51 wells at June 30, 2006 to 98 wells at June 30, 2007 and the expiration of a severance tax holiday for the first six months of production.

Depletion, Depreciation and Amortization

Depletion, depreciation and amortization expense during the second quarters of 2007 and 2006 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 $423,866 is due primarily to the increase in oil and gas production and related capital costs resulting from our increased drilling activity as well as the unproved property impairment related to the Wyoming acreage as discussed above.

Impairment

As of June 30, 2007, based on oil and gas prices of $54.09 per barrel and $3.90 per mcf, the full cost pool exceeded the above described ceiling by $66,700,000. However, subsequent to quarter end, oil and gas prices increased; and using these prices our full cost pool exceeded the ceiling limitation by $64,300,000. Therefore, impairment expense of $64,300,000 was recorded during the six months ended June 30, 2007. The impairment expense of $51,000,000 during the second quarter of 2006 was based on oil and gas prices of $59.87 per barrel and $5.42 per mcf.

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
	June 30,
	2007			2006
Total general and administrative costs	$	1,630,169		$	1,401,210
General and administrative costs allocated to drilling, completion and operating activities		(288,013	)		(98,851	)

General and administrative expense	$	1,342,156		$	1,302,359

General and administrative expenses per Mcfe	$	1.19		$	1.51


Total stock-based compensation costs	$	886,498		$	1,180,360
Stock-based compensation costs capitalized		(8,076	)		106,288

Stock-based compensation	$	878,422		$	1,286,648

Stock-based compensation per Mcfe	$	0.78		$	1.49


Total general and administrative expense including stock-based compensation	$	2,220,578		$	2,589,007


Total general and administrative expense per Mcfe	$	1.97		$	3.00

General and administrative expense decreased by $368,429 during the second quarter of 2007 as compared with the second quarter of 2006. The decrease is primarily due to a decrease in consulting and legal expenses partially offset by increased compensation expense due to the hiring of additional employees during the last quarter of 2006. Additionally the allocation of certain drilling, completion and production overhead related to specific projects increased during the second quarter of 2007 due primarily to the increase in the number of wells we operate. The decrease in stock-based compensation expense is due primarily to certain stock options and restricted stock becoming fully vested and to the cancellation or forfeiture of options and restricted stock during the first six months of 2007.

Interest Expense

Interest expense increased $113,653 during the second quarter of 2007 as compared with the second quarter of 2006. The increase is comprised of additional interest expense incurred on the $12,000,000 of borrowings under our line of credit during the first quarter of 2007 partially offset by $163,704 in capitalized interest during the second quarter of 2007.

The First Six Months of 2007 Compared to the First Six Months of 2006

The comparisons for the six months ended June 30, 2007 and the six months ended June 30, 2006 are consistent with those discussed in the second quarter of 2007 compared to the second quarter of 2006 except as discussed below:


	For the Six Months Ended
	June 30,
	2007		2006
Natural gas production (Mcf)		2,052,718		1,709,295
Average sales price per Mcf	$	4.88	$	5.86
Natural gas revenue	$	10,007,565	$	10,010,020

Oil production (Bbl)		20,319		9,077
Average sales price per Bbl	$	47.71	$	58.36
Oil revenue	$	969,347	$	529,729

The increase in oil and gas revenue of $437,163 during the first six months of 2007 compared with the first six months of 2006 is comprised of an increase in oil and gas production of 11,242 Bbls and 344,423 Mcf partially offset by a decrease in the average oil price of $10.65 per bbl and a decrease in the average gas price of $0.98 per Mcf during 2007. The $437,163 increase in oil and gas revenue during the first six months of 2007 represents an increase of $2,215,057 related to the production increase and a decrease of $1,777,894 related to the decrease in oil and gas prices. The increase in production is described above.

Recently Issued Accounting Pronouncements

In September 2006, the 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. The Statement is to be effective for the Gasco’s financial statements issued in 2008; however, earlier application is encouraged. We are

currently evaluating the timing of adoption and the impact that adoption might have on our financial position or results of operations.

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB 108 was effective for Gasco on January 1, 2007. The adoption of SAB 108 had no impact on our financial position or results from operations.

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for Gasco’s financial statements issued in 2008. We are currently evaluating the impact that the adoption of SFAS No. 159 might have on our financial position or results of operations.

Cautionary Statement Regarding Forward-Looking Statements

In the interest of providing the stockholders with certain information regarding the Company’s future plans and operations, certain statements set forth in this Form 10-Q relate to management’s future plans and objectives. Such statements are forward-looking statements within the meanings of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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. In addition, 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 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 the Company expectations (“Cautionary Statements”) include those discussed under the caption “Risk Factors”, in Item 1A hereof and in the Company’s Form 10-K/A for the year ended December 31, 2006. 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 the Cautionary Statements. 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 in this annual report.

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

Bbl/d. One Bbl per day.

Bcf. Billion cubic feet of natural gas.

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

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

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

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

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

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

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

Proved properties. Properties with proved reserves.

Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves may not include estimates attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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

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

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

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

Unproved properties. Properties with no proved reserves.

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

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk relates to changes in the pricing applicable to the sales of gas production in the Uinta Basin of northeastern Utah and the Greater Green River Basin of west central Wyoming. This risk will become more significant to us as more wells are drilled and begin producing in these areas. We also have market risk related to the interest rate on borrowings under our Credit Agreement. Interest on borrowings under the Credit Agreement accrues at variable interest rates at either, at our election, a Eurodollar rate or an alternative base rate. Although we are not using derivatives at this time to mitigate the risk of adverse changes in commodity prices or interest rates, we may consider using them in the future.

ITEM 4 – CONTROLS AND PROCEDURES

Our management has evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2007. 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 June 30, 2007, 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

None.

Item 1A – Risk Factors

Information about material risks related to our business, financial condition and results of operations for the three months ended June 30, 2007, does not materially differ from that set out in Part I, Item 1A of the Company’s Annual Report on 10-K/A for the year ended December 31, 2006, other than the following two additional risk factors:

Pipeline constraints may limit Gasco’s ability to sell its gas production and may negatively affect the price at which Gasco sells its gas.

Gasco’s production is transported through a single intrastate pipeline and therefor any constraints on the capacity of this pipeline could adversely affect its ability to sell Gasco’s production. Additionally, many pipelines, particularly those connecting to higher-priced eastern markets, are operating at or near capacity. Management believes that this situation could continue, at least, into early 2008. In certain circumstances this may limit Gasco’s ability to sell any, or all, of its natural gas production in a given period. As producers vie one with another to sell their gas, this situation may also serve to reduce the price at which Gasco is able to sell the gas that does flow. During the second quarter of 2007, Gasco curtailed a portion of its natural gas production due to the low price for natural gas that prevailed in the Rockies. These low prices are due in part to gas on gas sales competition resulting from the region’s capacity to produce natural gas exceeding the take-away capacity of interstate pipelines that move the natural gas to other consuming regions in the United States. A reduction in the amount of natural gas that Gasco can sell or the price at which such natural gas can be sold could materially adversely affect Gasco’s financial position and results of operations.

Gasco’s officers and directors are engaged in other businesses which may result in conflicts of interest.

Certain of Gasco’s officers and directors also serve as directors of other companies or have significant shareholdings in other companies. Gasco’s chairman, Marc A. Bruner, is the largest shareholder of Galaxy Energy Corporation (“Galaxy”) and Exxcel Energy. Mr. Marc A. Bruner also serves as the Chairman and Chief Operating Officer of Falcon Oil and Gas, Ltd. (“Falcon”). Falcon’s current drilling activities include projects in Romania and Hungary. Carl Stadelhofer, one of Gasco’s directors is a director of Falcon. In addition, another Gasco director, C. Tony Lotito, currently serves as the Executive Vice President, Chief Financial Officer, Secretary-Treasurer and a member of the Board of Directors of PetroHunter Corporation (“PetroHunter”), which is majority owned by Mr. Marc A. Bruner. Charles Crowell, one of Gasco’s directors, is the Chief Executive Officer and serves on the Board of Directors of PetroHunter. Mr. Crowell also serves on the Boards’ of Directors of Providence Resources, Inc. Richard S. Langdon, another one of Gasco’s directors, is President and Chief Executive Officer of Matris Exploration Company, L.P., a private exploration and production company active in onshore California. Mr. Langdon is also a member of the Board of Directors of Constellation Energy Partners LLC (“CEP”), a public limited liability company focused on the acquisition, development and exploitation of oil and natural gas properties and related midstream assets. CEP’s activities are currently focused in the Black Warrior Basin of Alabama. Another one of Gasco’s directors, Richard Burgess, is a director of ROC Oil Company (“ROC”), a Limited Liability Corporation incorporated in Australia. ROC has oil and gas activities in China, Australia, UK North Sea, and West Africa. ROC has no activities in North or South America. Gasco estimates that all of its directors except Mr. Crowell spend approximately 10% of their time on Gasco business and Mr. Crowell spends approximately 25% of his time on Gasco business. Mark Erickson, Gasco’s CEO, President and director has direct private investments in certain Rocky Mountain and Mid-Continent oil and gas leases and has a majority interest in a private oil and gas company with core assets in Oklahoma and additional lease holdings in Colorado, Wyoming and Utah. Mr. Erickson is also a co-majority shareholder in a private company engaged in the exploration of non-oil and gas mineral resources in the Republic of Guinea, Africa. Mr. Erickson spends 100% of his time on Gasco business.

To the extent that such other companies participate in ventures in which Gasco may participate, or compete for prospects or financial resources with it, these officers and directors will have a conflict of interest in negotiating and concluding terms relating to the extent of such participation. In the event that such a conflict of interest arises at a meeting of the board of directors, a director who has such a conflict must disclose the nature and extent of his interest to the board of directors and abstain from voting for or against the approval of such participation or such terms.

In accordance with the laws of the State of Nevada, Gasco’s directors are required to act honestly and in good faith with a view to the best interests of Gasco. In determining whether or not Gasco will participate in a particular program and the interest therein to be acquired by it, the directors will primarily consider the degree of risk to which Gasco may be exposed and its financial position at that time.

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

The following table presents information about repurchases of our common stock during the three months ended June 30, 2007:

Total Number of

Maximum Number

Total

Shares Purchased

of Shares That May

Number

Average

as Part of Publicly

Yet Be Purchased

of Shares

Price Paid

Announced Plans

Under the Plans

Period

Purchased^(a)

Per Share^(a)

or Programs

or Programs^(b)

June 1, 2007 through June 30, 2007

81,006

2.54

—

Total

81,006

2.54

—


(a)		Represents the surrender to the Company of 81,006 shares of common stock to pay withholding taxes in connection with the vesting of employee restricted stock.

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

Item 3 – Defaults Upon Senior Securities

None.

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

The Company held its Annual Meeting (“Annual Meeting”) of Stockholders on May 15, 2007. The meeting was held to elect eight directors to serve until the 2008 Annual Meeting of Stockholders and to ratify the selection of Hein & Associates LLP as independent auditors of the Company for the year ending December 31, 2007.

The “For” column represents the number of affirmative votes, and the “withheld” column represents the number of abstentions and broker non-votes, by holders of common and preferred stock represented by either proxy or in person at the Annual Meeting. The results of the voting related to the elections of the nominees for director were as follows:


Name	For		Withheld
Marc A. Bruner		68,532,427		11,564,935
Richard J. Burgess		78,729,559		1,367,803
Charles B. Crowell		76,198,131		3,899,231
Mark A. Erickson		69,622,730		10,474,632
Richard S. Langdon		78,619,877		1,477,485
Carmen J. (Tony) Lotito		73,943,146		6,154,216
John Schmit		76,145,131		3,952,231
Carl Stadelhofer		76,216,707		3,880,655

Stockholders voted 76,518,703 shares “for” and 3,499,910 shares “against” the proposal to ratify the selection of Hein & Associates LLP as independent auditors of the Company for the fiscal year ending December 31, 2007, with 78,193 votes abstaining.

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)).

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)).


Exhibit Number		Exhibit

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

3.1		Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).

3.2		Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).

3.3		Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).


Exhibit Number		Exhibit

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, 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 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


Exhibit Number		Exhibit

		year ended December 31, 2003, filed on March 26, 2004, File No. 000-26321).

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

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

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

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

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

4.13		Voting Agreement dated September 20, 2006 by and among Gasco Energy, Inc., Richard N. Jeffs, Gregory Pek, Ian Robinson, Michael L. Nazmack, Eugene Sweeney and Shawne Malone (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).

4.14		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).


Exhibit Number		Exhibit

#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.

*31		Rule 13a-14(a)/15d-14(a) Certifications.

*32		Section 1350 Certifications


*		Filed 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: August 1, 2007	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)).


Exhibit Number		Exhibit

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

3.1		Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).

3.2		Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).

3.3		Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).


Exhibit Number		Exhibit

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, 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 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


Exhibit Number		Exhibit

		year ended December 31, 2003, filed on March 26, 2004, File No. 000-26321).

4.8		Indenture dated as of October 20, 2004, between Gasco Energy, Inc. and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).
4.9		Form of Global Note representing $65 million principal amount of 5.5% Convertible Senior Notes due 2011 (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).

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

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

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

4.13		Voting Agreement dated September 20, 2006 by and among Gasco Energy, Inc., Richard N. Jeffs, Gregory Pek, Ian Robinson, Michael L. Nazmack, Eugene Sweeney and Shawne Malone (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).

4.14		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).


Exhibit Number		Exhibit

#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.

*31		Rule 13a-14(a)/15d-14(a) Certifications.

*32		Section 1350 Certifications


*		Filed herewith.

#		Identifies management contracts and compensating plans or arrangements.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Avg

Gasco Energy (GSXN) Inactive 10-Q2007 Q2 Quarterly report

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