Gasco Energy (GSXN) 10-Q 2010 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2010

OR

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

FOR THE TRANSITION PERIOD FROM         TO        

Commission File Number: 001-32369

GASCO ENERGY, INC.

(Exact name of registrant as specified in its charter)

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)

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

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

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

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

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

Number of common shares outstanding as of November 2, 2010: 117,246,749

Table of Contents

Part I
Item 1.	Condensed Financial Statements (Unaudited)	3
	Condensed Consolidated Balance Sheets	3
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	39
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 4.	Controls and Procedures	64
Part II
Item 1.	Legal Proceedings	65
Item 1A.	Risk Factors	65
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	65
Item 6.	Exhibits	65

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ITEM I — FINANCIAL STATEMENTS

PART 1 — FINANCIAL INFORMATION

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,611,792		$	10,577,340
Accounts receivable
Joint interest billings	1,280,378			857,405
Revenue	2,461,940			2,979,726
Inventory	1,779,480			1,019,913
Derivative instruments	940,011			—
Prepaid expenses	7,122			292,421
Total	10,080,723			15,726,805
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved properties	258,543,654			254,682,870
Unproved properties	38,291,679			38,638,936
Facilities and equipment	1,029,750			971,890
Furniture, fixtures and other	283,807			333,049
Total	298,148,890			294,626,745
Less accumulated depletion, depreciation, amortization and impairment	(229,936,128		)	(227,291,163		)
Total	68,212,762			67,335,582
Assets held for sale, net of accumulated depreciation	—			20,155,544
Total	68,212,762			87,491,126
OTHER ASSETS
Deposit	639,500			139,500
Note receivable	500,000			500,000
Deferred financing costs	1,384,334			884,282
Total	2,523,834			1,523,782
TOTAL ASSETS	$	80,817,319		$	104,741,713

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

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GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

(Unaudited)

	September 30,			December 31,
	2010			2009
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable	$	684,413		$	1,110,259
Revenue payable	2,925,640			2,245,545
Advances from joint interest owners	2,064,152			—
Current portion of long-term debt	5,544,969			—
Derivative instruments	—			1,932,513
Accrued interest	701,066			844,108
Accrued expenses	1,045,000			1,215,106
Total	12,965,240			7,347,531
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes due 2011	400,000			65,000,000
5.5% Convertible Senior Notes due 2015, net of unamortized discount of $26,329,390	18,838,610			—
Long-term debt	—			34,544,969
Deferred income from sale of assets	2,918,694			—
Derivative instruments	—			761,092
Asset retirement obligation related to assets held for sale	—			206,595
Asset retirement obligation	1,094,602			1,054,370
Deferred rent expense	—			20,555
Total	23,251,906			101,587,581
STOCKHOLDERS’ EQUITY (DEFICIT)
Series B Convertible Preferred stock - $0.001 par value; 20,000 shares authorized; zero shares outstanding	—			—
Series C Convertible Preferred stock - $0.001 par value; 2,000,000 shares authorized; 305,754 shares outstanding	306			—
Common stock - $.0001 par value; 600,000,000 shares authorized; 107,768,897 shares issued and 107,695,197 outstanding as of September 30, 2010 and 107,789,597 shares issued and 107,715,897 outstanding as of December 31, 2009	10,776			10,779
Additional paid-in capital	257,202,570			221,327,257
Accumulated deficit	(212,483,184		)	(225,401,140		)
Less cost of treasury stock of 73,700 common shares	(130,295		)	(130,295		)
Total	44,600,173			(4,193,399		)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$	80,817,319		$	104,741,713

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

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GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months EndedSeptember 30,
	2010			2009
REVENUES
Gas	$	4,029,912		$	2,952,924
Oil	671,775			602,737
Gathering	—			882,195
Total	4,701,687			4,437,856
OPERATING EXPENSES
Lease operating	1,422,397			887,594
Gathering operations	—			479,668
Transportation and processing	801,938			—
Depletion, depreciation, amortization and accretion	817,986			982,182
Loss on sale of assets, net	79,837			155,536
General and administrative	1,225,048			1,861,101
Total	4,347,206			4,366,081
OPERATING INCOME	260,481			71,775
OTHER INCOME (EXPENSE)
Interest expense	(13,851,122		)	(1,420,025		)
Derivative gains (losses)	8,080,387			(1,571,682		)
Gain on extinguishment of debt	14,430			—
Amortization of deferred income from sale of assets	50,613			—
Interest income	7,113			13,203
Total	(5,698,579		)	(2,978,504		)
NET LOSS	$	(5,344,098	)	$	(2,906,729	)
NET LOSS PER COMMON SHARE BASIC AND DILUTED	$	(0.05	)	$	(0.03	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING - BASIC AND DILUTED	107,606,525			107,546,398

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

5

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Nine Months EndedSeptember 30,
	2010			2009
REVENUES
Gas	$	13,390,284		$	9,759,682
Oil	2,041,887			1,414,385
Gathering	595,942			2,723,325
Rental income	—			366,399
Total	16,028,113			14,263,791
OPERATING EXPENSES
Lease operating	3,893,737			2,667,580
Gathering operations	375,848			1,962,364
Transportation and processing	1,926,146			—
Depletion, depreciation, amortization and accretion	2,764,814			4,659,283
Impairment	—			41,000,000
Contract termination fee	—			4,701,000
Loss on sale of assets, net	34,726			834,725
General and administrative	5,142,871			5,731,145
Total	14,138,142			61,556,097
OPERATING INCOME (LOSS)	1,889,971			(47,292,306		)
OTHER INCOME (EXPENSE)
Interest expense	(16,260,691		)	(4,080,213		)
Derivative gains	11,368,447			721,885
Gain on extinguishment of debt	15,772,441			—
Amortization of deferred income from sale of assets	118,097			—
Interest income	29,691			19,025
Total	11,027,985			(3,339,303		)
NET INCOME (LOSS)	$	12,917,956		$	(50,631,609	)
NET INCOME (LOSS) PER COMMON SHARE – BASIC AND DILUTED	$	0.12		$	(0.47	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING - BASIC AND DILUTED	107,615,804			107,559,351

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

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GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	12,917,956		$	(50,631,609	)
Adjustment to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, amortization, accretion and impairment expense	2,764,814			45,659,283
Stock-based compensation	1,207,553			1,462,110
Gain on extinguishment of debt	(15,772,441		)	—
Change in fair value of derivative instruments	(10,474,008		)	12,070,025
Amortization of debt discount, deferred expenses and other	13,067,159			1,282,975
Changes in operating assets and liabilities:
Accounts receivable	94,813			6,729,214
Inventory	(805,493		)	3,174,505
Prepaid expenses	285,299			180,062
Accounts payable	(189,588		)	(2,122,789		)
Revenue payable	680,098			(1,561,380		)
Accrued interest	(141,650		)	559,649
Accrued expenses	(170,106		)	(278,000		)
Net cash provided by operating activities	3,464,406			16,524,045
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other	(16,683		)	(2,297		)
Cash paid for acquisitions, development and exploration	(5,135,129		)	(8,666,306		)
Proceeds from sale of assets	24,309,000			500,000
Increase (decrease) in advances from joint interest owners	2,064,152			(612,222		)
Net cash provided by (used in) investing activities	21,221,340			(8,780,825		)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit	—			13,000,000
Repayment of borrowings	(29,000,000		)	(9,455,031		)
Cash paid for debt issuance costs	(2,044,070		)	—
Cash paid for stock issuance costs	(52,824		)	—
Cash paid for repurchase of convertible notes	(54,400		)	—
Payment of deposit	(500,000		)	—
Net cash (used in) provided by financing activities	(31,651,294		)	3,544,969
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(6,965,548		)	11,288,189
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD	10,577,340			1,053,216
END OF PERIOD	$	3,611,792		$	12,341,405

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

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GASCO ENERGY, INC.

NOTES TO UNAUDITED CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2010 AND 2009

NOTE 1 — ORGANIZATION

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

The unaudited condensed consolidated financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States (“US GAAP”) applicable to interim financial statements and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods.  Such financial statements conform to the presentation reflected in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, as amended (“2009 10-K”) filed with the Securities and Exchange Commission (the “SEC”). The current interim period reported herein should be read in conjunction with the financial statements and accompanying notes, including Note 2 “Significant Accounting Policies,” included in the Company’s 2009 10-K.

The results of operations for the nine months ended September 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010. All significant intercompany transactions have been eliminated.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Oil and Gas Properties

The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, internal costs

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directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized internal costs of $54,853 and $83,906 during the three and nine months ended September 30, 2010, respectively, and none and $47,617 during the three and nine months ended September 30, 2009, respectively. Additionally, the Company capitalized stock compensation expense related to its drilling consultants as further described in Note 6 “Stock-Based Compensation” herein. Costs associated with production and general corporate activities are expensed in the period incurred. During April 2010, the Company began charging a marketing fee related to the sale of its natural gas production to the wells in which it is the operator and, therefore, the net income attributable to the outside working interest owners from the marketing activities of $40,396 and $96,633 were recorded as a credits to proved properties during the three and nine months ended September 30, 2010, respectively.  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 are computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include: (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion; (b) estimated future development costs to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties of $38,291,679 as of September 30, 2010 are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment.

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

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion (full cost pool) and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued in the balance sheet plus the cost, or estimated fair value if lower, of unproved properties and the costs of any properties not being amortized, if any, net of income taxes (ceiling limitation). Should the full cost pool exceed this ceiling limitation, an impairment is recognized. The present value of estimated future net revenues is computed by applying the average, first-day-of—the-month oil and gas price during the 12-month period ended September 30, 2010 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. As of December 31, 2009, the oil and gas accounting rules were revised. Prior to this date, proved oil and gas reserves were determined using the period-end price and subsequent commodity price increases could be utilized to calculate the ceiling value.

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As of March 31, 2009, the Company’s full cost pool exceeded the ceiling limitation, based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf, by $41,000,000. Therefore, an impairment expense of $41,000,000 was recorded during the nine months ended September 30, 2009. No impairment expense was recorded during the nine months ended September 30, 2010.

Facilities and Equipment

During 2006 and 2008, the Company constructed two evaporation pits in the Riverbend area of Utah that were used for the disposal of produced water from the wells that the Company operates in the area. The pits were depreciated using the straight-line method over their estimated useful lives of twenty-five years. The costs of water disposal into the evaporation pits were charged to wells operated by Gasco and, therefore, the net income (expense) attributable to the outside working interest owners from the evaporation pits of $0 and $106,433 for the three and nine months ended September 30, 2010, respectively, and $(22,874) and $24,636 during the three and nine months ended September 30, 2009, respectively, were recorded as adjustments to proved properties. These facilities were sold during February 2010 as described in Note 3 “Asset Sales and Purchases” herein.

The Company’s other oil and gas equipment is depreciated using the straight-line method over an estimated useful life of five to ten years for the equipment, twenty years for the drilling rig (sold in June 2009) and twenty five years for the facilities. The rental of the equipment owned by the Company is charged to the wells that are operated by the Company and, therefore, the net income or (expense) attributable to the outside working interest owners from the equipment rental of $81,582 and $22,472, and $(15,476) and $51,612 were recorded as adjustments to proved properties during the three and nine months ended September 30, 2010 and 2009, respectively.

Deferred Income from Sale of Assets

The deferred income from sale of assets represents the excess of proceeds received over the carrying value that was recorded in connection with the sale of the Company’s gathering assets and evaporative facilities in February 2010 as further described in Note 3 “Asset Sales and Purchases” herein. This income will be amortized over the fifteen-year terms of the gathering and salt water disposal contracts which were entered into at the time of the sale.

Derivatives

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The Company records all commodity derivative instruments at fair value within the accompanying unaudited condensed consolidated balance sheets. Changes in fair value are to be recognized currently in earnings unless specific hedge accounting criteria are met. Management has decided not to use hedge accounting under the accounting guidance for its commodity derivatives and therefore, the changes in fair value are recognized in earnings. In addition, as discussed in Note 4 “Convertible Senior Notes” herein, the Company accounted for the embedded conversion features related to the outstanding 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”), which were

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issued in June 2010 in the Exchange Transaction as derivatives until September 15, 2010. Changes in fair value were recorded in earnings.

Asset Retirement Obligation

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

	Three Months Ended September 30,				Nine Months EndedSeptember 30,
	2010		2009		2010			2009
Balance beginning of period	$	1,070,202	$	1,204,100	$	1,260,965		$	1,150,179
Liabilities incurred	—		—		2,100			225
Property dispositions	—		—		(242,981		)	—
Accretion expense	24,400		27,799		74,518			81,495
Balance end of period	$	1,094,602	$	1,231,899	$	1,094,602		$	1,231,899

Off Balance Sheet Arrangements

From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of September 30, 2010, the off-balance sheet arrangements and transactions that the Company had entered into include undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

Computation of Net Income (Loss) Per Share

Basic net income (loss) per share of common stock is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss)

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per share only after the shares become fully vested. Diluted net income per share of common stock includes both the vested and unvested shares of restricted stock. Diluted net income or loss per common share of stock is computed by dividing adjusted net income by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculation consist of unvested shares of restricted common stock, in-the-money outstanding options to purchase the Company’s common stock, the Company’s outstanding Series C Convertible Preferred Stock, par value $0.001 per share (“Preferred Stock”), which are convertible into shares of the Company’s common stock and the Company’s outstanding 2015 Notes and 5.5% Convertible Senior Noted due 2011 (the “2011 Notes” and together with the 2015 Notes, the “Convertible Senior Notes”) are convertible into shares of the Company’s common stock.

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

For the three and nine months ended September 30, 2010, common stock equivalents of 40,813,902 and 32,366,811, respectively and 28,567,537 common stock equivalents for the three and nine months ended September 30, 2009 were excluded from the computation of diluted net income (loss) per share because their inclusion would have been anti-dilutive.

Since the Company now has outstanding shares under two classes of stock, the net income (loss) per share must be reported for both the Preferred Stock and the common stock. As the net income (loss) per share for the Preferred Stock is immaterial, it is not presented as a separate line item in the accompanying unaudited condensed consolidated financial statements.

During October 2010, 57,912 shares of Preferred Stock were converted into 9,562,001 shares of common stock. Had this conversion occurred on September 30, 2010, the basic and diluted net income (loss) per share would have been $(0.05) and $0.11 for the three and nine months ended September 30, 2010, respectively.

Use of Estimates

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

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

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the fair value of financial instruments including derivative instruments and impairments to unproved property.

Reclassifications

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

Recently Issued Accounting Pronouncements

In January 2010, ASC guidance for fair value measurements and disclosure was updated to require additional disclosures related to transfers in and out of level 1 and 2 fair value measurements and enhanced detail in the level 3 reconciliation. The guidance was amended to clarify the level of disaggregation required for assets and liabilities and the disclosures required for inputs and valuation techniques used to measure the fair value of assets and liabilities that fall in either level 2 or level 3. The updated guidance was effective for the Company’s fiscal year beginning January 1, 2010, with the exception of the level 3 disaggregation which is effective for the Company’s fiscal year beginning January 1, 2011. The adoption had no impact on the Company’s consolidated financial position, results of operations or cash flows. Refer to Note 8 “Fair Value Measurement” herein for further details regarding the Company’s assets and liabilities measured at fair value.

NOTE 3 — ASSET SALES AND PURCHASES

Sale of Gathering Assets

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

Pursuant to the Purchase Agreement, simultaneous with Closing, Gasco entered into (i) a transition services agreement with Monarch pursuant to which the Company provided certain services relating to the operation of the Gathering Assets to Monarch for a six-month term commencing at Closing; (ii) a gas gathering agreement with Monarch pursuant to which the Company dedicated its natural gas production from all of its Utah acreage for a minimum fifteen-year period and Monarch provides gathering, compression and processing services utilizing the Gathering Assets to the Company; and (iii) a salt water disposal services agreement with Monarch pursuant to which the Company may deliver salt water produced by its operations to the evaporative facilities that Monarch acquired in the Asset Sale for a minimum 15-year period. The Purchase Agreement was subject to customary post-closing terms and conditions for transactions of this size and nature.

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The Company recognized deferred income of approximately $3 million on the Asset Sale which will be amortized over the fifteen-year terms of the gathering and salt water disposal contracts with Monarch.

The following pro forma information is presented as if the Asset Sale had an effective date of January 1, 2009.

	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	2010			2009			2010			2009
Revenue as reported	$	4,701,687		$	4,437,856		$	16,028,113		$	14,263,791
Less: revenue from sale of Gathering Assets	—			882,195			595,942			2,723,325
Pro forma revenue	$	4,701,687		$	3,555,661		$	16,624,055		$	11,540,466
Net income (loss) as reported	$	(5,344,098	)	$	(2,906,729	)	$	12,917,956		$	(50,631,609	)
Less: operating loss resulting from the Gathering Assets sale	—			(994,026		)	(824,337		)	(2,502,413		)
Pro forma net income (loss)	$	(5,344,098	)	$	(3,900,755	)	$	12,093,619		$	(53,134,022	)
Net income (loss) per share - basic and diluted as reported	$	(0.05	)	$	(0.03	)	$	0.12		$	(0.47	)
Less net income (loss) per share - from sale of Gathering Assets	0.00			(0.01		)	(0.01		)	(0.02		)
Pro forma net income (loss) per share basic and diluted	$	(0.05	)	$	(0.04	)	$	0.11		$	(0.49	)

Acquisition of Petro-Canada Assets

On February 25, 2010, the Company completed the acquisition of two wells and certain oil and gas leases (the “Petro-Canada Assets”) from Petro-Canada Resources (USA) Inc., a Colorado corporation (“Petro-Canada”), for a purchase price of approximately $482,000, subject to customary post-closing terms and conditions for transactions of this size and nature. The sale was made pursuant to a definitive agreement dated February 4, 2010 by and between the Company and Petro-Canada. The Petro-Canada Assets include one producing well, one shut in well with recompletion potential and 5,582 gross and net acres located in Utah, west of our Gate Canyons operating area. This acquisition was funded with cash flows from operating activities.

Sale of Partial Working Interest in Producing Wells

On March 19, 2010, the Company closed the sale of a partial working interest in 32 wells for $1.25 million. The 32 wells were part of a joint venture project that was started in 2002 under which each of the participants received a net profits interest in these wells for a period of twelve years from initial production date. the Company agreed to sell its interest in these wells related to the period subsequent to the initial twelve year period to one of the joint venture participants and to convert the purchaser’s net profits interest into a working interest. The proceeds received were recorded as a

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credit to the full cost pool during the nine months ended September 30, 2010 (during the first quarter of 2010).

Prospect Fee

During September 2010, Gasco entered into an arrangement with an exploration and production company which operates in California, pursuant to which the Company received a $1.5 million prospect fee related to certain of its California acreage. The fee reimburses costs that the Company has invested in the area and provides it with a potential carried interest of 20% in two wells to be drilled on the acreage.  Additionally, the farmee is obligated to obtain and provide to Gasco 3-D Seismic data over the contract area. The proceeds received were recorded as a credit to unproved properties during the nine months ended September 30, 2010 (during the third quarter of 2010).

NOTE 4 - CONVERTIBLE SENIOR NOTES

Exchange Transaction

On June 22, 2010, the Company entered into exchange agreements (collectively, the “Exchange Agreements”) with certain holders (collectively, the “Investors”) of its outstanding 2011 Notes. In accordance with the Exchange Agreements, on June 25, 2010 (the “Closing Date”), the Company exchanged $64,532,000 aggregate principal amount of its 2011 Notes (representing 99.28% of the then outstanding 2011 Notes) for $64,532,000 aggregate principal amount of the Company’s newly issued 2015 Notes, which are convertible, at the option of the holder, into shares of the Company’s common stock and/or shares of the Company’s Preferred Stock which are convertible into shares of common stock (the “Exchange Transaction”). The Company also paid to the Investors an aggregate cash amount of $788,724, equal to all accrued but unpaid interest with respect to the 2011 Notes as of but not including the Closing Date.

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

The 2015 Notes bear interest at a rate of 5.50% per annum, to be paid in arrears, on April 5 and October 5 of each year commencing on October 5, 2010.

As stated above, the 2015 Notes are convertible, at the option of the holder, at any time prior to maturity, into common stock or, at the election of such holder, into Preferred Stock. The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock, other than pursuant to an automatic conversion (described below), is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the Indenture, the Company could not issue shares of common stock to

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holders of the 2015 Notes (including shares of common stock issuable upon a conversion of the 2015 Notes or upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes or in payment of any change of control purchase price, make whole premium or conversion make whole payment (each as described in the Indenture)) in excess of 19.9% of the number of shares of common stock outstanding immediately prior to the closing of the Exchange Transaction (the “Exchange Cap”), until stockholder approval of the issuance of common stock in excess of the Exchange Cap was obtained or the Company obtained a written opinion from its outside counsel that such approval was not required. Additionally, pursuant to the Indenture, a holder may not convert all or any portion of such holder’s 2015 Notes into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion, beneficially own more than 4.99% of the outstanding shares of common stock (the “Maximum Ownership Percentage”), provided that such holder, upon not less than 61 days’ prior written notice to the Company, may increase the Maximum Ownership Percentage applicable to such holder (but, for the avoidance of doubt, not for any subsequent or other holder) to 9.9% of the outstanding shares of common stock.

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

Upon a change of control (as defined in the Indenture), each holder of 2015 Notes may require the Company to repurchase some or all of its 2015 Notes at a repurchase price equal to 100% of the aggregate principal amount of the 2015 Notes to be repurchased plus accrued and unpaid interest and liquidated damages, if any, to but not including the date of purchase, plus, in certain circumstances, a make whole premium. The Company may pay the change of control purchase price and/or the make whole premium in cash or shares of Preferred Stock at the Company’s option. In addition, in the case of the make whole premium, at the Company’s option, the Company may pay such premium in the same form of consideration used to pay for the shares of common stock in connection with the transaction constituting the change of control. On or after September 15, 2010 or to the extent the Company has exercised its provisional redemption right, holders of the 2015 Notes are permitted to convert the 2015 Notes in full, subject to the Maximum Ownership Percentage.

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

Events of default under the Indenture include (1) the Company’s failure to pay (in cash or, if applicable, shares of Preferred Stock) principal or premium (including any make whole premium or conversion make-whole payment) when due; (2) the Company’s failure to pay interest, including liquidated damages, if any, when due on the 2015 Notes, and such failure continues for 30 days after the date when due; (3) the Company’s failure to issue and deliver shares of common stock or Preferred Stock, and any cash in lieu of fractional shares, when such shares of common stock, Preferred Stock or cash in lieu of fractional shares is required to be delivered, and such failure continues for 10 days after the required delivery date; (4) the Company’s failure to give timely notice of a change of control; (5) during the required period, the Company’s failure to file certain reports, statements and other documents required to be filed by the Company with the SEC prior to the periods set forth in the Indenture; (6) the Company’s failure to perform or observe any other term, covenant or agreement in the 2015 Notes or the Indenture for 60 days after written notice of such failure has been given to the Company as provided in the Indenture; (7) the Company’s or that of its significant subsidiaries’ failure to make payments by the end of the applicable grace period, if any, on indebtedness for borrowed money in excess of $5 million or if indebtedness for borrowed money of the Company or a significant subsidiary in excess of $5 million is accelerated in certain circumstances; (8) certain events of bankruptcy, insolvency or reorganization with respect to the Company or a significant subsidiary or any of the Company’s subsidiaries which in the aggregate would constitute a significant subsidiary; and (9) a default occurs under any permitted subordinated indebtedness in excess of $2,000,000 individually or in the aggregate.

The 2015 Notes are unsecured and unsubordinated and rank on a parity in right of payment with all of the Company’s existing and future senior unsecured indebtedness (including any 2011 Notes that were not exchanged for 2015 Notes), rank senior in right of payment to any of the Company’s existing and future subordinated indebtedness, and are effectively subordinated in right of payment to any of the Company’s secured indebtedness or other obligations to the extent of the value of the assets securing such indebtedness or other obligations. The Company’s subsidiaries guarantee the 2015 Notes pursuant to a Guaranty Agreement dated as of June 25, 2010, by and among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of the Trustee.

The Company received stockholder approval for the issuance of all of the shares of common stock issuable upon conversion of the 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes in accordance with applicable law and the rules of the

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NYSE Amex at its 2010 Annual Meeting of Stockholders, which was held on September 15, 2010. As provided for in the Indenture, following receipt of the stockholder approval described above, an aggregate principal amount of 2015 Notes equal to the difference (but not less than zero) of (i) 30% of the original principal amount of all 2015 Notes minus (ii) the principal amount, if any, of the 2015 Notes that had been repaid, redeemed or repurchased by the Company, or converted into shares of common stock or Preferred Stock by holders of the 2015 Notes, automatically converted into a number of shares of Preferred Stock equal to the aggregate principal amount of such 2015 Notes to be so converted multiplied by 0.01579.

The Exchange Transaction was recorded as an extinguishment of debt whereby the difference between the fair value of the 2015 Notes and the carrying value of the 2011 Notes (inclusive of unamortized debt issuance costs), was recorded as a gain on the extinguishment of debt in the accompanying consolidated statement of operations. Prior to September 15, 2010, the date on which the Company received shareholder approval for the issuance of the shares of common stock to settle the conversion of the 2015 Notes, the conversion feature in the 2015 Notes was accounted for separately as an embedded derivative at fair value, yet presented together with the 2015 Notes, in the consolidated balance sheet.  The changes in the fair value of the embedded derivative through September 15, 2010 were reported as derivative gains (losses) in the consolidated statement of operations. On September 15, 2010, because shareholders approved the Company’s right to issue common stock to settle the conversion feature in the 2015 Notes, the fair value of the conversion feature at that date was reclassified to additional paid in capital under the provisions of ASC paragraph 815-15-40-1. The debt host component of the 2015 Notes was unaffected by this reclassification and continues to be accounted for on an amortized cost basis where the debt discount continued to be accreted to interest expense under the effective interest method at a rate of 26.3%.

On September 20, 2010, the Company effected the automatic conversion of $19,364,000 of the outstanding principal amount of the 2015 Notes into 305,754 shares of Preferred Stock which resulted in a reclassification of $306 and $19,363,694 into Preferred Stock, and additional paid-in capital, respectively. The Company paid an aggregate cash amount of $254,599, equal to all accrued but unpaid interest on the 2015 Notes subject to automatic conversion through the automatic conversion date of September 20, 2010.

On conversion of 30% of the original principal amount of the 2015 Notes on September 20, 2010, a pro-rata portion of the unamortized discount and debt interest costs were recorded as interest expense ($12 million) and the respective carrying amount of the 2015 Notes was reclassified from 5.5% Convertible Senior Notes due 2015 to Preferred Stock and Additional Paid-in Capital in the amounts of $306 and $19,363,694, respectively.

Note Purchase

During August 2010, the Company purchased $68,000 in principal value of its 2011 Notes including interest for $54,400. The difference between the purchase price and the principal value less unamortized debt issuance costs was recorded as a gain on the extinguishment of debt.

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NOTE 5 — DERIVATIVES

As of September 30, 2010 and December 31, 2009, natural gas derivative instruments consisted of two swap agreements for the gas production from 2009 through March 2011. The following table details the fair value of the derivatives recorded in the consolidated balance sheets, by category:

		Fair Value at
	Location on Consolidated Balance Sheets	September 30, 2010		December 31,2009
Natural gas derivative contracts	Current assets	$	940,011	$	—
Natural gas derivative contracts	Current liabilities	—		1,932,513
Natural gas derivative contracts	Noncurrent liabilities	—		761,092

These natural gas derivative instruments allow the Company to predict with greater certainty the effective natural gas prices to be realized for its production. For its swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three and nine months ended September 30, 2010 and 2009.

	Three Months EndedSeptember 30,					Nine Months Ended September 30,
	2010		2009			2010		2009
Realized gains on commodity instruments	$	645,956	$	1,031,459		$	894,439	$	12,791,910
Change in commodity instruments, net	594,039		(2,603,141		)	3,633,616		(12,070,025		)
Change in fair value of embedded derivative feature	6,840,392		—			6,840,392		—
Total realized and unrealized gains (losses) recorded	$	8,080,387	$	(1,571,682	)	$	11,368,447	$	_ 721,885

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

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As of September 30, 2010, the Company’s swap agreements for 2010 through March 2011 are summarized in the table below:

Agreement Type	RemainingTerm	Quantity	Fixed PriceCounterparty payer	Floating Price (a)Gasco payer
Swap (b)	10/10 — 12/10	3,500 MMBtu/day	$4.418/MMBtu	NW Rockies
Swap	10/10 — 3/11	3,000 MMBtu/day	$4.825/MMBtu	NW Rockies
Swap (b)	1/11 — 3/11	2,000 MMBtu/day	$4.418/MMBtu	NW Rockies

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

(b)Includes information pertaining to a portion of a single natural gas derivative contract with declining volumes. The fixed price represents the weighted average price for the entire contract period from June 2009 through March 2011.

During October 2010, the Company entered into an additional swap agreement for the  year ended December 31, 2011 for 2,000 MMBtu/day with a fixed price of $4.00/MMBtu at a Northwest Pipeline Rocky Mountains — Inside FERC first of month index price.

See Note 4 “Convertible Senior Notes” herein for discussion of embedded derivatives relating to convertible debt.

NOTE 6 — STOCK-BASED COMPENSATION

The Company has outstanding common stock options and restricted stock issued under its equity incentive plans. The Company measures the fair value at the grant date for stock option grants and restricted stock awards and records compensation expense over the requisite service period.

The Company accounts for stock compensation arrangements with non-employees using a fair value approach. Under this approach, the stock compensation related to the unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair value on that date. During the three and nine months ended September 30, 2010 and 2009, the Company recognized stock-based compensation as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
Employee compensation	$	333,111		$	490,371	$	1,211,511		$	1,452,946
Consultant compensation (reduction in compensation)	(761		)	15,286		(5,687		)	14,348
Total stock-based compensation	332,350			505,657		1,205,824			1,467,294
Less: consultant compensation expense (reduction in expense) capitalized as proved property	(359		)	7,638		1,729			5,184
Stock-based compensation expense	$	332,709		$	498,019	$	1,207,553		$	1,462,110

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Stock Options

The following table summarizes the stock option activity in the equity incentive plans from January 1, 2010 through September 30, 2010:

	Shares Underlying Stock Options		Weighted-Average Exercise Price
Outstanding at January 1, 2010	12,096,672		$	1.82
Granted	871,000		$	0.36
Exercised	—		—
Forfeited	(86,547	)	$	1.64
Cancelled	(691,392	)	$	2.46
Outstanding at September 30, 2010	12,189,733		$	1.68
Exercisable at September 30, 2010	10,304,373		$	1.92

During the nine months ended September 30, 2010, the Company granted 871,000 options to purchase 50,000, 175,000 and 646,000 shares of common stock with exercise prices of $0.34, $0.35 and $0.36 per share, respectively. These options have a two year vesting period and expire within five years of the grant date. These options are subject to shareholder approval and may not be exercised until approval is received. These options are accounted for using a fair value approach. Under this approach, the stock compensation related to these unvested stock options is recalculated at the end of each reporting period based upon the fair value on that date.

The following table summarizes information related to the outstanding and vested options as of September 30, 2010:

	Outstanding Options		Vested options
Number of shares	12,189,733		10,304,373
Weighted Average Remaining Contractual Life	3.45		3.22
Weighted Average Exercise Price	$	1.68	$	1.86
Aggregate intrinsic value	$	3,200	$	2,133

The aggregate intrinsic value in the table above represents the total pretax intrinsic value, which is the amount by which the fair value of the Company’s stock at September 30, 2010 of $0.30 exceeds the exercise price of certain outstanding options.

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

As of September 30, 2010, there is $646,264 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 2 years.

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Restricted Stock

The following table summarizes the restricted stock activity from January 1, 2010 through September 30, 2010:

	Restricted Stock		Weighted-Average Grant Date Fair Value
Outstanding at January 1, 2010	140,500		$	2.39
Granted	—		—
Vested	(32,200	)	$	1.90
Forfeited	(20,700	)	$	2.83
Outstanding at September 30, 2010	87,600		$	2.45

As of September 30, 2010, there is $66,979 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a period of 2 years.

NOTE 7 — CREDIT FACILITY

The Company’s $250 million revolving credit facility (“Credit Facility”) is available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes. Borrowings made under the Credit Facility are secured by a pledge of the capital stock of certain of the Company’s subsidiaries and mortgages on substantially all of the Company’s oil and gas properties. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2011.

On February 1, 2010, the Company entered into the Ninth Amendment to Credit Facility, pursuant to which the Credit Facility was amended to, among other things, (i) remove the scheduled redetermination of the borrowing base on or about January 30, 2010, with the effect that scheduled redeterminations for the year ended December 31, 2010 revert to the regular redetermination schedule of every six months on or about May 1 and November 1 of each year, and (ii) reduce the borrowing base to $16 million from $35 million by incremental fixed amounts in connection with certain contemplated asset sales, and, effective as of April 1, 2010, to automatically reduce the borrowing base to $16 million, regardless of whether any of the contemplated asset sales were consummated. The Ninth Amendment also provided for the release of certain liens relating to those assets that secure the Company’s obligations under the Credit Facility.  Effective February 26, 2010, in connection with the consummation of the sale of the Gathering Assets and the application of the proceeds of $23 million therefrom to pay down outstanding borrowings, the Company elected to reduce the borrowing base to $16 million effective immediately as further discussed in Note 3 “Asset Sales and Purchases” herein.

The Ninth Amendment also increased the interest rate pricing grid by 25 basis points for Eurodollar based loans and for alternate base rate (“ABR”) priced loans effective February 1, 2010. Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an ABR. The Eurodollar rate is calculated as LIBOR plus an applicable margin that, as amended, varies

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from 2.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 3.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The ABR, as amended, is equal to the sum of (i) the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50% and (c) the Adjusted LIBOR for a one month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 2.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The Company elects the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the Lenders may require the Company to use the non-elected basis in the event that the elected basis does not adequately and fairly reflect the cost of making such loans. The interest rate on our Credit Facility is 3.06% as of September 30, 2010.

On June 22, 2010, in connection with the Exchange Transaction, the Company entered into the Tenth Amendment to the Credit Facility pursuant to which the Credit Facility was amended to, among other things, permit (i) the Company’s incurrence of indebtedness under the 2015 Notes, (ii) the Company’s Subsidiaries’ guarantee of the 2015 Notes; (iii) the Company’s incurrence of indebtedness and related liens relating to certain insurance policies; (iv) the interest payments and equity payments (of common stock and Preferred Stock) required under the 2015 Notes; and (v) and the exchange of the 2011 Notes for the 2015 Notes and other transactions and requirements contemplated by the Exchange Transaction further described in Note 4 “Convertible Senior Notes” herein.

The Credit Facility requires the Company to comply with financial covenants that require it to maintain (1) a current ratio (defined as current assets plus unused availability under the Credit Facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1.0; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Facility) for the most recent four quarters not to be greater than 3.5:1.0 for each fiscal quarter.  In addition, the Credit Facility contains covenants that restrict the Company’s ability to incur other indebtedness, create liens or sell the Company’s assets, pay dividends on the Company’s common stock and make certain investments. Sustained or lower oil and natural gas prices could reduce the Company’s consolidated EBITDAX and thus could reduce the Company’s ability to maintain existing levels of bank debt or incur additional indebtedness. Any failure to be in compliance with any material provision or covenant of the Credit Facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under the Credit Facility.  Additionally, should the Company’s obligation to repay indebtedness under the Credit Facility be accelerated, the Company would be in default under the indentures governing the Convertible Senior Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such Convertible Senior Notes.  To the extent it becomes necessary to address any anticipated covenant compliance issues, the Company will seek to obtain a waiver or amendment of the Credit Facility from the Lenders, and in the event that such waiver or amendment is not granted, the Company may be required to sell a portion of its assets or issue additional securities, which would be dilutive to the Company’s shareholders.  Any sale of assets or issuance of additional securities may not be on terms acceptable to the Company.

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As of September 30, 2010, the Company’s current and senior debt to EBITDAX ratios are 2.6:1.0 and 0.6:1.0, respectively, and the Company is in compliance with each of the covenants contained in the Credit Facility.

As of September 30, 2010, there are loans of $5,544,969 outstanding and our available credit was approximately $10.5 million.

NOTE 8 — FAIR VALUE MEASUREMENTS

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

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

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

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

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
Assets:
Commodity derivatives	$	—	$	940,011	$	—	$	940,011
Liabilities	$	—	$	—	$	—	$	—

As of September 30, 2010, the Company’s commodity derivative financial instruments are comprised of two natural gas swap agreements. The fair values of the swap agreements are determined based primarily on inputs that are derived from observable data at commonly quoted intervals for the full term of the derivatives and are, therefore, considered level 2 in the fair value

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hierarchy. The Company determines the fair value of these swap contracts under the income approach using a discounted cash flows model. The valuation models require a variety of inputs, including contractual terms, projected gas market prices, discount rate and credit risk adjustments, as appropriate. The Company has consistently applied this valuation technique in all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds. The counterparty in all of the Company’s commodity derivative financial instruments is the Administrative Agent under the Credit Agreement. See Note 6 “Credit Facility” herein.

During June 2010, we accounted for the embedded cash conversion features related to the 2015 Notes at fair value. The value of the this feature was derived based on both observable and unobservable pricing inputs and, therefore, the data sources utilized in this valuation model were considered level 3 inputs in the fair value hierarchy. The Company determined the fair value of the derivatives under the income approach using an option pricing model that required inputs such as the trading price of the Company’s stock, time value, price volatility of the Company’s common stock and considerations of the Company’s credit risk. The Company believes it has obtained and applied the most accurate information available for this type of derivative. On September 15, 2010, the Company received shareholder approval to issue stock rather than cash upon the conversion of the 2015 Notes. The receipt of shareholder approval resulted in the embedded derivative feature no longer requiring fair value accounting and was reclassified to additional paid in capital. See Note 4 “Convertible Senior Notes” herein for discussion of embedded derivatives relating to convertible debt.

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

	2015 Notes
Balance as of January 1, 2010	$	—
Total gains (realized or unrealized):
Included in earnings	6,840,392
Included in other comprehensive income	—
Issuances	(22,199,008		)
Settlements	15,358,616
Transfers in and out of level 3	—
Balance as of September 30, 2010	$	—
Change in unrealized gains included in earnings relating to instruments still held as of September 30, 2010	$	—

Other financial instruments not measured at fair value on a recurring basis include cash and cash equivalents, accounts receivable, note receivable, accounts payable, accrued liabilities, 2011 Notes and long-term debt. With the exception of the note receivable, 2011 Notes and long-term debt, the financial statement carrying amounts of these items approximate their fair values due to their short-term nature. The carrying amount of long-term debt approximates the fair value due to its floating rate structure. The carrying amount of the Company’s note receivable approximates fair value based

25

on current interest rates for similar instruments. The estimated fair value of the 2015 Notes as of September 30, 2010 was $28,128,000 determined using a discounted cash flow and option pricing model. Estimated fair values for 2011 Notes of $312,000 and $40,218,750 as of September 30, 2010 and December 31, 2009, respectively, have been determined using market quotes and the Company’s recent purchase of $68,000 in aggregate principal of its 2011 Notes.

NOTE 9 — EQUITY

Series C Convertible Preferred Stock

During June 2010, in connection with the Exchange Transaction, the Company created and authorized out of the authorized but unissued shares of the capital stock of the Company, 2,000,000 shares of Series C Convertible Preferred Stock. The Preferred Stock is entitled to receive cash dividends and other distributions declared on the common stock, as well as distributions upon liquidation, dissolution or any other winding up event, in each case as set forth in the Certificate of Designations. The Preferred Stock does not have any right or power to vote on any question or in any proceeding or to be represented at or to receive notice of any meeting of holders of capital stock of the Company, except as required by law. The Preferred Stock may not be redeemed by the Company at any time.

Each share of Preferred Stock is convertible at the option of the holder thereof, at any time, into the number of fully paid and nonassessable shares of common stock equal to the quotient of (1) one hundred dollars ($100.00) divided by (ii) the conversion price applicable to shares of common stock as determined pursuant to the Indenture and in effect at the time of conversion (and any fractional shares will be paid in cash). As for the 2015 Notes, a holder may not convert all or any portion of such holder’s Preferred Stock into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion beneficially own more than the Maximum Ownership Percentage (as defined in the Indenture governing the 2015 Notes).

On September 20, 2010, the Company effected the automatic conversion of $19,364,000 of the outstanding principal amount of the 2015 Notes into 305,754 shares of Preferred Stock, and as of September 30, 2010, 305,754 shares of Preferred Stock are issued and outstanding.

During October 2010, 57,912 shares of Preferred Stock were converted into 9,562,001 shares of common stock.

NOTE 10 - STATEMENTS OF CASH FLOWS

During the nine months ended September 30, 2010, 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 $2,100.

·Stock-based compensation expense of $1,729 capitalized as proved property.

26

·Additions to oil and gas properties included in accounts payable of $236,261.

·Recognition of deferred income of $3,036,791 in connection with Asset Sale described in Note 3 “Asset Sales and Purchases” herein.

·Exchange of 2011 Notes for 2015 Notes of $64,532,000 described in Note 4 “Convertible Senior Notes” herein.

·Exchange of $19,364,000 of the principal value of the 2015 Notes was converted into 305,754 shares of Preferred Stock and debt derivative liabilities of $15,358,616 were reclassified to Additional Paid-in Capital as described in Note 4 — “Convertible Senior Notes” herein.

During the nine months ended September 30, 2009, the Company’s non-cash investing and financing activities consisted of the following transactions:

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

·Stock-based compensation expense reduction of $5,184 capitalized as proved property.

·Additions to oil and gas properties included in accounts payable of $3,207,500.

·Sale of assets for a note receivable of $500,000.

Cash paid for interest during the nine months ended September 30, 2010 and 2009 was $3,231,004 and $3,056,357, respectively. There was no cash paid for income taxes during the nine months ended September 30, 2010 and 2009.

NOTE 11 — LEGAL PROCEEDINGS

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

EPA Enforcement Action

In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), a wholly-owned subsidiary of the Company, who was preparing air emission calculations for possible future capacity expansions, preliminarily determined that Riverbend may have not accurately calculated the amount of air pollutants that could be emitted from certain existing equipment at its Riverbend Compressor

27

Station in Uintah County, Utah.  Riverbend thereafter undertook a more detailed assessment, which confirmed that Riverbend had not obtained certain air permits nor complied with certain air pollution regulatory programs that were applicable to its operations at the Riverbend Compressor Station.  On June 22, 2007, Riverbend sent a letter to the United States Environmental Protection Agency (“EPA”) Region 8 office in Denver, Colorado, which—because the Riverbend Compressor Station is located in Indian Country—is the agency that has jurisdiction over federal air permitting and air pollution regulatory programs.  Riverbend’s June 22 letter voluntarily disclosed the potential violations to EPA and informed the agency of the steps that Riverbend had taken and planned to take to achieve compliance.  In November 2007, Riverbend met with EPA Region 8 personnel and discussed the disclosed violations, its plans to bring the Riverbend Compressor Station into compliance, and possible resolution of the disclosed violations.  In a letter to the EPA dated January 23, 2008, Riverbend confirmed its willingness to sign a consent decree with the United States that resolves the apparent violations, specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that will effectively authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented.  Riverbend has continued to work with the EPA and the Department of Justice on a settlement of this matter, and it anticipates that such a resolution will be achieved during 2010.

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

Sweeney Litigation

On December 5, 2008, a lawsuit was filed in state court in Cook County, Illinois (“Sweeney litigation”) by eleven individual plaintiffs and Griffin Asset Management, LLC.  The lawsuit alleges that defendants Richard N. Jeffs (“Jeffs), Marc Bruner (“Bruner”) and the Company through its agency with Bruner, made misrepresentations, committed fraud, aided and abetted a scheme to defraud, and conspired to defraud in connection with the plaintiffs’ investment in Brek Energy Corporation (“Brek”).  The complaint alleged that plaintiffs’ relied on various misrepresentations and omissions by the individual defendants when making the decision to invest in Brek, which merged into the Company in December of 2007.  Plaintiffs sought unspecified damages in an amount in excess of $50,000, punitive damages, attorneys’ fees, and costs.  The Company removed the case

28

to the United States District Court for the Northern District of Illinois, Eastern Division, on January 7, 2009 and answered the complaint, denying all liability, on February 13, 2009. A scheduling conference was held on April 1, 2009.  The judge ordered fact discovery in the case to be completed by December 15, 2009 and set the trial for June 7, 2010.  Following the scheduling conference, Jeffs was served with the complaint and filed a motion to dismiss all counts against him on the grounds that certain claims are barred by limitations, that plaintiffs lack standing to bring other claims, and that plaintiffs have failed to join an indispensable party (Brek).

During the fall of 2009, the parties began to engage in the early stages of discovery and numerous depositions were scheduled for late November and the first half of December 2009.  Prior to the start of depositions, however, on November 25, 2009, the parties reached an agreement in principle to settle the claims made against the Company and Bruner in the Sweeney litigation.

On December 4, 2009, while counsel for the Company was documenting the partial settlement, counsel for Jeffs sent a letter to the Company demanding that the Company (1) reimburse Jeffs for his defense costs to date in the Sweeney litigation; and (2) indemnify Jeffs for any judgment entered (or settlement made) in the Sweeney litigation.  Jeffs’ counsel claimed that Jeffs was entitled to such reimbursement and indemnification under the bylaws of Brek Energy Corporation that were in effect at the time of Brek’s merger into a wholly-owned subsidiary of the Company.

On December 9, 2009, Jeffs also filed an action in Colorado federal district court to obtain a declaration that the 550,000 shares of the Company’s stock being held in escrow under an agreement between the Company and Jeffs belong to, and should be released to, Jeffs pursuant to the terms of the escrow agreement (“Jeffs litigation”).

On or around December 18, counsel for the Company, Bruner, Jeffs, and plaintiffs reached an agreement in principle to settle all claims in both the Sweeney litigation and the Jeffs litigation.  This global settlement was documented and finalized in February 2010.

On February 5, 2010, counsel for the Company, Bruner, Jeffs, and plaintiffs filed an Agreed Motion for Dismissal with Prejudice of the Sweeney litigation.  On February 9, 2010, the United States District Court for the Northern District of Illinois, Eastern Division entered a docket entry granting the parties’ Agreed Motion and dismissing the Sweeney litigation with prejudice.  On February 10, 2010, a settlement payment was made to the Sweeney plaintiffs in connection with this dismissal with prejudice. On February 16, 2010, counsel for Gasco and Jeffs filed an Agreed Motion for Dismissal with Prejudice of the Jeffs litigation.  On February 17, 2010, the United States District Court for the District of Colorado entered an Order of Dismissal with Prejudice.  A settlement payment, which was accrued in the accompanying financial statements as of December 31, 2009, was made on February 17, 2010, following this dismissal with prejudice. The Company received a partial reimbursement from its insurance provider related to this matter during the second quarter of 2010.

NOTE 12 — CONSOLIDATING FINANCIAL STATEMENTS

On August 22, 2008, the Company filed a Form S-3 shelf registration statement with the SEC. Under this registration statement, which was declared effective on September 8, 2008, the Company may from time to time offer and sell securities including common stock, preferred stock, depositary shares and

29

debt securities that may be fully, irrevocably and unconditionally guaranteed by all of its subsidiaries:  Gasco Production Company, Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (collectively the “Guarantor Subsidiaries”). Set forth below are the condensed consolidating financial statements of the Company which, for purposes of this note and the related financial statements, is referred to as the Parent, and the Guarantor Subsidiaries. In accordance with US GAAP the financial statements of the Parent would include an investment in its subsidiaries and the subsidiaries would include general and administrative expenses.  These condensed statements are presented for information purposes only and do not purport to be the Parent’s balance sheet or statement of operations prepared under US GAAP.

30

Condensed Consolidating Balance Sheet

As of September 30, 2010

(Unaudited)

				Guarantor
	Parent			Subsidiaries			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	458,063		$	3,153,729		$	3,611,792
Accounts receivable	374,120			3,368,198			3,742,318
Inventory	—			1,779,480			1,779,480
Derivative instruments	940,011			—			940,011
Prepaid expenses	6,797			325			7,122
Total	1,778,991			8,301,732			10,080,723
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests	76,401			258,467,253			258,543,654
Unproved mineral interests	1,054,096			37,237,583			38,291,679
Facilities and equipment	—			1,029,750			1,029,750
Furniture, fixtures and other	283,807			—			283,807
Total	1,414,304			296,734,586			298,148,890
Less accumulated depreciation, depletion and amortization	(225,809		)	(229,710,319		)	(229,936,128		)
Total	1,188,495			67,024,267			68,212,762
OTHER ASSETS
Deposit	139,500			500,000			639,500
Note receivable	—			500,000			500,000
Deferred financing costs	1,384,334			—			1,384,334
Intercompany	205,073,832			(205,073,832		)	—
Total	206,597,666			(204,073,832		)	2,523,834
TOTAL ASSETS	$	209,565,152		$	(128,747,833	)	$	80,817,319

31

Condensed Consolidating Balance Sheet

As of September 30, 2010

(Unaudited)

			Guarantor
	Parent		Subsidiaries			Consolidated
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable	$	53,733	$	630,680		$	684,413
Revenue payable	—		2,925,640			2,925,640
Advances from joint interest owners	—		2,064,152			2,064,152
Current portion of long-term debt	5,544,969		—			5,544,969
Accrued interest	701,066		—			701,066
Accrued expenses	1,045,000		—			1,045,000
Total	7,344,768		5,620,472			12,965,240
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes due 2011	400,000		—			400,000
5.5% Convertible Senior Notes due 2015	18,838,610		—			18,838,610
Deferred income from sale of assets	—		2,918,694			2,918,694
Asset retirement obligation	—		1,094,602			1,094,602
Total	19,238,610		4,013,296			23,251,906
STOCKHOLDERS’ EQUITY (DEFICIT)
Preferred stock	306		—			306
Common stock	10,776		—			10,776
Other	182,967,692		(138,378,601		)	44,589,091
Total	182,978,774		(138,378,601		)	44,600,173
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$	209,562,152	$	(128,744,833	)	$	80,817,319

32

Condensed Consolidating Balance Sheet

As of December 31, 2009

(Unaudited)

				Guarantor
	Parent			Subsidiaries			Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	629,170		$	9,948,170		$	10,577,340
Accounts receivable	43,927			3,793,204			3,837,131
Inventory	—			1,019,913			1,019,913
Prepaid expenses	130,096			162,325			292,421
Total	803,193			14,923,612			15,726,805
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved mineral interests	78,130			254,604,740			254,682,870
Unproved mineral interests	1,054,096			37,584,840			38,638,936
Facilities and equipment	—			971,890			971,890
Furniture, fixtures and other	333,049			—			333,049
Total	1,465,275			293,161,470			294,626,745
Less accumulated depreciation, depletion and amortization	(251,438		)	(227,039,725		)	(227,291,163		)
Total	1,213,837			66,121,745			67,335,582
Assets held for sale, net of accumulated depreciation	—			20,155,544			20,155,544
Total	1,213,837			86,277,289			87,491,126
OTHER ASSETS
Deposit	139,500			—			139,500
Note receivable	500,000						500,000
Deferred financing costs	884,282			—			884,282
Intercompany	243,997,788			(243,997,788		)	—
Total	245,521,570			(243,997,788		)	1,523,782
TOTAL ASSETS	$	247,538,600		$	(142,796,887	)	$	104,741,713

33

Condensed Consolidating Balance Sheet

As of December 31, 2009

(Unaudited)

			Guarantor
	Parent		Subsidiaries			Consolidated
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable	$	209,153	$	901,106		$	1,110,259
Revenue payable	—		2,245,545			2,245,545
Derivative instruments	1,932,513		—			1,932,513
Accrued interest	844,108		—			884,108
Accrued expenses	1,215,106		—			1,215,106
Total	4,200,880		3,146,651			7,347,531
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes	65,000,000		—			65,000,000
Long-term debt	34,544,969		—			34,544,969
Derivative instruments	761,092		—			761,092
Asset retirement obligation related to assets held for sale	—		206,595			206,595
Asset retirement obligation	—		1,054,370			1,054,370
Deferred rent expense	20,555		—			20,555
Total	100,326,616		1,260,965			101,587,581
STOCKHOLDERS’ EQUITY (DEFICIT)
Common stock	10,780		—			10,780
Other	143,000,324		(147,204,503		)	(4,204,179		)
Total	143,011,104		(147,204,503		)	(4,193,399		)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)	$	247,538,600	$	(142,796,887	)	$	104,741,713

34

Condensed Consolidating Statements of Operations

(Unaudited)

				Guarantor
For the Three Months Ended September 30, 2010	Parent			Subsidiaries		Consolidated
REVENUES
Oil and gas	$	—		$	4,701,687	$	4,701,687
Total	—			4,701,687		4,701,687
OPERATING EXPENSES
Lease operating	—			1,422,397		1,422,397
Transportation and processing	—			801,938		801,938
Depletion, depreciation, amortization and accretion	12,863			805,123		817,986
Gain on sale of assets, net	—			79,837		79,837
General and administrative	1,225,048			—		1,225,048
Total	1,237,911			3,109,295		4,347,206
OTHER INCOME (EXPENSE)
Interest expense	(13,851,122		)	—		(13,851,122		)
Derivative gains	8,080,387			—		8,080,387
Gain on extinguishment of debt	14,430			—		14,430
Amortization of deferred income from sale of assets	—			50,613		50,613
Interest income	155			6,958		7,113
Total	(5,756,150		)	57,571		(5,698,579		)
NET INCOME (LOSS)	$	(6,994,061	)	$	1,649,963	$	(5,344,098	)

				Guarantor
For the Three Months Ended September 30, 2009	Parent			Subsidiaries		Consolidated
REVENUES
Oil and gas	$	—		$	3,555,661	$	3,555,661
Gathering	—			882,195		882,195
Total	—			4,437,856		4,437,856
OPERATING EXPENSES
Lease operating	—			887,594		887,594
Gathering operations	—			479,668		479,668
Depletion, depreciation, amortization and accretion	16,383			965,799		982,182
Loss on sale of assets, net	—			155,536		155,536
General and administrative	1,861,101			—		1,861,101
Total	1,877,484			2,488,597		4,366,081
OTHER INCOME (EXPENSE)
Interest expense	(1,420,025		)	—		(1,420,025		)
Derivative loss	(1,571,682		)	—		(1,571,682		)
Interest income	203			13,000		13,203
Total	(2,991,504		)	13,000		(2,978,504		)
NET INCOME (LOSS)	$	(4,868,988	)	$	1,962,259	$	(2,906,729	)

35

Condensed Consolidating Statements of Operations

(Unaudited)

				Guarantor
For the Nine Months Ended September 30, 2010	Parent			Subsidiaries		Consolidated
REVENUES
Oil and gas	$	—		$	15,432,171	$	15,432,171
Gathering	—			595,942		595,942
Total	—			16,028,113		16,028,113
OPERATING EXPENSES
Lease operating	—			3,893,737		3,893,737
Gathering operations	—			375,848		375,848
Transportation and processing	—			1,926,146		1,926,146
Depletion, depreciation, amortization and accretion	40,296			2,724,518		2,764,814
Gain on sale of assets, net	—			34,726		34,726
General and administrative	5,142,871			—		5,142,871
Total	5,183,167			8,954,975		14,138,142
OTHER INCOME (EXPENSE)
Interest expense	(16,260,691		)	—		(16,260,691		)
Derivative gain	11,368,447			—		11,368,447
Gain on extinguishment of debt	15,772,441			—		15,772,441
Amortization of deferred income from sale of assets	—			118,097		118,097
Interest income	554			29,137		29,691
Total	10,880,751			147,234		11,027,985
NET INCOME	$	5,697,584		$	7,220,372	$	12,917,956

				Guarantor
For the Nine Months Ended September 30, 2009	Parent			Subsidiaries			Consolidated
REVENUES
Oil and gas	$	—		$	11,174,067		$	11,174,067
Gathering	—			2,723,325			2,723,325
Rental income	—			366,399			366,399
Total	—			14,263,791			14,263,791
OPERATING EXPENSES
Lease operating	—			2,667,580			2,667,580
Gathering operations	—			1,962,364			1,962,364
Depletion, depreciation, amortization and accretion	49,964			4,609,319			4,659,283
Impairment	—			41,000,000			41,000,000
Contract termination fee	4,701,000			—			4,701,000
Loss on sale of assets, net	—			834,725			834,725
General and administrative	5,731,145			—			5,731,145
Total	10,482,109			51,073,988			61,556,097
OTHER INCOME (EXPENSE)
Interest expense	(4,080,213		)	—			(4,080,213		)
Derivative gain	721,885			—			721,885
Interest income	1,519			17,506			19,025
Total	(3,356,809		)	17,506			(3,339,303		)
NET LOSS	$	(13,838,918	)	$	(36,792,691	)	$	(50,631,609	)

36

Condensed Consolidating Statements of Cash Flows

(Unaudited)

				Guarantor
For the Nine Months Ended September 30, 2010	Parent			Subsidiaries			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(7,481,819	)	$	10,946,225		$	3,464,406
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other	(16,683		)	—			(16,683		)
Cash paid for acquisitions, development and exploration	—			(5,135,129		)	(5,135,129		)
Increase in advances from joint interest owners	—			2,064,152			2,064,152
Proceeds from property sales	—			24,309,000			24,309,000
Net cash provided by (used in) investing activities	(16,683		)	21,238,023			21,221,340
CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of borrowings	(29,000,000		)	—			(29,000,000		)
Cash paid for debt issuance costs	(2,044,070		)	—			(2,044,070		)
Payment of deposit	(500,000		)	—			(500,000		)
Cash paid of stock issuance costs	(52,824		)	—			(52,824		)
Cash paid for repurchase of convertible notes	(54,400		)	—			(54,400		)
Intercompany	38,923,956			(38,923,956		)	—
Net cash provided by (used in) financing activities	7,272,662			(38,923,956		)	(31,651,294		)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(225,840		)	(6,739,708		)	(6,965,548		)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD	683,903			9,893,437			10,577,340
END OF PERIOD	$	458,063		$	3,153,729		$	3,611,792

37

Condensed Consolidating Statements of Cash Flows

(Unaudited)

				Guarantor
For the Nine Months Ended September 30, 2009	Parent			Subsidiaries			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES	$	(484,208	)	$	17,008,253		$	16,524,045
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other	(2,297		)	—			(2,297		)
Cash paid for acquisitions, development and exploration	—			(8,666,306		)	(8,666,306		)
Proceeds from the sale of assets	—			500,000			500,000
Advances from joint interest owners	—			(612,222		)	(612,222		)
Net cash used in investing activities	(2,297		)	(8,778,528		)	(8,780,825		)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit	13,000,000			—			13,000,000
Repayment of borrowings	(9,455,031		)	—			(9,455,031		)
Intercompany	(2,764,776		)	2,764,776			—
Net cash provided by financing activities	780,193			2,764,776			3,544,969
NET INCREASE IN CASH AND CASH EQUIVALENTS	293,688			10,994,501			11,288,189
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD	501,511			551,705			1,053,216
END OF PERIOD	$	795,199		$	11,546,206		$	12,341,405

38

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

Forward-Looking Statements

Please refer to the section entitled “Cautionary Statement Regarding Forward-Looking Statements” at the end of this section for a discussion of factors which could affect the outcome of forward-looking statements used in this Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 (“Quarterly Report”).

Overview

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

Recent Developments

The Exchange Transaction

During the second quarter of 2010 we completed the exchange of $64,532,000 aggregate principal amount of our 5.5% Convertible Senior Notes due October 5, 2011 (the “2011 Notes”) for $64,532,000 aggregate principal amount of our unsecured 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”),  which are convertible, at the option of the holder, into shares of our common stock or, at the election of the holder,  shares of our newly designated Series C Convertible Preferred Stock, par value $0.001 per share (the “Preferred Stock”), which are convertible into shares of common stock (the “Exchange Transaction”). The 2015 Notes are governed by an indenture (the “Indenture”), dated as of June 25, 2010, by and between us and Wells Fargo Bank, National Association, as trustee (the “Trustee”).

The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock, other than pursuant to an automatic conversion (described below), is equal to $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the Indenture, we could not issue shares of common stock to holders of the 2015 Notes (including shares of common stock issuable upon a conversion of the 2015 Notes or upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes or in payment of any change of control purchase price, make whole premium or conversion make whole

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payment (each as described in the Indenture)) in excess of 19.9% of the number of shares of common stock outstanding immediately prior to the closing of the Exchange Transaction (the “Exchange Cap”), until stockholder approval of the issuance of common stock in excess of the Exchange Cap was obtained.

On September 15, 2010, at our 2010 Annual Meeting of Stockholders, we received stockholder approval for the issuance of all of the shares of common stock issuable upon conversion of our 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes in accordance with applicable law and the rules of the NYSE Amex. On September 20, 2010, we effected the automatic conversion of thirty percent of the then outstanding 2015 Notes, which equaled $19,364,000 aggregate principal amount, into 305,754 shares of Preferred Stock. We also paid an aggregate cash amount of $254,599, equal to all accrued but unpaid interest on the 2015 Notes subject to automatic conversion through September 20, 2010. See Note 4 “Convertible Senior Notes” to the accompanying unaudited condensed consolidated financial statements for further discussion.  As of September 30, 2010, we had 305,754 shares of Preferred Stock outstanding. During October 2010, 57,912 shares of Preferred Stock were converted into 9,562,001 shares of common stock.

Prospect Fee

During September 2010, we entered into an arrangement with an exploration and production company which operates in California. We received a $1.5 million prospect fee related to certain of its California acreage. The fee reimburses costs that we have invested in the area and provides us with a potential carried interest of 20% in two wells to be drilled on the acreage.  Additionally, the farmee is obligated to obtain and provide to us with 3-D seismic data over the contract area.

Impact of Current Credit Markets and Commodity Prices

The severe disruptions in the credit markets and reductions in global economic activity during 2008 and 2009 had significant adverse impacts on stock markets and oil and gas-related commodity prices, which contributed to a significant decline in our stock price and negatively impacted our future liquidity. Our liquidity has continued to be negatively affected in 2010 by the effects of this activity. The following discussion outlines the potential impacts that reduced commodity prices could have on our business, financial condition and results of operations.

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

Oil and gas prices have declined significantly since historic highs in July 2008. To mitigate the impact of lower commodity prices on our cash flows, we entered into commodity derivative instruments through 2011 (see Note 5 “Derivatives” of the accompanying unaudited condensed consolidated financial statements for further discussion).  In the event that commodity prices stay depressed or decline further, our cash flows from operations would be reduced even taking into account our commodity derivative instruments for 2010 and 2011 and may not be sufficient when coupled with available capacity under our Credit Facility to meet our working capital needs or, in the event of a significant decline in commodity prices, fund our 2010 capital expenditure budget.  This

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could cause us to alter our business plans, including further reducing our exploration and development plans.

Our capital expenditure program for 2010 of $6 million is being used primarily for the completion and recompletion projects on our existing wells.  During the first nine months of 2010, we funded our operating activities with cash flows from operating activities and sales proceeds from the sale of a partial working interest in some of our wells. Based on current expectations, we intend to fund our capital expenditure program entirely through cash flows from operations. Consequently, we will continue to monitor spending and cash flows throughout the year and may accelerate or delay investment depending on commodity prices, cash flows expectations and changes in our borrowing capacity.

Effective February 26, 2010, in connection with certain asset sales, our borrowing base under our Credit Facility was reduced to $16 million from $35 million, and as of September 30, 2010, we have $5.5 million of outstanding borrowings thereunder. Our borrowing base could be further reduced in the future by our lenders.  Though we anticipate funding our capital expenditure program of $6 million for 2010 through cash flows from operations, an inability to access additional borrowings in excess of our $10.5 million of existing capacity under our Credit Facility will limit our ability to increase our operating budget and execute on our growth plans.

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

Reduced Cash Flows from Operations Could Result in a Default under Our Credit Facility and Convertible Senior Notes due 2015 and Convertible Senior Notes due 2011

Our Credit Facility contains covenants including those that require us to maintain (1) a current ratio (defined as current assets plus unused availability under the credit facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1.0; and (2) a ratio of senior debt to EBITDAX (as such term is defined in the Credit Facility) for the most recent four quarters not to be greater than 3.5:1.0 for each fiscal quarter.  In addition, the Credit Facility contains covenants that restrict our ability to incur other indebtedness, create liens or sell our assets, pay dividends on our common stock and make certain investments. As of September 30, 2010, our current and senior debt to EBITDAX ratios are 2.6:1.0 and 0.6:1.0, respectively, and we are in compliance with each of the covenants as of September 30, 2010.  Sustained or lower oil and natural gas prices and the impact of the sale of our gathering system could reduce our consolidated EBITDAX and thus could reduce our ability to maintain existing levels of senior debt or incur additional indebtedness.

Any failure to be in compliance with any material provision or covenant of our Credit Facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under our Credit Facility.  Additionally, should our obligation to repay

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indebtedness under our Credit Facility be accelerated, we would be in default under the indentures governing our 2015 Notes and 2011 Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such 2015 Notes and 2011 Notes.  To the extent it becomes necessary to address any anticipated covenant compliance issues, we may be required to sell a portion of our assets or issue additional securities, which would be dilutive to our shareholders and may not be on terms acceptable to us.

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

Our Credit Facility limits our borrowings to the borrowing base less our total outstanding letters of credit issued there under. As of September 30, 2010, we have loans of approximately $5.5 million and no letters of credit outstanding under our Credit Facility (see Note 7 “Credit Facility” to the accompanying unaudited condensed consolidated financial statements for further discussion).

Under the terms of our Credit Facility, our borrowing base is subject to semi-annual redetermination by our lenders thereunder (the “Lenders”) based on their valuation of our proved reserves and their internal criteria.  In addition to such semi-annual determinations, our Lenders may request one additional borrowing base redetermination between each semi-annual calculation.

If our borrowing base is further reduced as a result of a redetermination to a level below our then current outstanding borrowings, we will be required to repay the amount by which such outstanding borrowings exceed the borrowing base within 30 days of notification by the Lenders and we will have less or no access to borrowed capital going forward. If we do not have sufficient funds on hand for repayment, we will be required to seek a waiver or amendment from our Lenders, refinance our Credit Facility or sell assets or additional shares of common stock.  We may not be able to refinance or complete such transactions on terms acceptable to us, or at all.  In the event that we are unable to repay the amount owed within 30 days, we will be in default under the Credit Facility, and as such the Lenders party thereto will have the right to terminate their aggregate commitment under the Credit Facility and declare our outstanding borrowings immediately due and payable in whole.  An acceleration of the outstanding indebtedness under the Credit Facility in this manner would additionally constitute an event of default under the indentures governing our 2015 Notes and our 2011 Notes. Should an event of default occur and continue under the indentures governing the 2015 Notes and the 2011 Notes, the 2015 Notes and the 2011 Notes may be declared immediately due and payable at their principal amount together with accrued interest and liquidated damages, if any.  As such, should we anticipate that we will not be able to repay all amounts owed under the Credit Facility as a result of the anticipated borrowing base redetermination; we will consider, along with previously discussed refinancing and sales, a sale of our company or our assets as well as a voluntary reorganization in bankruptcy. Additionally, if we are unable to repay amounts owed under the Credit Facility, the 2015 Notes and the 2011 Notes, we may be forced into an involuntary reorganization in bankruptcy.

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

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

Investments in unproved properties are also assessed periodically to ascertain whether impairment has occurred. Our evaluation of impairment of unproved properties incorporates our expectations of developing unproved properties given current and forward-looking economic conditions and commodity prices.  We believe that the majority of our remaining unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before we can explore or develop it further, or by making decisions that further exploration and development activity will not occur.

Reduced Commodity Prices May Impact Our Ability to Produce Economically

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

Completion Operations

We began our up-hole recompletion program in early February 2010. Since then, we have successfully completed the initial stages on one Upper Mancos well and recompleted 16 gross wells (6.5 net) with five gross wells (1.7 net) occurring in the third quarter 2010. Future recompletions are subject to oilfield service availability and weather conditions.

In late March, we turned on one of the wells (Gasco operated — 100% working interest) that we acquired as part of the Petro-Canada acquisition discussed earlier, after installing production equipment and connecting it to sales. The other well acquired in this acquisition was producing when it was purchased; however, our field personnel have optimized the production and have increased the flows rates on this well (Gasco operated — 100% working interest).

Oilfield services and pressure pumping remain widely available to us and at competitive prices.  Current per-stage fracture stimulation costs are now averaging $30,000, as compared to $95,000 two years ago, a 67% decrease.  The average recompletion includes six stages. Current recompletions are consistently yielding higher production rates for the Upper Blackhawk and Mesaverde pay horizons.  The first eight Upper Blackhawk/Mesaverde recompletions in 2010 are realizing a greater than 25% increase in their production over eight similar recompletions in 2008 when compared to each well’s first eight-week production period.  Consequently, the decreased stimulation costs when combined with the increased production are contributing to much better per-well economics.

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As of September 30, 2010, we operated 133 gross wells, and we currently have an inventory of 24 operated wells with up-hole recompletions and one Upper Mancos well awaiting initial completion activities. We do not have a drilling rig under contract at this time.

California Projects

The project in our Northwest McKittrick Prospect is in its final permitting stage and we currently expect a late 2010 spud date.  The Northwest McKittrick Prospect is a subthrust prospect covering approximately 600 gross acres targeting Tulare, Olig, McKittrick and Stevens sands draped over a faulted anticlinal nose as interpreted from well data and surface geology. We will be carried for 20% working interest on three wells that will test through the Stevens sands.

Our partner in the Southwest Cymric Prospect has elected not to drill its option well.  This partner drilled a first, shallow well on this prospect in December 2009 and the well was plugged and abandoned.  In order to earn into the prospect the partner had to drill a second, deeper well within 180 days from completing drilling operations on the first well.  The partner has returned all acreage to us and we are currently in the process of identifying a potential partner for this prospect.

Our Willow Springs Prospect is in the process of having 3-D seismic shot over it.  The operator will then process the 3-D seismic and identify potential drillable locations in the Willow Springs area.  The timing of any initial drilling on the Willow Springs Prospect is subject to the operator’s discretion.

The partner in our Willow Springs Prospect also recently bought into our Antelope Valley Trend group of nine oil and gas prospects that include both shallow horizons and deeper subthrust objectives.  The objectives within the Antelope Valley Trend consist of four to five sand members within the Temblor interval, including the Carneros. Our partner is currently in the process of planning and obtaining the necessary permits for a 3-D seismic shoot over this trend.  The first well in this area must be spud on or before July 1, 2012.  When the first well is drilled, our partner will earn approximately one half of the prospect area and four to five prospects as well, depending on the results of the 3-D seismic.  Our partner will then have the option to drill a second well on or before December 31, 2012.  The drilling of the second well will allow our partner to earn the remaining acreage and prospects.  Additionally we will receive a full license to the 3-D seismic data for this area.

We continue to pursue opportunities in the western area of the San Joaquin Basin.  We have identified additional leads and prospects within the overall trend of prospects defined by the Antelope Valley, Willow Springs, Northwest McKittrick and Southwest Cymric prospects.  We have purchased existing seismic data are having this data reprocessed to better define these new leads and prospects.  We are also purchasing additional acreage as these prospects become defined.

Wyoming

During the second quarter 2010 we sold our remaining acreage in Wyoming along with our interest in two producing wells at an auction for $9,000. The low natural gas prices we were receiving in this

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area had made it difficult for us to find partners to participate in the drilling of wells in this area, and as a result, we reclassified all unproved leasehold costs associated with this area into proved property during 2007.

Oil and Gas Production Summary

The following table presents our production and price information during the three and nine months ended September 30, 2010 and 2009. The Mcfe calculations assume a conversion of 6 Mcf for each Bbl of oil.

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2010		2009		2010		2009
Natural gas production (Mcf)	1,073,831		981,478		3,097,448		3,286,085
Average sales price per Mcf	$	3.75	$	3.01	$	4.32	$	2.97
Oil production (Bbl)	11,019		10,477		32,378		33,147
Average sales price per Bbl	$	60.96	$	57.53	$	63.06	$	42.67
Production (Mcfe)	1,139,945		1,044,340		3,291,716		3,484,967

Our equivalent oil and gas production increased by 9% during the three months ended September 30, 2010 as compared with the three months ended September 30, 2009 primarily due to the new production from our recompletion projects during the first nine months of 2010 which more than offset the normal production decline on our existing wells. During the first nine months of 2010 as compared with the first nine month of 2009, our equivalent oil and gas production decreased by approximately 5% primarily due to normal production declines which were not offset by the new production from the recompletion projects during 2010.

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are internally generated cash flows from operating activities or asset sales, availability under our Credit Facility, and access to capital markets, to the extent available. In connection with certain asset sales (see Note 3 “Asset Sales and Acquisitions” of the accompanying unaudited condensed consolidated financial statements), the borrowing base under our Credit Facility was reduced to $16 million effective February 26, 2010. Additionally our Credit Facility provides for periodic and special borrowing base redeterminations which could further affect our available borrowing base. The capital markets, as they relate to us, have been adversely impacted by the recent financial crisis, the potential lack of liquidity in the banking system and the potential unavailability and cost of credit. Though recently there has been some improvement in the capital markets, there is no guarantee that such will continue. We continually evaluate our capital needs and compare them to our capital resources and ability to raise funds in the financial markets. We adjust capital expenditures in response to changes in natural gas and oil prices, drilling results and cash flow. Please see “—Impact of Credit Market and Commodity Prices” above for a discussion of our liquidity and the impact of current market conditions thereon.

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As of September 30, 2010 we have negative working capital of $2,884,517 primarily, due to the $5,544,969 of borrowings under our Credit Facility which is now a current liability due March 29, 2011. We are currently working with our lenders to extend the maturity date of this obligation.

Sources and Uses of Funds

The following table summarizes our sources and uses of cash for each of the nine months ended September 30, 2010 and 2009.

	For the Nine Months EndedSeptember 30,
	2010			2009
Net cash provided by operations	$	3,464,406		$	16,524,045
Net cash provided by (used in) investing activities	21,221,340			(8,780,825		)
Net cash (used in) provided by financing activities	(31,651,294		)	3,544,969
Net (decrease) increase in cash	(6,965,548		)	11,288,189

Cash provided by operations decreased by $13,009,639 from September 30, 2009 to September 30, 2010.  The decrease in cash provided by operations was primarily due to the changes in operating assets and liabilities during the first nine months of 2010.  The decrease in cash provided by operations was partially offset by increased oil and gas revenue primarily due to a 45% increase in gas prices and a 48% increase in oil prices, partially offset by the 5% decrease in equivalent oil and gas production during 2010.

Our investing activities during the nine months ended September 30, 2010 and 2009 related primarily to the sales proceeds of $24,309,000 associated primarily with the sale of our gathering and evaporative facilities and the sale of a partial working interest in 32 producing wells (see Note 3 “Asset Sales and Acquisitions” of the accompanying unaudited condensed consolidated financial statements). In addition, investing activities included our development and exploration activities, fixed asset additions and the change in our advances from joint interest owners.

The financing activity during the first nine months of 2010 was comprised of $29,000,000 in repayments of borrowings on our line of credit, the payment of $2,044,070 in debt issuance costs associated with the Exchange Transaction, the payment of $52,824 in stock issuance costs, the payment of $54,400 for the purchase of 2011 Notes and the payment of a deposit of $500,000 in connection with our new gathering agreement. The financing activity during the first nine months of 2009 consisted of $13,000,000 of borrowings under our line of credit and the repayment of borrowings of $9,143,731.

Schedule of Contractual Obligations

The following table summarizes the Company’s obligations and commitments to make future payments under its notes payable, operating leases, employment contracts, consulting agreements and service contracts for the periods specified as of September 30, 2010.

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	Payments due by Period
Contractual Obligations	Total		Less than 1 year		1–3 years		3–5 years		More than5 years
Convertible 2015 Notes
Principal	$	45,168,000	$	—	$	—	$	—	$	45,168,000
Interest	12,455,703		2,484,240		4,968,480		4,968,480		34,503
Convertible 2011 Notes
Principal	400,000		—		400,000		—		—
Interest	22,306		22,000		306		—		—
Credit Facility Principal	5,544,969		5,544,969		—		—		—
Operating leases	136,786		136,786		—		—		—
Employment & consulting contracts	858,460		684,460		174,000		—		—
Asset retirement obligations (a)	1,094,602		—		—		—		1,094,602
Total Contractual Cash Obligations	$	65,680,826	$	8,872,455	$	5,542,786	$	4,968,480	$	46,297,105

(a)The accuracy and timing of the asset retirement obligations cannot be precisely determined in advance. See further discussion in Note 2 “Significant Accounting Policies — Asset Retirement Obligation” of the accompanying unaudited condensed consolidated financial statements.

Capital Budget

Based on current expectations, we intend to fund our 2010 capital expenditure program entirely through cash flows from operations. This program will focus primarily on completion and recompletion projects on our existing wells. Consequently, we will monitor spending and cash flows throughout the year and may accelerate or delay investment depending on commodity prices, cash flows expectations and changes in our borrowing capacity.

Critical Accounting Policies and Estimates

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

Oil and Gas Properties and Reserves

We follow the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated

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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. Under new oil and gas accounting rules, we prepared our oil and gas reserve estimates as of December 31, 2009 and September 30, 2010 using the average, first-day-of—the-month price during the 12-month periods then ending. In prior periods, we used the year-end price and subsequent commodity price increases could be utilized to calculate the ceiling value. As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf. There was no additional impairment recorded for the remainder of 2009 or during the first nine months of 2010. Therefore, impairment expense of $41,000,000 was recorded during the nine months ended September 30, 2009.

Estimated reserve quantities and future net cash flows have the most significant impact on us because these reserve estimates are used in providing a measure of the overall value of our company. Estimated quantities are affected by changes in commodity prices and actual well performance. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of our proved properties.  If our reserve quantities change or if additional costs are reclassified from unproved properties into proved properties, depletion expense could be significantly affected.

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

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

Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the quantities and present value of our reserves.  For example, a decrease in prices used to estimate our reserve quantities as of December 31, 2009 of

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$0.10 per Mcf for natural gas and $1.00 per barrel of oil would result in a decrease in our December 31, 2009 present value of future net cash flows of approximately $2,427,400. 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 us. This per acre estimate is then applied to the acres that we do not plan to develop in order to calculate the impairment.  A change in the estimated value of the acreage could have a material impact on the total impairment recorded by us, calculation of depletion expense and the ceiling test analysis.

Stock-Based Compensation

We account for stock option grants and restricted stock awards by recognizing 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. This model requires us to estimate a risk free interest rate and the volatility of our common stock price. The use of a different estimate for any one of these components could have a material impact on the amount of calculated compensation expense.

Derivatives

We have entered into certain commodity derivative instruments to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. We record all derivative instruments at fair value in the accompanying consolidated balance sheets. Changes in the fair value are to be recognized currently in earnings unless specific hedge accounting criteria are met. We recorded a change in the fair value of commodity derivative instruments of $3,633,616 and $(12,070,025) during the nine months ended September 30, 2010 and 2009, respectively.

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As of September 30, 2010, the fair value of the natural gas agreements was a current asset of $940,011. The fair value measurement of the commodity derivative assets and liabilities are measured based upon our valuation model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) notional quantities, (d) current market and contractual prices for the underlying instruments and (e) the counterparty’s credit risk. The unobservable inputs related to the volatility of the oil and gas commodity market are very significant in these calculations. Continued volatility in these markets could have a significant impact on the fair value of our derivative contracts. See Note 8 “Fair Value Measurements” to the accompanying unaudited condensed consolidated financial statements for further discussion.

Results of Operations

The Third Quarter of 2010 Compared to the Third Quarter of 2009

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  September 30,
	2010		2009
Natural gas production (Mcf)	1,073,831		981,478
Average sales price per Mcf	$	3.75	$	3.01
Natural gas revenue	$	4,029,912	$	2,952,924
Oil production (Bbl)	11,019		10,477
Average sales price per Bbl	$	60.96	$	57.53
Oil revenue	$	671,775	$	602,737
Equivalent production (Mcfe)	1,139,945		1,044,340

The increase in oil and gas revenue of $1,146,026 during the third quarter of 2010 compared with the third quarter of 2009 is comprised of an increase in the average oil and gas prices of $3.43 per Bbl and $0.74 per Mcf and a 9% increase in equivalent oil and gas production primarily due to the new production from recompletion projects on existing wells which more than offset normal production declines. The $1,146,026 increase in oil and gas revenue during the third quarter of 2010 represents an increase of $765,221 related to the increase in oil and gas prices and an increase of $380,805 related to the equivalent production increase.

Gathering Revenue and Expenses

Gathering revenue and expense represents the income earned from the third-party working interest owners in the wells we operate (our share of gathering revenue is eliminated against the transportation expense included in our lease operating costs) and the expenses incurred from the

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Riverbend area gathering assets that we constructed during 2004 and 2005. We sold our gathering assets during February 2010, as described in Note 3 “Asset Sales and Purchases — Sale of Gathering Assets” of the accompanying unaudited condensed consolidated financial statements, which resulted in a decrease in the gathering revenue of $882,195 and a decrease of $479,668 in gathering operations expenses during the third quarter of 2010.

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  September 30,
	2010		2009
Direct operating expenses and overhead	$	1,118,533	$	772,448
Workover expense	89,063		14,422
Total operating expenses	$	1,207,596	$	786,870
Operating expenses per Mcfe	$	1.06	$	0.75
Production and property taxes	$	214,801	$	100,724
Production and property taxes per Mcfe	$	0.19	$	0.10
Total lease operating expense per Mcfe	$	1.25	$	0.85

Lease operating expense increased $534,803 during the third quarter of 2010 compared with the third quarter of 2009. The increase is comprised of a $420,726 increase in operating expenses and a $114,077 increase in production taxes primarily due to the increase in natural gas and oil revenue during the third quarter of 2010.  The increase in operating expenses is primarily due to a $335,000 increase in water disposal fees as we now have to pay the new owner for these services due to the sale of our evaporative facilities in February 2010 combined with a $75,000 increase in workover expenses. Prior to the sale of the evaporative facilities, the revenue and expenses related to water disposal were eliminated. See further description in Note 3 “Asset Sales and Purchases — Sale of Gathering Assets” in the accompanying unaudited condensed consolidated financial statements.

Transportation and Processing

Transportation and processing costs of $801,938 ($0.70 per Mcfe) represent the costs we incurred to transport the gas production from our wells subsequent to the sale of our gathering assets as described in Note 3 “Asset Sales and Purchases — Sale of Gathering Assets” in the accompanying unaudited condensed consolidated financial statements. Prior to the sale of our gathering assets during February 2010, these intercompany costs were eliminated from revenue and expense.

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Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation and amortization expense during the third quarters of 2010 and 2009 is comprised of depletion expense related to our oil and gas properties, depreciation expense of furniture, fixtures and equipment and accretion expense related to the asset retirement obligation. The decrease of $164,196 during the third quarter of 2010 compared to the third quarter of 2009 is primarily due to the sale of our gathering assets and evaporative facilities as described in Note 3 “Asset Sales and Purchases — Sale of Gathering Assets” in the accompanying unaudited condensed consolidated financial statements.

Loss on Sale of Assets, net

The loss on sale of assets, net during the third quarters of 2010 and 2009 is primarily comprised of a net loss reflecting the decrease in the market value of our inventory.

General and Administrative Expense

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

	For the Three Months Ended September 30,
	2010			2009
Total general and administrative costs	$	1,305,762		$	1,659,482
General and administrative costs allocated to drilling, completion and operating activities	(413,423		)	(296,400		)
General and administrative expense	$	891,339		$	1,363,082
General and administrative expenses per Mcfe	$	0.78		$	1.30
Total stock-based compensation costs	$	332,350		$	505,657
Stock-based compensation (costs) reduction in costs capitalized	359			(7,638		)
Stock-based compensation	$	332,709		$	498,019
Stock-based compensation per Mcfe	$	0.29		$	0.48
Total general and administrative expense including stock-based compensation	$	1,225,048		$	1,861,101
Total general and administrative expense per Mcfe	$	1.07		$	1.78

General and administrative expense decreased by $542,053 ($0.47 per Mcfe) during the third quarter of 2010 as compared with the third quarter of 2009 primarily as the result of a $90,000 decrease in compensation expense due to the salary reductions we implemented during March 2009, a $380,000 reduction in consulting fees related to our financial transactions during 2009, and a $165,000 decrease in stock-based compensation due to the vesting of certain stock options.

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Interest Expense

Interest expense increased $12,431,097 during the third quarter of 2010 as compared with the third quarter of 2009 primarily due to the pro-rata portion of the unamortized discount and debt interest costs that were recorded as interest expense of $11,903,000 upon the conversion of 30% of the original principal amount of the 2015 Notes on September 20, 2010, and the additional interest expense due to the amortization of the discount on our 2015 Notes which was partially offset by the decreased outstanding debt balance during 2010 resulting from the sale of our gathering assets and evaporative facilities as further discussed in Note 3 “Asset Sales and Purchases” in the accompanying unaudited condensed consolidated financial statements. Cash paid for interest during the quarters ended September 30, 2010 and 2009 was $327,275 and $432,303, respectively.

 Derivative Gains (Losses)

Derivative gains (losses) during the third quarters of September 30, 2010 and 2009 are comprised of realized and unrealized gains and losses on our commodity derivative instruments and the unrealized gain on our embedded conversion features during the third quarter of 2010. The unrealized derivative gains (losses) represent the changes in the fair value of our derivative assets and liabilities and the realized derivative gains (losses) represent the net settlements due from or to our counterparty based on each month’s settlement during the quarter.

Gain on Extinguishment of Debt

During the third quarter of 2010, we purchased $68,000 in principal value of our 2011 Notes including interest for $54,400. The difference between the purchase price and the principal value less unamortized debt issuance costs was recorded as a gain on the extinguishment of debt during the third quarter of 2010.

Amortization of Deferred Income from Sale of Assets

The amortization of the deferred income from the sale of assets during the third quarter of 2010 represents the amortization of the excess of proceeds received over the carrying value of our gathering assets and evaporative facilities as further described in Note 3 “Asset Sales and Purchases” of the accompanying unaudited condensed consolidated financial statements.

The First Nine Months of 2010 Compared to the First Nine Months of 2009

The comparisons for the nine months ended September 30, 2010 with the nine months ended September 30, 2009 are consistent with those discussed in the three months ended September 30, 2010 compared to the three months ended September 30, 2009 except as discussed below:

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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 Nine Months Ended  September 30,
	2010		2009
Natural gas production (Mcf)	3,097,448		3,286,085
Average sales price per Mcf	$	4.32	$	2.97
Natural gas revenue	$	13,390,284	$	9,759,682
Oil production (Bbl)	32,378		33,147
Average sales price per Bbl	$	63.06	$	42.67
Oil revenue	$	2,041,887	$	1,414,385
Equivalent production (Mcfe)	3,291,716		3,484,967

The increase in oil and gas revenue of $4,258,104 during the first nine months of 2010 compared with the first nine months of 2009 is comprised of an increase in the average oil and gas prices of $20.39 per Bbl and $1.35 per Mcf partially offset by a 5% decrease in equivalent oil and gas production primarily due to normal production declines which were not offset by new production due to our recompletion operations in during the first nine months of 2010. The $4,528,104 increase in oil and gas revenue during the first nine months of 2010 represents an increase of $5,123,611 related to the increase in oil and gas prices and a decrease of $865,507 related to the equivalent production decrease.

Rental Income

Rental income during 2009 represents the lease payments received from a third party’s use of our drilling rig which was sold during June 2009. Our drilling rig was sold during June 2009 and therefore no rental income was recorded during the nine months ended September 30, 2010.

Impairment

As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf. Therefore, impairment expense of $41,000,000 was recorded during the nine months ended September 30, 2009. No impairments were recorded during the nine months ended September 30, 2010.

Contract Termination Fee

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

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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 Nine Months Ended September 30,
	2010			2009
Total general and administrative costs	$	5,048,867		$	5,282,940
General and administrative costs allocated to drilling, completion and operating activities	(1,113,549		)	(1,013,905		)
General and administrative expense	$	3,935,318		$	4,269,035
General and administrative expenses per Mcfe	$	1.19		$	1.22
Total stock-based compensation costs	$	1,205,553		$	1,467,294
Stock-based compensation (costs) reduction in costs capitalized	1,729			(5,184		)
Stock-based compensation	$	1,207,553		$	1,462,110
Stock-based compensation per Mcfe	$	0.37		$	0.42
Total general and administrative expense including stock-based compensation	$	5,142,871		$	5,731,145
Total general and administrative expense per Mcfe	$	1.56		$	1.64

General and administrative expense decreased by $494,274 ($0.15 per Mcfe) during the first nine months of 2010 as compared with the first nine months of 2009 primarily due to $300,000 decrease in compensation expense due to the salary reductions we implemented during March 2009, $400,000 in legal reimbursements received from our insurance company in connection with the litigation settlement further described in Note 11 “Legal Proceedings” in the accompanying unaudited condensed consolidated financial statements, a $800,000 reduction in consulting fees related to our financial transactions during 2009, and a $255,000 decrease in stock-based compensation due to the vesting of certain stock options. This decrease was partially offset by $950,000 in severance payments we agreed to make to our former president and CEO in connection with his resignation during January 2010 and increased compensation expense due to the payment of non-management employee bonuses of approximately $300,000 related to the successful completion of asset sales and purchases during the first quarter of 2010 as further discussed in Note 3 “Asset Sales and Acquisitions” in the accompanying unaudited condensed consolidated financial statements.

Gain on Extinguishment of Debt

Gain on extinguishment of debt during the first nine months of 2010 represents the difference between the fair value of the 2015 Notes and the debt conversion derivative as compared to the carrying value of the 2011 Notes less unamortized debt issuance costs that were exchanged in the Exchange Transaction as further described in Note 4 “Convertible Senior Notes” of the accompanying unaudited condensed consolidated financial statements, and the gain on the repurchase of 2011 Notes as described above.

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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 September 30, 2010, the off-balance sheet arrangements and transactions that we entered into include undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. We do not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

Recently Issued Accounting Pronouncements

In January 2010, ASC guidance for fair value measurements and disclosure was updated to require additional disclosures related to transfers in and out of level 1 and 2 fair value measurements and enhanced detail in the level 3 reconciliation. The guidance was amended to clarify the level of disaggregation required for assets and liabilities and the disclosures required for inputs and valuation techniques used to measure the fair value of assets and liabilities that fall in either level 2 or level 3. The updated guidance was effective for our fiscal year beginning January 1, 2010, with the exception of the level 3 disaggregation which is effective for our fiscal year beginning January 1, 2011. The adoption had no impact on our consolidated financial position, results of operations or cash flows. Refer to Note 8 “Fair Value Measurements” of the accompanying unaudited condensed consolidated financial statements for further details regarding the Company’s assets and liabilities measured at fair value.

Cautionary Statement Regarding Forward-Looking Statements

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

Although any forward-looking statements contained in this Quarterly Report or otherwise expressed by or on behalf of us are, to the knowledge and in the judgment of our officers and directors, believed to be reasonable, there can be no assurances that any of these expectations will prove correct or that any of the actions that are planned will be taken. Forward-looking statements involve and can be affected by inaccurate assumptions or by known and unknown risks and uncertainties which may cause our actual performance and financial results in future periods to differ materially from any projection, estimate or forecasted result. Important factors that could cause actual results to differ materially from expected results include those discussed under Part I, Item 1A “Risk Factors” and elsewhere in our 2009 10-K and under Part II Item 1A “Risk Factors” and elsewhere in this Quarterly Report.

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

·fluctuations in natural gas and oil prices;

·pipeline constraints;

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

·changes in general economic conditions in the United States;

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

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

·our ability to generate sufficient cash flows to operate;

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

·the amount, nature and timing of capital expenditures;

·estimated reserves of natural gas and oil;

·drilling of wells;

·acquisition and development of oil and gas properties;

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

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

·operating costs and other expenses;

·cash flows and anticipated liquidity;

·future operating results;

·marketing of oil and natural gas;

·federal and state regulatory or legislative developments;

·competition and regulation; and

·plans, objectives and expectations.

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

GLOSSARY OF NATURAL GAS AND OIL TERMS

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

Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, used 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 well, the reporting of abandonment to the appropriate agency.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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 well.  An exploratory or development well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil and gas in another reservoir.

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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 pre-tax 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 average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as

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general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

Productive well.  A producing well and a well that is found to be mechanically capable of production.

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.  Proved developed oil and gas reserves are reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior

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to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved properties.  Properties with proved reserves.

Proved undeveloped reserves.  Undeveloped oil and gas reserves are reserves of any category 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. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be 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 projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

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 individual and separate from other reservoirs.

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

Standardized Measure of Discounted Future Net Cash Flows.    The discounted future net cash flows relating to proved reserves based on average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period and period-end costs and statutory tax rates (adjusted for permanent differences) and a 10-percent annual discount rate.

Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily arc drilled without the intent 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 economic quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

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Unproved properties.  Properties with no proved reserves.

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

ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. To mitigate a portion of our exposure to adverse market changes, we have entered into various derivative instruments. As of September 30, 2010, our derivative instruments consists of two swap agreements for our 2010 through March 2011 production. The fair value of these agreements is a current asset of $940,011 as of September 30, 2010. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our hedged production. For our swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Our swap agreements as of September 30, 2010 for 2010 through March 2011 are summarized in the table below:

Agreement Type	RemainingTerm	Quantity	Fixed PriceCounterparty payer	Floating Price (a)Gasco payer
Swap (b)	10/10 – 12/10	3,500 MMBtu/day	$4.418/MMBtu	NW Rockies
Swap	10/10 – 3/11	3,000 MMBtu/day	$4.825/MMBtu	NW Rockies
Swap (b)	1/11 – 3/11	2,000 MMBtu/day	$4.418/MMBtu	NW Rockies

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

(b)Includes information pertaining to a portion of a single natural gas derivative contract with declining volumes. The fixed price represents the weighted average price for the entire period from June 2009 through March 2011.

During October 2010, we entered into an additional swap agreement for the year ended December 31, 2011, for 2,000 MMBtu/day with a fixed price of $4.00/MMBtu and a Northwest Pipeline Rocky Mountains — Inside FERC first of month index price.

The swap contracts allow us to predict with greater certainty the effective natural gas prices that we will receive for our hedged production and to benefit from operating cash flows when market prices are less than the fixed prices of the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for the hedged production. Our hedging contracts have no requirements for us to post additional collateral based upon the changes in the market value of our hedge instruments.

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The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production for the nine months ended September 30, 2010, our annual revenue would increase or decrease by approximately $32,000 for each $1.00 per barrel change in crude oil prices and $310,000 for each $0.10 per Mcf change in natural gas prices.

Interest Rate Risk

We do not currently use interest rate derivatives to mitigate our exposure, including under our Credit Facility, to the volatility in interest rates. A 1.0% increase in interest rates on the average borrowings outstanding during the first nine months of 2010 would increase interest expense by approximately $55,000 per year.

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ITEM 4 - CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, as appropriate, to allow such persons to make timely decisions regarding required disclosures.

Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of September 30, 2010 at the reasonable assurance level.

Changes in Internal Controls over Financial Reporting during the Third Quarter of 2010

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

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PART II - OTHER INFORMATION

Item 1 -Legal Proceedings

For a discussion of our legal proceedings please see Note 11 “Legal Proceedings” of the accompanying unaudited condensed financial statements included herein.

Item 1A -Risk Factors

Information about material risks related to our business, financial condition and results of operations for the three months ended September 30, 2010, does not materially differ from that set out in Part I, Item 1A of our 2009 10-K and in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010.

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

Working capital restrictions and other limitations upon the payment of dividends are reported in Note 7 “Credit Facility” of the accompanying unaudited condensed financial statements included herein.

Item 6 —Exhibits

The following is a list of exhibits filed or furnished (as indicated) as part of this Quarterly Report.  Where so noted, exhibits which were previously filed are incorporated herein by reference.

Exhibit Number	Exhibit
3.1	Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
3.2	Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).
3.3	Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).
3.4	Second Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).

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4.1	Certificate of Designation for Series B Preferred Stock (incorporated by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement, filed on April 17, 2003, File No. 333-104592).
4.2	Certificate of Designation, Preferences and Rights of Series C Convertible Preferred Stock dated as of June 22, 2010 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
10.1	Ninth Amendment to the Credit Agreement, dated as of February 1, 2010, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K dated February 1, 2010, filed February 5, 2010, File No. 001-32369).
10.2	Tenth Amendment to Credit Agreement dated as of June 22, 2010 by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
10.3	Consulting Agreement and Release, dated January 29, 2010, by and between Gasco Energy, Inc. and Mark A. Erickson (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated January 27, 2010, filed on February 1, 2010, File No. 001-32369).
10.4	Asset Purchase Agreement dated January 29, 2010 by and among Gasco Energy, Inc., Riverbend Gas Gathering, LLC, and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated January 29, 2010, filed on February 3, 2010, File No. 001-32369).
10.5	Gas Gathering and Processing Agreement dated March 1, 2010 by and between Gasco Production Company and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated February 26,2010 filed on March 3, 2010, File No. 001-32369).
10.6	Indenture (including form of 2015 Note) dated as of June 25, 2010 between Gasco Energy, Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
*10.7	First Supplemental Indenture dated as of September 22, 2010.
10.8	Guaranty Agreement dated as of June 25, 2010 among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).

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10.9	Investor Rights Agreement dated as of June 25, 2010 among Gasco Energy, Inc., CNH CA Master Account, L.P. and AQR Absolute Return Master Account, L.P. (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
10.10	Form of Exchange Agreement dated as of June 22, 2010 between Gasco Energy, Inc. and each of the Investors (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
10.11	Confidential Information Memorandum dated as of June 22, 2010 (incorporated by reference to Exhibit 99.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
*31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
*31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
**32.1	Section 1350 Certification of Chief Executive Officer.
**32.2	Section 1350 Certification of Chief Financial Officer.

*   Filed herewith.

** Furnished herewith.

#   Identifies management contracts and compensating plans or arrangements.

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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: November 2, 2010	By:	/s/ W. King Grant
		W. King Grant, President and
		Chief Financial Officer
		(Chief Financial Officer and Authorized Officer)

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EXHIBIT INDEX

Exhibit Number	Exhibit
3.1	Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
3.2	Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).
3.3	Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).
3.4	Second Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).
4.1	Certificate of Designation for Series B Preferred Stock (incorporated by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement, filed on April 17, 2003, File No. 333-104592).
4.2	Certificate of Designation, Preferences and Rights of Series C Convertible Preferred Stock dated as of June 22, 2010 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
10.1	Ninth Amendment to the Credit Agreement, dated as of February 1, 2010, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K dated February 1, 2010 filed on February 5, 2010, File No. 001-32369).
10.2	Tenth Amendment to Credit Agreement dated as of June 22, 2010 by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
10.3	Consulting Agreement and Release, dated January 29, 2010, by and between Gasco Energy, Inc. and Mark A. Erickson (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated January 27,2010, filed on February 1, 2010 File No. 001-32369).

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10.4	Asset Purchase Agreement dated January 29, 2010 by and among Gasco Energy, Inc., Riverbend Gas Gathering, LLC, and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated January 29, 2010, filed on February 3, 2010 File No. 001-32369).
10.5	Gas Gathering and Processing Agreement dated March 1, 2010 by and between Gasco Production Company and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1 to on the Company’s Form 8-K dated February 26, 2010, filed on March 3, 2010 File No. 001-32369).
10.6	Indenture (including form of 2015 Note) dated as of June 25, 2010 between Gasco Energy, Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
*10.7	First Supplemental Indenture dated as of September 22, 2010.
10.8	Guaranty Agreement dated as of June 25, 2010 among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
10.9	Investor Rights Agreement dated as of June 25, 2010 among Gasco Energy, Inc., CNH CA Master Account, L.P. and AQR Absolute Return Master Account, L.P. (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
10.10	Form of Exchange Agreement dated as of June 22, 2010 between Gasco Energy, Inc. and each of the Investors (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
10.11	Confidential Information Memorandum dated as of June 22, 2010 (incorporated by reference to Exhibit 99.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
*31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
*31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
**32.1	Section 1350 Certification of Chief Executive Officer.
**32.2	Section 1350 Certification of Chief Financial Officer.

*   Filed herewith.

** Furnished herewith.

#   Identifies management contracts and compensating plans or arrangements.

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