UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

o		TRANSITION REPORT UNDER SECTION 13 OF 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___

Commission File Number 001-32369

GASCO ENERGY, INC.

(Exact name of registrant as specified in its charter)

Nevada		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 þ No o

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

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

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

Number of common shares outstanding as of November 3, 2009: 107,728,798

 

 

Table of Contents

Part I
Item 1.		Financial Statements (Unaudited)			3
		Consolidated Balance Sheets			3
		Consolidated Statements of Operations			5
		Consolidated Statements of Cash Flows			7
		Notes to Consolidated Financial Statements			8
Item 2.		Management’s Discussion and Analysis			33
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			58
Item 4.		Controls and Procedures			60
Part II
Item 1.		Legal Proceedings			61
Item 1A.		Risk Factors			61
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			61
Item 3.		Defaults Upon Senior Securities			61
Item 4.		Submission of Matters to a Vote of Security Holders			61
Item 5.		Other Information			61
Item 6.		Exhibits			62
EX-4.5
EX-31
EX-32

ITEM I — FINANCIAL STATEMENTS

PART 1 — FINANCIAL INFORMATION

GASCO ENERGY, INC.

CONSOLIDATED BALANCE SHEETS
(Unaudited)

		September 30,				December 31,
		2009				2008
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	12,341,405			$	1,053,216
Accounts receivable
Joint interest billings			375,932				5,436,636
Revenue			2,159,440				3,827,950
Inventory			1,074,587				4,177,967
Derivative instruments			—				8,855,947
Prepaid expenses			8,748				188,810
Total			15,960,112				23,540,526
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved properties			253,443,888				247,976,854
Unproved properties			39,329,656				39,314,406
Wells in progress			—				644,688
Gathering assets			17,784,520				17,440,680
Facilities and equipment			6,377,952				8,549,928
Furniture, fixtures and other			371,674				371,605
Total			317,307,690				314,298,161
Less accumulated depletion, depreciation, amortization and impairment			(230,612,237	)			(185,585,582	)
Total			86,695,453				128,712,579
OTHER ASSETS
Deposit			139,500				139,500
Note receivable			500,000				—
Deferred financing costs			1,025,127				1,492,903
Total			1,664,627				1,632,403
TOTAL ASSETS		$	104,320,192			$	153,885,508

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

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

		September 30,				December 31,
		2009				2008
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable		$	548,861			$	5,879,150
Revenue payable			2,279,605				3,840,985
Advances from joint interest owners			—				612,222
Derivative instruments			1,543,019				—
Accrued interest			1,747,144				1,187,495
Accrued expenses			848,000				1,126,000
Total			6,966,629				12,645,852
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes			65,000,000				65,000,000
Long-term debt			34,544,969				31,000,000
Derivative instruments			1,671,059				—
Asset retirement obligation			1,231,899				1,150,179
Deferred rent expense			27,063				46,589
Total			102,474,990				97,196,768
STOCKHOLDERS’ EQUITY (DEFICIT)
Series B Convertible Preferred stock — $0.001 par value; 20,000 shares authorized; zero shares outstanding			—				—
Common stock — $.0001 par value; 300,000,000 shares authorized; 107,802,498 shares issued and 107,728,798 outstanding as of September 30, 2009 and 107,825,998 shares issued and 107,752,298 outstanding as of December 31, 2008			10,780				10,783
Additional paid-in capital			220,842,666				219,375,369
Accumulated deficit			(225,844,578	)			(175,212,969	)
Less cost of treasury stock of 73,700 common shares			(130,295	)			(130,295	)
Total			(5,121,427	)			44,042,888
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)		$	104,320,192			$	153,885,508

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

GASCO ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

		Three Months Ended
		September 30,
		2009				2008
REVENUES
Gas		$	2,952,924			$	8,457,980
Oil			602,737				1,210,047
Gathering			882,195				1,248,483
Rental income			—				312,344
Total			4,437,856				11,228,854
OPERATING EXPENSES
Lease operating			887,594				1,224,416
Gathering operations			479,668				1,004,061
Depletion, depreciation, amortization and accretion			982,182				1,702,682
Loss on sale of assets, net			155,536				—
General and administrative			1,861,101				2,113,675
Total			4,366,081				6,044,834
OTHER INCOME (EXPENSE)
Interest expense			(1,420,025	)			(1,248,702	)
Derivative gains (losses)			(1,571,682	)			17,099,899
Interest income			13,203				4,681
Total			(2,978,504	)			15,855,878
NET INCOME (LOSS)		$	(2,906,729	)		$	21,039,898
NET INCOME (LOSS) PER COMMON SHARE
BASIC		$	(0.03	)		$	0.20
DILUTED		$	(0.03	)		$	0.17
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING -
BASIC			107,546,398				107,499,883
DILUTED			107,546,398				125,992,710

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

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

		Nine Months Ended
		September 30,
		2009				2008
REVENUES
Gas		$	9,759,682			$	27,760,412
Oil			1,414,385				2,985,582
Gathering			2,723,325				3,236,040
Rental income			366,399				1,095,469
Total			14,263,791				35,077,503
OPERATING EXPENSES
Lease operating			2,667,580				4,426,517
Gathering operations			1,962,364				2,701,404
Depletion, depreciation, amortization and accretion			4,659,283				7,323,481
Impairment			41,000,000				—
Contract termination fee			4,701,000				—
Loss on sale of assets, net			834,725				—
General and administrative			5,731,145				6,788,301
Total			61,556,097				21,239,703
OTHER INCOME (EXPENSE)
Interest expense			(4,080,213	)			(3,727,513	)
Derivative gains			721,885				5,705,394
Interest income			19,025				25,492
Total			(3,339,303	)			2,003,373
NET INCOME (LOSS)		$	(50,631,609	)		$	15,841,173
NET INCOME (LOSS) PER COMMON SHARE
BASIC		$	(0.47	)		$	0.15
DILUTED		$	(0.47	)		$	0.14
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING -
BASIC			107,559,351				107,195,454
DILUTED			107,559,351				109,561,398

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

GASCO ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

		Nine Months Ended
		September 30,
		2009				2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)		$	(50,631,609	)		$	15,841,173
Adjustment to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, amortization and impairment expense			45,577,788				7,251,087
Accretion of asset retirement obligation			81,495				72,394
Stock-based compensation			1,462,110				2,236,022
Change in fair value of derivative instruments, net			12,070,025				(7,153,561	)
Amortization of deferred rent expense			(19,526	)			(7,496	)
Amortization of deferred financing costs			467,776				388,675
Loss on sale of assets, net			834,725				—
Changes in operating assets and liabilities:
Accounts receivable			6,729,214				(6,962	)
Inventory			3,174,505				(1,686,240	)
Prepaid expenses			180,062				242,370
Accounts payable			(2,122,789	)			(3,415,980	)
Revenue payable			(1,561,380	)			4,314,571
Accrued interest			559,649				949,351
Accrued expenses			(278,000	)			407,000
Net cash provided by operating activities			16,524,045				19,432,404
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other			(2,297	)			(73,814	)
Cash paid for acquisitions, development and exploration			(8,666,306	)			(29,465,037	)
Proceeds from sale of assets			500,000				7,500,000
Decrease in advances from joint interest owners			(612,222	)			(1,348,908	)
Net cash used in investing activities			(8,780,825	)			(23,387,759	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit			13,000,000				19,000,000
Repayment of borrowings			(9,455,031	)			(16,000,000	)
Exercise of options to purchase common stock			—				1,161,284
Net cash provided by financing activities			3,544,969				4,161,284
NET INCREASE IN CASH AND CASH EQUIVALENTS			11,288,189				205,929
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD			1,053,216				1,843,425
END OF PERIOD		$	12,341,405			$	2,049,354

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

GASCO ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2009 AND 2008
(Unaudited)

NOTE 1 — ORGANIZATION AND LIQUIDITY

Gasco Energy, Inc. (“Gasco,” the “Company,” “we,” “our” or “us”) is a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. The Company’s principal business strategy is to enhance stockholder value by using technologies new to a specific area to generate and develop high-potential exploitation resources in this area. The Company’s principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. The Company is currently focusing its 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 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 filed with the Securities and Exchange Commission (the “SEC”) for the year ended December 31, 2008 (“2008 10-K”). 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 2008 10-K.

The Company’s credit agreement provides for periodic borrowing base redeterminations which impact the available borrowing base of the Company. See Note 4 “Credit Facility” herein for discussion of the current status of the credit agreement and how it affects the Company’s liquidity and ability to continue as a going concern.

The results of operations for the nine months ended September 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009. All significant intercompany transactions have been eliminated. The Company has evaluated subsequent events through November 3, 2009, the filing date of this Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009, and has disclosed such items in Note 4 “Credit Facility” herein.

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Oil and Gas Properties

The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, internal costs directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized internal costs of $47,617 during the first nine months of 2009 and none during the third quarter of 2009. The Company capitalized internal costs of $21,209 and $80,865 during the three and nine months ended September 30, 2008, respectively. Additionally, the Company capitalized stock compensation expense related to its drilling consultants as further described in Note 3 “Stock-Based Compensation” herein. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

Depletion of exploration and development costs and depreciation of production equipment 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 $39,329,656 as of September 30, 2009 are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment.

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

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

the ceiling value.

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. There was no additional impairment recorded for the three months ended June 30, 2009 or September 30, 2009. Therefore, impairment expense of $41,000,000 was recorded during the nine months ended September 30, 2009.

Wells in Progress

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

Facilities and Equipment

The Company constructed four evaporation pits in the Riverbend area of Utah to be used for the disposal of produced water from the wells that Gasco operates in the area. The pits are being depreciated using the straight-line method over their estimated useful life of twenty-five years. The costs of water disposal into the evaporation pits are charged to wells operated by Gasco and therefore, the net income or (expense) attributable to the outside working interest owners from the evaporation pits of $(22,874) and $193; and $24,636 and $284,301 was recorded as an adjustment to proved properties during the three and nine months ended September 30, 2009 and 2008, respectively.

The Company’s other oil and gas equipment is depreciated using the straight-line method over the estimated useful life of five to ten years for the equipment, twenty years for the drilling rig (sold June 2009 as described below) and twenty five years for the facilities. The rental of the equipment owned by Gasco is charged to the wells that are operated by Gasco, and therefore the net income or (expense) attributable to the outside working interest owners from the equipment rental of $(15,476) and $51,612; and $105,604 and $409,249 was recorded as an adjustment to proved properties during the three and nine months ended September 30, 2009 and 2008, respectively.

Through the beginning of June 2009, the Company owned a drilling rig that it leased to an operator for the drilling of wells that it did not operate. During June 2009 the Company sold the drilling rig for proceeds of $1,000,000 which consisted of a cash payment of $500,000 and an interest bearing promissory note of $500,000 with a maturity date of June 30, 2012. The Company recognized a loss of $905,850 on the sale, which is included in “Loss on sale of assets, net” in the accompanying financial statements.

Forward Sales Contracts

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

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

The Company believes that it is not required to treat the contracts as derivatives and the contracts will not be marked to market because the Company anticipates that (1) it will produce the volumes required to be delivered under the terms of the contracts, (2) it is probable the delivery will be made to the counterparty and (3) the counterparty will fulfill its contractual obligations under the terms of the contracts.

Derivatives

The Company uses derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The Company records all derivative instruments at fair value within the accompanying 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 derivatives and therefore, the changes in fair value are recognized in earnings.

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

		Location on Consolidated		Fair Value at
		Balance Sheets		September 30, 2009				December 31, 2008
Natural gas derivative contracts		Current assets		$	—			$	8,855,947
Natural gas derivative contracts		Current liabilities			1,543,019				—
Natural gas derivative contracts		Noncurrent liabilities			1,671,059				—

These instruments allow the Company to predict with greater certainty the effective natural gas prices to be realized for its production. The Company’s derivative contracts are described below:

	•		For its swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
	•		The Company’s costless collar contained a fixed floor price (put) and ceiling price (call). If the market price exceeded the call strike price or fell below the put strike price, Gasco received the fixed price and paid the market price. If the market price was between the call and the put strike prices, no payments were due from either party.

During May 2009, the Company monetized selected natural gas hedge contracts for net proceeds of $8,528,731. These proceeds were used to repay a portion of the Company’s outstanding borrowings as further described in Note 4 “Credit Facility” herein. Concurrent with the monetization of the hedges, the Company re-hedged a portion of its production for the period June 2009 through March 2011 as further detailed below. The new derivative contracts were entered into at a weighted average price over the contract periods. The Company elected the weighted average price scenario for a portion of its natural gas volumes in an effort to secure what it believes to be the best prices for the 2009 contract period.

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, 2009 and 2008.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Realized gains (losses) on derivative instruments		$	1,031,459			$	413,993			$	12,791,910			$	(1,448,167	)
Change in fair value of derivative instruments, net			(2,603,141	)			16,685,906				(12,070,025	)			7,153,561
Total realized and unrealized gains (losses) recorded		$	(1,571,682	)		$	17,099,899			$	721,885			$	5,705,394

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

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

		Remaining				Fixed Price		Floating Price (a)
Agreement Type		Term		Quantity		Counterparty payer		Gasco payer
Swap (b)		10/09 — 12/09		6,500 MMBtu/day		$4.418/MMBtu		NW Rockies
Swap (b)		1/10 — 12/10		3,500 MMBtu/day		$4.418/MMBtu		NW Rockies
Swap		1/10 — 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

Concentrations of Credit Risk

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

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

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 in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs using the units-of-production method. 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. The asset retirement liability is allocated to operating expense using a systematic and rational method. The information below reconciles the value of the asset retirement obligation for the periods presented.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Balance beginning of period		$	1,204,100			$	1,094,147			$	1,150,179			$	1,030,283
Liabilities incurred			—				8,984				225				35,463
Liabilities settled			—				—				—				(10,179	)
Property dispositions			—				(11,107	)							(11,107	)
Accretion expense			27,799				24,830				81,495				72,394
Balance end of period		$	1,231,899			$	1,116,854			$	1,231,899			$	1,116,854

Contract Termination Fee

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

Off Balance Sheet Arrangements

From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of September 30, 2009, the off-balance sheet arrangements and transactions that the Company has entered into include undrawn letters of credit, operating lease agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

Computation of Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of the options to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period).

The table below sets forth the computations of basic and diluted net income per share for the three and nine months ended September 30, 2008. Basic and diluted net loss per share was the same in each of the three and nine month periods ended September 30, 2009.

		Three Months Ended				Nine Months Ended
		September 30, 2008				September 30, 2008
Numerator:
Basic net income		$	21,039,898			$	15,841,173
Interest on convertible senior notes			901,096				—
Diluted net income, adjusted for interest on convertible senior notes		$	21,940,994			$	15,841,173
Denominator:
Basic weighted average common shares outstanding			107,499,883				107,195,454
Effect of dilutive securities:
Options to purchase common stock			4,626,004				4,759,909
Assumed treasury shares purchased			(2,662,597	)			(2,673,385	)
Unvested restricted stock			279,420				279,420
Shares issued upon conversion of convertible senior notes			16,250,000				—
Diluted weighted average common shares outstanding			125,992,710				109,561,398
Basic net income per share		$	0.20			$	0.15
Diluted net income per share		$	0.17			$	0.14

The 16,250,000 shares of common stock that would have been issued upon conversion of the 5.50% Convertible Senior Notes due 2011 issued on October 20, 2004 (the “Convertible Notes”) have been excluded from the diluted weighted average shares outstanding during the nine months ended September 30, 2008 because the inclusion of such shares would have been anti-dilutive. For the three and nine months ended September 30, 2008, 5,780,926 and 5,438,059 options to purchase common stock, respectively, were excluded from the diluted weighted average shares outstanding because the exercise of these options would have been anti-dilutive.

For the three and nine months ended September 30, 2009, common stock equivalents of 28,567,537 have been excluded from the computation of diluted net income (loss) per share, including the 16,250,000 shares of common stock that would have been issued upon conversion of the Convertible Notes.

Use of Estimates

The preparation of the financial statements for the Company in conformity with 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 the fair value of derivative instruments and impairments to unproved property.

Reclassifications

Derivative gains and interest income in 2008 have been reclassified from revenues to other income (expense) and interest expense has been reclassified from operating expenses to other income (expense) to be consistent with the 2009 presentation. The following table summarizes the reclassification of these items within the consolidated statements of operations and cash flows for the nine months ended September 30, 2008:

		Nine Months Ended
		September 30, 2008								Nine Months Ended
		(Previously								September 30, 2008
		Reported)				Reclassification				(As Reclassified)
Total revenues		$	40,808,389			$	5,730,886			$	35,077,503
Total operating expenses			24,967,216				(3,727,513	)			21,239,703
Other income			—				2,003,373				2,003,373

Recently Issued Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued “FASB Accounting Standards Codification^™ (“Codification”), as the single source of authoritative US GAAP” for all non-governmental entities, with the exception of the SEC and its staff. The Codification, which became effective July 1, 2009, changes the referencing and organization of accounting guidance and is effective for interim and annual periods ending after September 15, 2009. The Company adopted the Codification on July 1, 2009 which provides for changes in references to technical accounting literature (if used) in this Quarterly Report on Form 10-Q and subsequent reports, but did not have a material impact on the Company’s financial position, results of operations or cash flows.

In September 2006, the FASB issued accounting guidance related to fair value measurements and related disclosures. This new guidance defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The Company adopted this guidance on January 1, 2008, as required for its financial assets and financial liabilities. However, the FASB deferred the effective date of this guidance for one year as it relates to fair value measurement requirements for nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed at fair value on a recurring basis, which include, among others, those nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. Fair value used in the initial recognition of asset retirement obligations is determined based on the present value of expected future dismantlement costs incorporating our estimate of inputs used by industry participants when valuing similar liabilities. Accordingly, the fair value is based on unobservable pricing inputs and therefore, is considered a level 3 value input in the fair value hierarchy (See Note 5 “Fair Value Measurements” herein). The adoption of this accounting guidance related to these items did not have a material impact on the Company’s financial position or results of operations.

In March 2008, the FASB issued new accounting guidance related to disclosures about derivative instruments and hedging activities. This guidance amends and expands disclosure requirements to provide a better understanding of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and their effect on an entity’s financial position, financial performance, and cash flows. This guidance is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company adopted this guidance January 1, 2009, which requires additional disclosures regarding the Company’s derivative instruments in this Quarterly Report on Form10-Q and subsequent reports, but did not have an impact on the Company’s financial position or results of operations. See Note 2 “Derivatives” herein for the required disclosures.

In April 2009, the FASB issued additional guidance regarding fair value measurements and impairments of securities which makes fair value measurements more consistent with fair value principles, enhances consistency in financial reporting by increasing the frequency of fair value disclosures, and provides greater clarity and consistency in accounting for and presenting impairment losses on securities. The additional guidance is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the provisions for the period ending March 31, 2009. The adoption

did not have a material impact on its financial position or results of operations.

In April 2009, the FASB issued new accounting guidance related to interim disclosures about the fair values of financial instruments. This guidance requires disclosures about the fair value of financial instruments whenever a public company issues financial information for interim reporting periods. This guidance is effective for interim reporting periods ending after June 15, 2009. The Company adopted this guidance upon its issuance, which requires additional disclosures regarding the fair value of financial instruments in this Quarterly Report on Form10-Q and subsequent reports, but had no material impact on the Company’s consolidated financial statements. See Note 5 “Fair Value Measurements” herein for the required disclosures.

In June 2009, the FASB issued new accounting guidance related to the accounting and disclosures of subsequent events. This guidance incorporates the subsequent events guidance contained in the auditing standards literature into authoritative accounting literature. It also requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. This guidance is effective for all interim and annual periods ending after June 15, 2009. The Company adopted this guidance upon its issuance and it had no material impact on the Company’s consolidated financial statements. The Company evaluates subsequent events up to immediately prior to the issuance of its financial statements, and for purposes of the accompanying consolidated financial statements, the Company has evaluated subsequent events through November 3, 2009, the filing date of this 10-Q, and has disclosed such items in Note 4 “Credit Facility” herein.

In August 2009, the FASB issued new accounting guidance to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. This guidance became effective for us on October 1, 2009. The Company adopted this guidance on October 1, 2009, and it had no material impact on its consolidated financial statements.

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

In September 2009, the FASB issued its proposed updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Extractive Industries—Oil and Gas (Topic 932) with the requirements in the SEC’s final rule discussed above. The public comment period for the FASB’s proposed updates ended October 15, 2009; however, no final guidance has been issued by the FASB. The Company is evaluating the potential impact of any updates to the oil

and gas accounting rules and will comply with any new accounting and disclosure requirements once they become effective. The Company anticipates that the following rule changes could have a significant impact on its results of operations as follows:

	•		The price used in calculating reserves will change from a single-day closing price measured on the last day of the company’s fiscal year to a 12-month average price, and will affect the Company’s depletion and ceiling test calculations.
	•		Several reserve definitions have changed that could revise the types of reserves that will be included in the Company’s year-end reserve report.

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

NOTE 3 — STOCK-BASED COMPENSATION

The Company has outstanding common stock options and restricted stock issued under its equity incentive plans (see Note 3 “Stock-Based Compensation” to the consolidated financial statements in the Company’s 2008 10-K for additional information). 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.

During the three and nine months ended September 30, 2009 and 2008, the Company recognized stock-based compensation as follows:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Total stock-based compensation		$	505,657			$	652,828			$	1,467,294			$	2,295,117
Consultant compensation (expense) reduction in expense capitalized as proved property			(7,638	)			54,116				(5,184	)			(59,095	)
Stock-based compensation expense		$	498,019			$	706,944			$	1,462,110			$	2,236,022

The Company records stock compensation related to the unvested stock options issued to non-employees by recalculating the amount of compensation expense at the end of each reporting period based upon the fair value on that date. Stock-based non-employee compensation expense for the three and nine months ending September 30, 2009 and 2008 is summarized as follows.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Total non-employee stock-based compensation		$	15,286			$	(96,345	)		$	14,348			$	144,029
Non-employee compensation (expense) reduction in expense capitalized as proved property			(7,638	)			54,116				(5,184	)			(59,095	)
Stock-based non-employee compensation expense		$	7,648			$	(42,229	)		$	9,164			$	84,934

Stock Options

The following table summarizes the stock option activity in the equity incentive plans from January 1, 2009 through September 30, 2009:

		Shares Underlying				Weighted-Average
		Stock Options				Exercise Price
Outstanding at January 1, 2009			11,124,788			$	2.06
Granted			1,752,083			$	0.66
Exercised			—				—
Forfeited			(152,624	)		$	1.75
Cancelled			(406,710	)		$	3.78
Outstanding at September 30, 2009			12,317,537			$	1.81
Exercisable at September 30, 2009			8,780,643			$	2.05

During the nine months ended September 30, 2009, the Company granted options to purchase 1,752,083 shares of common stock with exercise prices ranging from $0.22 to $5.69 per share. The weighted average grant-date fair value of the options granted during the nine months ended September 30, 2009 was $0.33 per share.

The following table summarizes information related to the outstanding and vested options as of September 30, 2009:

		Outstanding
		Options				Vested options
Number of shares			12,317,537				8,780,643
Weighted Average Remaining Contractual Life			4.48				4.13
Weighted Average Exercise Price		$	1.81			$	2.05
Aggregate intrinsic value		$	14,100			$	2,900

The aggregate intrinsic value in the table above represents the total pretax intrinsic value, which is the amount by which the market value of the Company’s stock at September 30, 2009 of $0.49 exceeds the exercise price of certain outstanding options.

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

As of September 30, 2009, there was $2,268,475 of total unrecognized compensation cost related to non-vested options granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 3.0 years.

Restricted Stock

The following table summarizes the restricted stock activity from January 1, 2009 through September 30, 2009:

						Weighted-Average
		Restricted				Grant Date
		Stock				Fair Value
Outstanding at January 1, 2009			233,300			$	2.35
Granted			7,500			$	0.25
Vested			(26,900	)		$	2.17
Forfeited			(31,500	)		$	1.32
Outstanding at September 30, 2009			182,400			$	2.47

As of September 30, 2009, there was $265,886 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a period of 3.0 years.

NOTE 4 — CREDIT FACILITY

On October 30, 2009, the Company and certain of its subsidiaries as guarantors, the lenders party thereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as administrative agent (the “Administrative Agent”), entered into the Seventh Amendment to Credit Agreement (the “Seventh Amendment”), amending that certain Credit Agreement, dated as of March 29, 2006 (as amended by the First, Second, Third, Fourth, Fifth and Sixth Amendments thereto, and as further amended by this Seventh Amendment, the “Credit Agreement”). Pursuant to the Seventh Amendment, the Credit Agreement was amended, among other things, to revise the definition of “Redetermination Date” with respect to scheduled redeterminations for the year ended December 31, 2009 to be on or about May 1 and November 30 of such year, thereby delaying the scheduled mid-year redetermination originally scheduled to occur on or about November 1, 2009. With respect to any scheduled redeterminations in subsequent years, however, the Redetermination Date continues to be on or about May 1 and November 1 of each such year.

Pursuant to the Seventh Amendment, should there be a borrowing base deficiency after the scheduled redetermination on or about November 30, 2009, the Company will have 30 days to eliminate such deficiency.

On September 30, 2009, the Company and the other parties to the Credit Agreement entered into the Sixth Amendment to Credit Agreement (the “Sixth Amendment”), pursuant to which the Credit Agreement was amended, among other things, to delay indefinitely the special redetermination of the Company’s borrowing base previously scheduled to occur on or about September 30, 2009.

On August 28, 2009, the Company and the other parties to the Credit Agreement entered into the Fifth Amendment to Credit Agreement (the “Fifth Amendment”), pursuant to which the Credit Agreement was amended, among other things, to increase the interest rate pricing grid by 25 b.p. for Eurodollar based loans and for Alternate Base Rate (“ABR”) priced loans with respect to any periods in which the Company has utilized at least 90% of the borrowing base. Interest on borrowings under the Credit Agreement accrues at variable interest rates at either a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies from 2.50% (for periods in which the Company has utilized less than 50% of the borrowing base) to 3.50% (for periods in which the Company has utilized at least 90% of the borrowing base).

The alternate base rate 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 LIBO Rate for a one month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.50% (for periods in which the Company has utilized less than 50% of the borrowing base) to 2.50% (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 Agreement. 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 Fifth Amendment also delayed the special redetermination of the Company’s borrowing base previously scheduled to occur on or about August 31, 2009, to on or about September 30, 2009. This September 30, 2009 special redetermination was delayed indefinitely pursuant to the Sixth Amendment, as described above.

On July 6, 2009, the Company and the other parties to the Credit Agreement entered into the Fourth Amendment to Credit Agreement (the “Fourth Amendment”), pursuant to which the Credit Agreement was amended, among other things, to delay the special redetermination of the Company’s borrowing base previously scheduled to occur on or about June 30, 2009, to on or about August 31, 2009. This August 31, 2009 special redetermination was delayed pursuant to the Fifth Amendment, as described above.

On May 14, 2009, the Company and the other parties to the Credit Agreement entered into the Third Amendment to the Credit Agreement (the “Third Amendment”). Pursuant to the Third Amendment, the Credit Agreement was amended to, among other things: (i) increase the interest rate pricing grid; (ii) amend the definition of LIBO Rate to include a floor of 2.00%; (iii) increase the required collateral coverage and the title requirement relating thereto; (iv) require the Company to engage a financial consultant on or prior to May 29, 2009 and (v) permit the Company to monetize its commodity hedges and use the proceeds to pay down outstanding borrowings under the Credit Agreement.

Furthermore, the Third Amendment involved a redetermination of the Company’s borrowing base, which was lowered to $35,000,000 from $45,000,000. Because the amount borrowed exceeded the revised borrowing base by approximately $9,000,000, the Company was required to prepay the Credit Agreement by an amount equal to the deficiency. On May 7, 2009, the Company monetized selected oil and natural gas hedge contracts and the net proceeds of $8,528,731 were used to repay a portion of the deficiency and the remainder was repaid with cash on hand as described in Note 2.

As stated, the Third Amendment revised the definition of LIBO Rate to include a floor of 2.00%. The Minimum Collateral Amount required under the Credit Agreement was set at 55% of the Engineered Value of Borrowing Base Properties for the 10-day period commencing on the Effective Date and is required to increase to 90% of the Engineered Value of Borrowing Base Properties thereafter. The related title requirement was also increased to require evidence of title to 80% of the applicable Minimum Collateral Amount percentage of the Engineered Value of Borrowing Base Properties.

Finally, the Third Amendment required the Company to retain a financial consultant acceptable to the Administrative Agent by May 29, 2009, for and until such time as the Administrative Agent

consents to termination. Accordingly, effective May 29, 2009, the Company executed an engagement letter with an entity who is currently acting as the Company’s financial consultant and advisor with the approval of the Administrative Agent.

The Credit Agreement is available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes. Borrowings made under the Credit Agreement are secured by a pledge of the capital stock of the Guarantors 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.

The Credit Agreement requires the Company to comply with financial covenants that require it to maintain (1) a current ratio (defined as current assets plus unused availability under the Credit Agreement divided by current liabilities excluding the current portion of the Credit Agreement), determined at the end of each quarter, of not less than 1.0:1.0; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Agreement) for the most recent four quarters not to be greater than 3.5:1.0 for each fiscal quarter. In addition, the Credit Agreement contains covenants that restrict the Company’s ability to incur other indebtedness, create liens or sell the Company’s assets, pay dividends on the Company’s common stock and make certain investments. Sustained or lower oil and natural gas prices could reduce the Company’s consolidated EBITDAX and thus could reduce the Company’s ability to maintain existing levels of Senior Debt or incur additional indebtedness. Additionally, at current commodity prices, EBITDAX will be reduced for the four quarters beginning with the first quarter of 2009 by the payment of approximately $4.7 million for early termination of the Company’s drilling contract in February 2009, resulting in a corresponding reduction in the levels of senior debt that the Company may have outstanding going forward without violating its senior debt to EBITDAX ratio. Any failure to be in compliance with any material provision or covenant of the Credit Agreement could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under the Credit Agreement. Additionally, should the Company’s obligation to repay indebtedness under the Credit Agreement be accelerated, the Company would be in default under the indenture governing the Convertible Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes. To the extent it becomes necessary to address any anticipated covenant compliance issues, the Company will seek to obtain a waiver or amendment of the Credit Agreement 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.

The Credit Agreement provides for semi-annual evaluation of the borrowing base, based on the Lenders’ valuation of the Company’s proved reserves and their internal criteria. In addition to such semi-annual scheduled determinations, the Lenders may request one additional special redetermination between each semi-annual scheduled calculation. The Company’s aggregate borrowings and outstanding letters of credit under the Credit Agreement may not at any time exceed the borrowing base. If the Company’s borrowing base is reduced as a result of a redetermination to a level below its then current outstanding borrowings, it will be required to repay the amount by which such outstanding borrowings exceed the borrowing base within 30 days of notification by the

Lenders, and the Company will have less or no access to borrowed capital going forward. If the Company does not have sufficient funds on hand for repayment, it will be required to seek a waiver or amendment from its Lenders, refinance its Credit Agreement or sell assets or additional shares of common stock. The Company may not be able to refinance or complete such transactions on terms acceptable to it, or at all. In the event that the Company is unable to repay the amount owed within 30 days, the Company will be in default under the Credit Agreement, and as such the Lenders will have the right to terminate their aggregate commitment under the Credit Agreement and declare the outstanding borrowings of the Company immediately due and payable in whole. An acceleration of the outstanding indebtedness under the Credit Agreement in this manner would additionally constitute an event of default under the indenture governing to the Convertible Notes. Should an event of default occur and continue under the indenture governing to the Convertible Notes, the Convertible Notes may be declared immediately due and payable at their principal amount together with accrued interest and liquidated damages, if any. As such, should the Company anticipate that it will not be able to repay all amounts owed under the Credit Agreement as a result of the anticipated borrowing base redetermination, it will consider, along with previously discussed refinancing and sales, a sale of the Company or its assets as well as a voluntary reorganization in bankruptcy. Additionally, if the Company is unable to repay amounts owed under the Credit Agreement, it may be forced into an involuntary reorganization in bankruptcy. The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments, if any, that might result form the effects of the borrowing base redetermination and subsequent transactions.

As of September 30, 2009, there were loans of $34,544,969 outstanding and letters of credit in the amount of $455,029 under the Credit Agreement, which are considered usage for purposes of calculating availability and commitment fees.

As of September 30, 2009, the Company’s current and senior debt to EBITDAX ratios were 2.9:1.0 and 2.0:1.0, respectively, and the Company was in compliance with each of the covenants contained in the Credit Agreement.

NOTE 5 — FAIR VALUE MEASUREMENTS

Effective January 1, 2008, the Company adopted the authoritative guidance that applies to all financial assets and liabilities required to be measured and reported on a fair value basis. Beginning January 1, 2009, the Company also applied the guidance to non-financial assets and liabilities. The 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 flow 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, 2009 by level within the fair value hierarchy:

		Fair Value Measurements Using
		Level 1				Level 2				Level 3				Total
Assets		$	—			$	—			$	—			$	—
Liabilities:
Derivative instruments		$	—			$	(3,214,078	)		$	—			$	(3,214,078	)

During May 2009, the Company monetized selected oil and natural gas hedge contracts consisting of two natural gas swap agreements and one costless collar agreement for net proceeds of $8,528,731. Concurrent with the monetization of these hedges, the Company re-hedged a portion of its production for the period June 2009 through March 2011 as further detailed in Note 2 “Significant Accounting Policies-Derivatives” herein.

As of September 30, 2009, the Company’s 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 hierarchy. Until May 2009, the Company’s derivative financial instruments also included a costless collar agreement. The fair value of the costless collar agreement was determined based on both observable and unobservable pricing inputs and therefore, the data sources utilized in this valuation model was considered level 3 inputs in the fair value hierarchy. The counterparty in all of the Company’s derivative financial instruments is the Administrative Agent under the Credit Agreement. See Note 4 “Credit Facility” herein.

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

		Derivatives as of September 30,
		2009				2008
Balance as of January 1		$	2,644,534			$	—
Total gains (losses) (realized or unrealized):
Included in earnings			916,493				1,726,661
Included in other comprehensive income			—				—
Purchases, issuances and settlements			(3,561,027	)			382,607
Transfers in and out of level 3			—				—
Balance as of September 30		$	—			$	2,109,268
Change in unrealized gains (losses) included in earnings relating to derivatives still held as of September 30,		$	—			$	2,109,268

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, Convertible Notes and long-term debt. With the exception of the note receivable, Convertible 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 on current interest rates for similar instruments. Estimated fair values for Convertible Notes of $29,575,000 and $39,081,250 as of September 30, 2009 and December 31, 2008, respectively, have been determined using recent market quotes.

NOTE 6 — STATEMENT OF CASH FLOWS

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 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.

During the nine months ended September 30, 2008, the Company’s non-cash investing and financing activities consisted of the following transactions:

•

Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $35,463.

	•		Reduction in asset retirement obligation of $10,179 for the plugging and abandonment costs and $11,107 due to property dispositions.
	•		Stock-based compensation of $59,095 capitalized as proved property.
	•		Additions to oil and gas properties included in accounts payable of $5,574,568.

Cash paid for interest during the nine months ended September 30, 2009 and 2008 was $3,056,357 and $2,391,175, respectively. There was no cash paid for income taxes during the nine months ended September 30, 2009 and 2008.

NOTE 7 — 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 flow.

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 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. Although the Company is unable to estimate a range of possible costs, the Company believes that all necessary pollution control and other equipment likely to be required by such a resolution is already installed at the site or accounted for in the Company’s capital budget, and that any civil penalty that may be assessed in conjunction with a resolution of this matter will not materially affect the Company’s financial position or liquidity. The compliance

costs could, however, materially affect the Company’s results of operations for a particular period.

On December 5, 2008, a lawsuit was filed in state court in Cook County, Illinois. The lawsuit alleges that Defendants Richard N. Jeffs, Marc Bruner and Gasco Energy, Inc. through its agency with Mr. Bruner, made misrepresentations, committed fraud, aided and abetted a scheme to defraud, and conspired to defraud in connection with the plaintiffs investment in Brek Energy Corporation (“Brek”). The complaint alleges that plaintiffs’ relied on various misrepresentations and omissions by the individual defendants when making the decision to invest in Brek, which merged into Gasco in December of 2007. Gasco removed the case to the United States District Court for the Northern District of Illinois, Eastern Division, on January 7, 2009 and answered the Complaint, denying all liability, on February 13, 2009. Gasco intends to vigorously defend the claims filed against it. A scheduling conference was held on April 1, 2009. The judge ordered fact discovery in the case to be completed by December 15, 2009 and set the trial for June 7, 2010. Following the scheduling conference, Richard N. 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). The motion to dismiss is fully briefed, but the Court has not yet made a decision on the motion. All defendants have been served, and the parties are engaged in the early stages of discovery.

At this time the Company has not formed an opinion that an unfavorable outcome is either “probable” or “remote” consequently, the Company expresses no opinion as to the likelihood of an unfavorable outcome or any range of possible loss.

NOTE 8 — CONSOLIDATING FINANCIAL STATEMENTS

On August 22, 2008, Gasco filed a Form S-3 shelf registration statement with the SEC. Under this registration statement, which was declared effective on September 8, 2008, Gasco may from time to time offer and sell securities including common stock, preferred stock, depositary shares and debt securities that may be fully, irrevocably and unconditionally guaranteed by all of its subsidiaries: Gasco Production Company, San Joaquin Oil & Gas, Ltd., Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (collectively, the “Guarantor Subsidiaries”). Set forth below are the condensed consolidating financial statements of Gasco, which is referred to as the Parent, and the Guarantor Subsidiaries. In accordance with US GAAP the financial statements of the Parent would include an investment in its subsidiaries. These condensed statements are presented for information purposes only and do not purport the Parent’s balance sheet or statement of operations are prepared under US GAAP.

Condensed Consolidating Balance Sheet
As of September 30, 2009
(Unaudited)

						Guarantor
		Parent				Subsidiaries				Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	795,199			$	11,546,206			$	12,341,405
Accounts receivable			393,510				2,141,862				2,535,372
Inventory			—				1,074,587				1,074,587
Prepaid expenses			8,748				—				8,748
Total			1,197,457				14,762,655				15,960,112
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved properties			76,205				253,367,683				253,443,888
Unproved properties			1,054,096				38,275,560				39,329,656
Gathering assets			—				17,784,520				17,784,520
Facilities and equipment			—				6,377,952				6,377,952
Furniture, fixtures and other			371,674				—				371,674
Total			1,501,975				315,805,715				317,307,690
Less accumulated depreciation, depletion and amortization			(277,054	)			(230,335,183	)			(230,612,237	)
Total			1,224,921				85,470,532				86,695,453
OTHER ASSETS
Deposit			139,500				—				139,500
Note receivable			—				500,000				500,000
Deferred financing costs			1,025,127				—				1,025,127
Intercompany			247,289,740				(247,289,740	)			—
Total			248,454,367				(246,789,740	)			1,664,627
TOTAL ASSETS		$	250,876,745			$	(146,556,553	)		$	104,320,192
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable		$	41,483			$	507,378			$	548,861
Revenue payable			—				2,279,605				2,279,605
Derivative instruments			1,543,019				—				1,543,019
Accrued interest			1,747,144				—				1,747,144
Accrued expenses			848,000				—				848,000
Total			4,179,646				2,786,983				6,966,629
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes			65,000,000				—				65,000,000
Long-term debt			34,544,969				—				34,544,969
Derivative instruments			1,671,059				—				1,671,059
Asset retirement obligation			—				1,231,899				1,231,899
Deferred rent expense			27,063				—				27,063
Total			101,243,091				1,231,899				102,474,990
STOCKHOLDERS’ EQUITY (DEFICIT)
Common stock			10,780				—				10,780
Other			145,443,228				(150,575,435	)			(5,132,207	)
Total			145,454,008				(150,575,435	)			(5,121,427	)
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)		$	250,876,745			$	(146,556,553	)		$	104,320,192

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

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

Consolidating Statements of Operations
(Unaudited)

						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
Rental income			—				—				—
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	)

						Guarantor
For the Three Months Ended September 30, 2008		Parent				Subsidiaries				Consolidated
REVENUES
Oil and gas		$	—			$	9,668,027			$	9,668,027
Gathering			—				1,248,483				1,248,483
Rental income			—				312,344				312,344
Total			—				11,228,854				11,228,854
OPERATING EXPENSES
Lease operating			—				1,224,416				1,224,416
Gathering operations			—				1,004,061				1,004,061
Depletion, depreciation, amortization and accretion			46,621				1,656,061				1,702,682
General and administrative			2,113,675				—				2,113,675
Total			2,160,296				3,884,538				6,044,834
OTHER INCOME (EXPENSE)
Interest expense			(1,248,702	)			—				(1,248,702	)
Derivative gain			17,099,899				—				17,099,899
Interest income			4,678				3				4,681
Total			15,855,875				3				15,855,878
NET INCOME		$	13,695,579			$	7,344,319			$	21,039,898

Consolidating Statements of Operations
(Unaudited)

						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	)