Gasco Energy (GSXN) 10-Q 2012 Q2 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 June 30, 2012

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 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)	(I.R.S. Employer Identification No.)

7979 E. Tufts Avenue, Suite 1150, Denver, Colorado 80237

(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 x  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 o	Smaller reporting company x
(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 July 31, 2012:  169,749,981

Table of Contents

	PART I — FINANCIAL INFORMATION
Cautionary Statement Regarding Cautionary Forward-Looking Statement		3
Item 1.	Financial Statements (Unaudited)	8
	Condensed Consolidated Balance Sheets	8
	Condensed Consolidated Statements of Operations	10
	Condensed Consolidated Statements of Cash Flows	12
	Notes to Condensed Consolidated Financial Statements	13
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	44
	PART II —OTHER INFORMATION
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 6.	Exhibits	45

2

Cautionary Statement Regarding Forward-Looking Statements

Some of the information in this Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.  All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q, including, without limitation, statements regarding our future financial position, expectations with respect to our liquidity and capital resources, 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 current expectations or forecasts about future events. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “should,” “would,” “could,” “expect,” “plan,” “intend,” “project,” “estimate,” “anticipate,” “believe” or “continue” or the negative thereof or similar terminology.

Although any forward-looking statements contained in this Quarterly Report on Form 10-Q or otherwise expressed by us are, to the knowledge and in the judgment of our management, believed to be reasonable when made, 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 (some of which are beyond our control) which may cause our actual performance and financial results in future periods to differ materially from any projection, estimate or forecasted result. Known material factors that could cause actual results to differ materially from expected results are discussed under Part I, Item 1A “Risk Factors” and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2011 and under Part II, Item 1A “Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q. Additional risks or uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or future results.

The following are  the known factors that could cause future results to differ materially from any projected, forecasted, estimated or budgeted amounts that we have discussed in this Quarterly Report on Form 10-Q:

·our ability to maintain adequate cash flow from operations or to obtain adequate financing to fund our capital expenditures, meet working capital needs and grow our operations;

·our ability to secure adequate alternative financing to replace our prior revolving credit facility, and the terms of any such financing;

·overall demand for natural gas and oil in the United States and related fluctuations in natural gas and oil prices, upon which our operating results are directly dependent and which impact our ability to produce economically and may affect our borrowing base under any future credit agreement;

·our ability to successfully operate our business within the restrictions imposed on us by our debt agreements;

·any requirement that we write down the carrying value of our oil and gas properties due to reductions in natural gas and oil prices or substantial downward adjustments to our estimated proved reserves;

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

·any failure by the gatherer of our natural gas, which would negatively affect our ability to deliver our natural gas production for sale;

·marketing of oil and natural gas;

3

·pipeline constraints;

·estimated reserves of natural gas and oil and underlying assumptions of such estimated reserves;

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

·acquisition and development of oil and gas properties, and replacement of reserves;

·delays in obtaining drilling permits and the timing and amount of future production of natural gas and oil;

·technological changes;

·competition;

·scope and extent of our insurance coverage;

·title defects and deficiencies;

·federal and state regulatory or legislative developments, including with respect to environmental matters;

·shortages of supplies, equipment and personnel, and increases in operating costs and other expenses generally;

·general economic conditions in the United States and key international markets, including credit and capital market constraints; and

·our ability to remain in compliance with the NYSE MKT’s continued listing requirements.

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. 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 made by us are expressly qualified in their entirety by these factors.  Readers are cautioned not to place undue reliance on our forward-looking statements, which speak only as of the date made. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

4

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 that may be used in this Quarterly Report on Form 10-Q.

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.

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.

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

Mcf.  Thousand cubic feet of natural gas.

5

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.

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.

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 general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. PV-10 is a non-GAAP financial measure.

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

Proved reserves or 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.

Proved properties.  Properties with proved reserves.

6

Proved undeveloped reserves.  Proved 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved 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 tests in the area and in the same reservoir.

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

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% annual discount rate.

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.

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.

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ITEM I — FINANCIAL STATEMENTS

PART 1 — FINANCIAL INFORMATION

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
	2012			2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,135,729		$	1,965,967
Accounts receivable
Joint interest billings	2,113,859			810,482
Revenue	596,568			1,483,382
Inventory	1,903,388			1,911,362
Note receivable	500,000			500,000
Derivative instruments	—			865,358
Prepaid expenses	73,699			152,045
Total	10,323,243			7,688,596
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved properties	255,738,109			268,793,463
Unproved properties	37,915,582			36,938,162
Wells in progress	—			1,938,691
Facilities and equipment	1,464,475			1,502,921
Furniture, fixtures and other	494,781			167,737
Total	295,612,947			309,340,974
Less accumulated depletion, depreciation, amortization and impairment	(243,462,407		)	(234,132,806		)
Total	52,150,540			75,208,168
NONCURRENT ASSETS
Deposit	564,638			639,500
Deferred financing costs	983,793			1,117,972
Total	1,548,431			1,757,472
TOTAL ASSETS	$	64,022,214		$	84,654,236

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

8

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

(Unaudited)

	June 30,			December 31,
	2012			2011
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	815,905		$	2,649,772
Revenue payable	1,734,445			2,043,240
Advances from joint interest owners	96,733			98,512
Current portion of long-term debt	—			8,544,969
Accrued interest	586,556			586,556
Accrued expenses	251,816			355,224
Total	3,485,455			14,278,273
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes due 2015, net of unamortized discount of $20,684,318 as of June 30, 2012 and $22,574,687 as of December 31, 2011	24,483,682			22,593,313
Deferred income from sale of assets	2,564,403			2,665,629
Asset retirement obligation	779,197			1,226,796
Derivative instruments	2,837,500			4,235,000
Deferred rent	281,390			—
Total	30,946,172			30,720,738
STOCKHOLDERS’ EQUITY
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; 182,065 shares outstanding as of June 30, 2012 and 191,000 shares outstanding as of December 31, 2011	182			191
Common stock - $0.0001 par value; 600,000,000 shares authorized; 169,823,681 shares issued and 169,749,981 outstanding as of June 30, 2012 and 168,084,515 shares issued and 168,010,815 outstanding as of December 31, 2011	16,982			16,808
Additional paid-in capital	262,489,186			262,344,286
Accumulated deficit	(232,785,468		)	(222,575,765		)
Less cost of treasury stock of 73,700 common shares	(130,295		)	(130,295		)
Total	29,590,587			39,655,225
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	64,022,214		$	84,654,236

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

9

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months EndedJune 30,
	2012			2011
REVENUES
Gas	$	1,273,178		$	4,609,574
Oil	330,695			1,145,897
Total	1,603,873			5,755,471
OPERATING EXPENSES
Lease operating	1,152,462			1,707,734
Transportation and processing	518,394			901,384
Depletion, depreciation, amortization and accretion	648,239			985,744
Impairment	3,755,000			—
General and administrative	1,112,620			945,342
Total	7,186,715			4,540,204
OPERATING (LOSS) INCOME	(5,582,842		)	1,215,267
OTHER (EXPENSE) INCOME
Interest expense	(1,659,945		)	(1,551,875		)
Derivative gains	2,024,957			309,283
Amortization of deferred income from sale of assets	50,613			50,613
Interest income	15,658			6,881
Total	431,283			(1,185,098		)
NET (LOSS) INCOME	$	(5,151,559	)	$	30,169
NET (LOSS) INCOME PER COMMON SHARE —
BASIC	$	(0.03	)	$	0.00
DILUTED	$	(0.03	)	$	0.00

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

10

GASCO ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Six Months EndedJune 30,
	2012			2011
REVENUES
Gas	$	3,581,042		$	8,312,605
Oil	1,203,098			1,711,971
Total	4,784,140			10,024,576
OPERATING EXPENSES
Lease operating	2,840,463			3,049,166
Transportation and processing	1,175,366			1,703,099
Depletion, depreciation, amortization and accretion	1,498,266			1,835,568
Impairment	8,055,000
General and administrative	2,517,602			2,071,505
Total	16,086,697			8,659,338
OPERATING (LOSS) INCOME	(11,302,557		)	1,365,238
OTHER INCOME (EXPENSE)
Interest expense	(3,388,714		)	(3,415,770		)
Gain on sale of assets	2,567,574			—
Derivative gains	1,788,090			373,236
Amortization of deferred income from sale of assets	101,226			101,226
Interest income	24,678			13,762
Total	1,092,854			(2,927,546		)
NET LOSS	$	(10,209,703	)	$	(1,562,308	)
NET LOSS PER COMMON SHARE — BASIC AND DILUTED	$	(0.06	)	$	(0.01	)

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

11

GASCO ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(10,209,703	)	$	(1,562,308	)
Adjustment to reconcile net loss to net cash (used in) provided by operating activities:
Depletion, depreciation, amortization, accretion and impairment expense	9,553,266			1,835,568
Stock-based compensation	136,861			176,178
Change in fair value of derivative instruments	(532,142		)	36,384
Gain on sale of assets	(2,567,574		)	—
Amortization of debt discount, deferred expenses and other	1,925,462			1,491,531
Payment of deposit	(46,138		)	—
Changes in operating assets and liabilities:
Accounts receivable	(410,627		)	(59,013		)
Inventory	7,974			(33,881		)
Prepaid expenses	78,346			47,876
Accounts payable	(1,119,867		)	(691,520		)
Revenue payable	(308,795		)	1,298,342
Accrued expenses	25,785			(615,442		)
Net cash (used in) provided by operating activities	(3,467,152		)	1,923,715
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture, fixtures and other	(196,572		)	(892		)
Cash paid for acquisitions, development and exploration	(3,812,087		)	(3,817,400		)
Proceeds from sale of assets	19,192,321			—
Decrease in advances from joint interest owners	(1,779		)	(1,032,248		)
Net cash provided by (used in) investing activities	15,181,883			(4,850,540		)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit	2,000,000			2,000,000
Repayment of borrowings	(10,544,969		)	—
Proceeds from issuance of common stock and warrants	—			6,000,000
Cash paid for stock offerings and debt issuance costs	—			(942,346		)
Net cash (used in) provided by financing activities	(8,544,969		)	7,057,654
NET INCREASE IN CASH AND CASH EQUIVALENTS	3,169,762			4,130,829
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD	1,965,967			1,994,542
END OF PERIOD	$	5,135,729		$	6,125,371

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

12

GASCO ENERGY, INC.

NOTES TO UNAUDITED CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS

THREE AND SIX MONTHS ENDED JUNE 30, 2012 AND 2011

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 in accordance with generally accepted accounting principles in the United States (“US GAAP”) applicable to interim financial statements and with the instructions to Form 10-Q and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, they do not include all of the information and footnotes required by US GAAP for complete financial statements.  The accompanying unaudited condensed consolidated financial statements 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 of the Company for the interim periods presented.  Such financial statements conform to the presentation reflected in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 10-K”) filed with the SEC on March 28, 2012. The current interim period financial statements included herein should be read in conjunction with the financial statements and accompanying notes, including Note 2 — Significant Accounting Policies, included in the Company’s 2011 10-K.

The Company faces significant uncertainties relating to its ability to generate sufficient cash flows from operations to fund its on-going operations and planned capital activities. Specifically, the Company had a net loss and negative cash flow from operations during the first six months of 2012. Furthermore, its credit facility matured on June 29, 2012.

While the Company believes that cash on hand and forecasted cash flows will be sufficient to fund cash requirements for working capital and planned capital expenditures through the second quarter of 2013, there can be no assurance and there is significant risk those plans may not be achieved for, among other reasons, existing market conditions.  Failure to generate operating cash inflows or to obtain additional financing for the development of our properties could adversely affect the Company’s liquidity and ability to meet its obligations as they come due. Further, we may not achieve profitability from operations in the near future or at all. Our failure to achieve profitability in the future could materially adversely affect the trading price of our common stock as well as our ability to raise additional capital to fund our operations.

The results of operations for the six months ended June 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.

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NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include Gasco and its wholly -owned subsidiaries. All significant intercompany transactions have been eliminated.

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 $2,883 and $11,520 of internal costs during the three and six months ended June 30, 2012, respectively, and $26,594 and $75,167 during the three and six months ended June 30, 2011, respectively. Additionally, the Company capitalized stock compensation expense related to its consultants as further described in Note 7 — Stock-Based Compensation herein. Costs associated with production and general corporate activities are expensed in the period incurred. The Company charges 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 (loss) attributable to the outside working interest owners from such marketing activities of $37,317 and $31,804 was recorded as an adjustment to proved properties during the three and six months ended June 30, 2012, respectively, and $28,341 and $66,335 during the three and six months ended June 30, 2011. 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 a cost center.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. Please see Note 3 — Asset Sales, herein.

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include: (i) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion; (ii) estimated future development costs to be incurred in developing proved reserves; and (iii) 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.

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, the ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent the excess capitalized costs exceed this ceiling limitation. The present value of estimated future net revenues is computed by applying the average first-day-of-

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the-month oil and gas price during the 12-month period ended June 30, 2012 to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. As of March 31, 2012 and June 30, 2012, the full cost pool exceeded the ceiling limitation based on the average first-day-of-the-month oil and gas prices of $82.58 per barrel and $2.94 per Mcf during the 12-month period ended March 31, 2012 and $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012. Therefore, impairment expense of $3,755,000 and $8,055,000 was recorded during the three and six months ended June 30, 2012, respectively.

Wells in Progress

Wells in progress at December 31, 2011, represent the costs associated with the drilling of two wells in the Riverbend area of Utah. Since the wells had not been completed as of December 31, 2011, they were classified as wells in progress and were withheld from the depletion calculation and the ceiling test. The costs for these wells were transferred into proved property during January 2012 when the wells reached total depth and were cased and became subject to depletion and the ceiling test calculation in subsequent periods.

Facilities and Equipment

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. 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 (expense) attributable to the outside working interest owners from the equipment rental was recorded as an adjustment to proved properties in the amount of $26,642 and $10,808 during the three and six months ended June 30, 2012, respectively, and $(15,310) and $(48,475) during the three and six months ended June 30, 2011, respectively.

Commodity 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. The Company’s 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 currently in earnings. See Note 5 — Derivatives, herein.

Warrants

On June 15, 2011, the Company issued warrants (“June Warrants”) to purchase 18,750,000 shares of common stock and on August 3, 2011, the Company issued warrants (“August Warrants” and collectively with the June Warrants, the “Warrants”) to purchase 11,500,000 shares of common stock. The Warrants are exercisable immediately for a term of sixty months, beginning at issuance, at an initial exercise price of $0.35 per share; however, the exercise price and number of shares of common stock issuable on exercise of the Warrants are subject to adjustment in the event of any stock split, reverse stock split, stock dividend, recapitalization, reorganization or similar transaction.  If the Company makes a distribution of its assets to all of its stockholders, holders of the Warrants may be entitled to participate. In the event of a Fundamental Transaction (as defined in the Warrants), at the election of a holder of a Warrant, the Company may be required to purchase the holder’s Warrant for cash in an amount equal to the value of the remaining unexercised portion of the Warrant.  As a result, the Warrants are accounted for as a liability on the Company’s consolidated balance sheets with changes in their fair value reported in earnings. Subject to certain exceptions, if the average of the daily volume weighted-average price of a share of common stock for some period of time equals or exceeds

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200% of the initial exercise price of the Warrants, and if at the time of such measurement the Equity Conditions (as defined in the Warrants) are satisfied, then the Company may, subject to certain conditions, require the holders of the Warrants to exercise.

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 and gathering system 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. 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 EndedJune 30,				Six Months EndedJune 30,
	2012		2011		2012			2011
Balance beginning of period	$	761,592	$	1,145,092	$	1,226,796		$	1,119,561
Liabilities incurred	—		—		—			—
Property dispositions	—		—		(493,178		)	—
Accretion expense	17,605		26,117		45,579			51,648
Balance end of period	$	779,197	$	1,171,209	$	779,197		$	1,171,209

See Note 3 – Asset Sales, herein, for discussion of property dispositions.

Revenue Recognition

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

The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves.

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 June 30, 2012, the off-balance sheet arrangements and transactions that the Company had entered into included operating lease agreements, gathering, compression, processing and

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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 is computed by dividing net income (loss) attributable to 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 (loss) per share of common stock includes both vested and unvested shares of restricted stock. Diluted net income (loss) per common share of stock is computed by dividing adjusted net income by the diluted weighted-average common shares outstanding.  Potentially dilutive securities for the diluted earnings per share calculation consist of (i) unvested shares of restricted common stock, (ii) in-the-money outstanding options and warrants to purchase shares of common stock, (iii) outstanding Series C Convertible Preferred Stock, par value $0.001 per share (“Preferred Stock”), which are convertible into shares of common stock and (iv) the Company’s outstanding 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”), which are convertible into shares of Preferred Stock and common stock.

The treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares that could have been repurchased by the Company with the proceeds from the exercise of the options (the repurchases of shares 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, warrants and shares into which the 2015 Notes and Preferred Stock are convertible.

Net income (loss) per share information is determined using the two-class method, which includes the weighted-average number of common shares outstanding during the period and other securities that participate in dividends (“participating security”). The Company considers the Preferred Stock to be a participating security because it includes rights to participate in dividends with the common stock. In applying the two-class method, earnings are allocated to both common stock shares and the Preferred Stock common stock equivalent shares based on their respective weighted-average shares outstanding for the period. Losses are not allocated to Preferred Stock shares. The table below sets forth the computations of basic and diluted net income (loss) per share for the three and six months ended June 30, 2012 and 2011.

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2012			2011		2012			2011
Basic Net (Loss) Income Per Common Share
Numerator:
Basic net (loss) income	$	(5,151,559	)	$	30,169	$	(10,209,703	)	$	(1,562,308	)
Net earnings allocated to participating securities	—			5,977		—			—
Net (loss) income attributed to common stockholders	$	(5,151,559	)	$	24,192	$	(10,209,703	)	$	(1,562,308	)
Denominator:
Weighted-average common shares outstanding	169,136,562			128,845,127		168,550,182			128,030,779
Basic net (loss) income per share	$	(0.03	)	$	0.00	$	(0.06	)	$	(0.01	)

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	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2012			2011		2012			2011
Diluted Net Income (Loss) Per Common Share
Numerator:
Basic net (loss) income	$	(5,151,559	)	$	30,169	$	(10,209,703	)	$	(1,562,308	)
Net earnings allocated to participating securities	—			5,977		—			—
Diluted net income (loss) attributed to common stockholders	$	(5,151,559	)	$	24,192	$	(10,209,703	)	$	(1,562,308	)
Denominator:
Basic weighted-average common shares outstanding	169,136,562			128,845,127		168,550,182			128,030,779
Effect of dilutive securities	—			—		—			—
Diluted weighted-average common shares outstanding	169,136,562			128,845,127		168,550,182			128,030,779
Diluted net income (loss) per share	$	(0.03	)	$	0.00	$	(0.06	)	$	(0.01	)

The following shares were excluded from the computation of diluted earnings (loss) per common share as they did not have a dilutive effect.

	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2012	2011	2012	2011
Shares related to:
2015 Notes	75,280,000	75,380,000	75,280,000	75,380,000
Preferred stock	30,344,173	—	30,344,173	31,833,340
Common stock options	9,898,214	10,579,293	9,898,214	10,579,293
Warrants	30,250,000	18,750,000	30,250,000	18,750,000
Unvested restricted stock	432,100	169,600	432,100	169,600

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, timing and costs associated with its retirement obligations, estimates of the fair value of derivative instruments, estimates used in stock-based compensation calculations and impairments to unproved property and to proved oil and gas properties.

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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

Effective January 1, 2012, the Company adopted Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards.” The adoption of ASU 2011-04 did not have a significant impact on the Company’s consolidated financial position or results of operations.

NOTE 3 – ASSET SALES

Uinta Basin Joint Venture

On March 22, 2012, the Company closed a previously announced transaction (the “Uinta Basin Transaction”) whereby, pursuant to the Purchase and Sale Agreement (the “Purchase Agreement”) dated February 23, 2012, between the Company’s wholly-owned subsidiary, Gasco Production Company, and Wapiti Oil & Gas II, L.L.C. (“Wapiti”), and a Closing Agreement (the “Closing Agreement”) dated March 22, 2012 relating to the Purchase Agreement, the Company (i) sold to Wapiti an undivided 50% of its interest in certain of its Uinta Basin producing oil and gas assets for $18.0 million in cash and $1.19 million in the form of a promissory note receivable from Wapiti, which was repaid in full during the second quarter of 2012, and (ii) transferred to Wapiti an undivided 50% of its interest in its Uinta Basin non-producing oil and gas assets in exchange for, among other agreements, Wapiti’s commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets.

As a part of the Uinta Basin Transaction, Gasco Production Company entered into a Development Agreement (the “Development Agreement”) with Wapiti, which includes terms and conditions of a drilling program agreed to by the parties.

Of Wapiti’s $30.0 million funding commitment, $15.0 million will be paid on behalf of the Company, and the Company has agreed to provide an additional $7.5 million of drilling and completion costs. Accordingly, the total program will be $37.5 million; provided that, if on February 23, 2013, the five-year New York Mercantile Exchange (“NYMEX”) natural gas strip pricing is at least $5.00/MMBtu, the drilling and completion program will be expanded by $6.25 million to $43.75 million with Wapiti paying for $5.0 million of the additional costs.

The drilling and completion program will continue until Wapiti’s funding commitment has been fully expended or for a shorter period, if the Operating Committee (as defined below) votes to cease the drilling program after Wapiti has expended $10.0 million on drilling and completion costs related to the program wells (the “Drilling Term”).

With respect to wells drilled pursuant to the drilling program, the net revenue interest attributable to such wells from the closing through the time when the cumulative proceeds received by Wapiti from such wells equals the amount of costs actually paid by Wapiti in respect of such wells and the drilling program (such time, “Payout”), will be allocated 32.5% to the Company and 67.5% to Wapiti. After Payout, the net revenue interest will be allocated in proportion to the actual net revenue interests of the parties in such wells.  With respect to each well drilled pursuant to the drilling program, (i) all drilling and completion costs will be borne (a) during the Drilling Term, 20% by the Company and 80% by Wapiti, (b) after the Drilling Term but before Payout,

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32.5% by the Company and 67.5% by Wapiti, and (c) after Payout, in proportion to the actual working interests of the parties in such wells, and (ii) all other working interest costs will be borne (x) before Payout, 32.5% by the Company and 67.5% by Wapiti, and (y) after Payout, in proportion to the actual working interests of the parties in such wells.

Subject to the terms of the Development Agreement, the Company will manage the operations contemplated by the drilling program.  Except for the subject assets that are already subject to joint operating agreements with third parties, the operation of (i) a portion of the subject assets will be subject to an agreed upon joint operating agreement (a “JOA”), which names Gasco Production Company as operator of record, and (ii) the remaining portion of the subject assets will be subject to an agreed upon JOA, which names Wapiti as operator of record.  Gasco Production Company and Wapiti also entered into a contract operating agreement naming Gasco Production Company as contract operator with respect to the portion of the subject assets for which Wapiti is named as operator of record.  The Company and Wapiti have formed an Operating Committee (the “Operating Committee”) to oversee generally the drilling program and operations in the project area and to approve certain matters specified in the Development Agreement. The Operating Committee consists of two members from each of us and Wapiti, with the members appointed by each party having an aggregate 50% vote.

The Development Agreement also contains transfer restrictions on each of our and Wapiti’s ability to transfer its respective interests in the subject assets. The Development Agreement also contains a customary area of mutual interest provision covering the Project Area. With certain limited exceptions, the Development Agreement will remain in effect during the Drilling Term; however, after the six-month anniversary of the end of the Drilling Term, the Development Agreement may be terminated by either us or Wapiti upon six months’ advance notice.

The foregoing description of the Uinta Basin Transaction, including the Purchase Agreement, the Closing Agreement and the Development Agreement, do not purport to be complete and are qualified in their entirety by reference to the full text of the Purchase Agreement, the Closing Agreement and the Development Agreement, which are attached as exhibits to our Current Report on Form 8-K filed on March 28, 2012.

The Company used approximately $10.5 million of the proceeds from the transaction to repay the borrowings under its prior revolving credit facility, and will use the remaining proceeds for capital expenditures, working capital, acquisitions of oil and natural gas properties and other general corporate purposes.

The sale of the proved property in the Uinta Basin Transaction was recorded by recognizing a gain of $2,567,574 rather than recording a credit to the full cost pool for the proceeds because this method would significantly alter the relationship between capitalized costs and the proved reserves attributable to the cost center.

No adjustments were made to the carrying value of the unproved properties upon the closing of the Uinta Basin Transaction. Rather as the wells are drilled, the cost basis of the unproved property associated with each well drilled will be reclassified from unproved property to the full cost pool to be depleted and included in the ceiling test. The cost basis will be determined based on a per acre valuation multiplied by the number of acres for each drilling location.

The following unaudited pro forma information is presented as if the Uinta Basin Transaction had an effective date of January 1, 2011, and is not necessarily indicative of either future results of operations or results that might have been achieved had the transaction been consummated as of January 1, 2011. The pro forma results for the three months ended June 30, 2012 were the same as the actual results.

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	Six Months Ended			Three Months Ended			Six Months Ended
	June 30, 2012			June 30, 2011			June 30, 2011
Revenue as reported	$	4,784,140		$	5,755,471		$	10,024,576
Less: revenue from the Uinta Basin Transaction	1,206,145			1,880,872			3,388,956
Pro forma revenue	$	3,577,995		$	3,874,599		$	6,635,620
Net (loss) income as reported	$	(10,209,703	)	$	30,169		$	(1,562,308	)
Less: operating loss resulting from the Uinta Basin Transaction	(2,390,235		)	(666,858		)	(1,174,662		)
Pro forma net (loss) income	(7,819,468		)	697,027			(387,646		)
Net (loss) income per share – basic and diluted as reported	$	(0.06	)	$	0.00		$	(0.01	)
Less net loss per share - from the Uinta Basin Transaction	(0.01		)	(0.01		)	(0.01		)
Pro forma net (loss) income per share – basic and diluted	$	(0.05	)	$	0.01		$	0.00

Prospect Fee

During January 2012, the Company entered into an arrangement with an exploration and production company which operates in California, pursuant to which the Company received a $750,000 prospect fee related to certain of its California acreage. The fee reimbursed 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. The proceeds were recorded as a credit to unproved properties during the six months ended June 30, 2012.

NOTE 4 - CONVERTIBLE SENIOR NOTES

As of June 30, 2012 and December 31, 2011, the Company had $45,168,000 aggregate principal amount of 2015 Notes outstanding.

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

The 2015 Notes bear interest at a rate of 5.50% per annum, and such interest is payable in cash semi-annually in arrears on April 5th and October 5th of each year.

The 2015 Notes are convertible, at the option of the holder, at any time prior to maturity, into shares of 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 $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 is $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 2015 Indenture, a holder may not

21

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 (as defined in the 2015 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 Issue 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 2015 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.

The 2015 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 guarantee 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 MKT 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.

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, 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,

22

Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of the Trustee.

The debt discount that was recognized in connection with the 2015 Notes is being accreted to interest expense under the effective interest method at a rate of 26.3%. The unamortized discount as of June 30, 2012 and December 31, 2011 was $20,684,318 and $22,574,687, respectively.

NOTE 5 — DERIVATIVES

From time to time, 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. As of December 31, 2011, natural gas derivative instruments consisted of one costless collar agreement for production from January 1, 2012 through December 31, 2012. During June 2012, the Company monetized this contract for net proceeds of $677,868. Prior to the monetization, the costless collar contained a fixed floor price (purchase put) and ceiling price (written call). The Company received the difference between the published index price and the floor price if the index price was below the floor price. The Company paid the difference between the ceiling price and the index price only if the index price was above the ceiling price. If the index price was between the ceiling and the floor prices, no amounts were paid or received.

On June 15, 2011, the Company issued the June Warrants to purchase 18,750,000 shares of common stock and on August 3, 2011, the Company issued the August Warrants to purchase 11,500,000 shares of common stock. The Warrants have an initial exercise price of $0.35 per share (subject to adjustment) and sixty-month term. The Warrants contain a contingent cash settlement provision at the option of the holder and accordingly, are classified as a derivative liability and are subject to the classification and measurement standards for derivative financial instruments.

The following table details the fair value of the derivatives recorded in the unaudited condensed consolidated balance sheets:

	Location on Consolidated	Fair Value at
	Balance Sheets	June 30, 2012		December 31, 2011
Natural gas derivative contracts	Current assets	$	—	$	865,358
Warrant derivatives	Noncurrent liabilities	2,837,500		4,235,000

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the three and six months ended June 30, 2012 and 2011.

	Three Months EndedJune 30,					Six Months EndedJune 30,
	2012			2011		2012			2011
Realized gains on commodity instruments	$	969,528		$	3,620	$	1,255,948		$	409,620
Change in fair value of commodity instruments	(1,062,071		)	142,538		(865,358		)	(199,509		)
Change in fair value of warrant derivatives	2,117,500			163,125		1,397,500			163,125
Total realized and unrealized gains recorded	$	2,024,957		$	309,283	$	1,788,090		$	373,236

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

NOTE 6 — GAS PROCESSING AGREEMENT

On September 21, 2011, the Company entered into a Gas Processing Agreement (the “Chipeta Processing Agreement”) with Chipeta Processing LLC (“Chipeta”) pursuant to which the Company dedicated certain of its natural gas production from its acreage in Utah to Chipeta for processing, and Chipeta agreed to process all natural gas production from such assets through facilities and related equipment that Chipeta owns or will construct on or before December 31, 2012.

The primary term of the Chipeta Processing Agreement is ten years, beginning after the in-service date of a 300 MMcf/d cryogenic processing facility to be built by Chipeta. The primary term will be extended for one year terms unless terminated by either party giving 180 days’ notice prior to the expiration of the then-current term.  If by December 31, 2012, among other conditions, (i) Chipeta has not completed its construction obligation and (ii) Questar Pipeline Company has not completed and received necessary regulatory approvals for the conversion of certain of its pipelines and facilities from a dry line to a wet line, the obligations of the Company and Chipeta under the Chipeta Processing Agreement shall be void.

Pursuant to the Chipeta Processing Agreement, the Company reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing.  The Company agreed to pay specified processing fees per MMBtu as well as a pro rata share of all applicable electric compression costs, subject to escalation on an annual basis.  The Company may also be required to make periodic deficiency payments to Chipeta for any shortfalls from the specified minimum volume commitments.

Historically, the Company’s natural gas production had been gathered and processed by Monarch Natural Gas, LLC, a Delaware limited liability company (“Monarch”) pursuant to the Gas Gathering and Processing Agreement effective March 1, 2010 between Monarch and the Company (the “Monarch Processing Agreement”).

On March 22, 2012, we entered into an Amended and Restated Gas Gathering and Processing Agreement (the “Amended and Restated Monarch Agreement”) with Monarch in which Monarch agreed to, among other things, (a) release and waive its rights to process the first 50,000 MMBtu/day of our gas delivered to Monarch’s gathering system pursuant to the Amended and Restated Monarch Agreement (the “Excluded Production”) and (b) retain all processing rights for all gas volumes produced from certain of our reserves in excess of the Excluded Production.  The Excluded Production may be reduced if we fail to meet certain drilling investment targets.  The term of the Amended and Restated Monarch Agreement extends through February 28, 2025, and, for wells that are already connected to Monarch’s gathering system on February 28, 2025, for so long as our gas can be produced in commercial quantities from such wells.

NOTE 7 — STOCK-BASED COMPENSATION

The Company has outstanding common stock options, stock appreciation rights (“SARs”) 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 expense recognized over the service period includes an estimate of the awards that will be forfeited.  Gasco assumes no forfeitures for employee awards based on the Company’s historical forfeiture experience.  The Company accounts for its SARs as liability based awards and accordingly the Company recognizes the fair value of the vested SARs each reporting period. The fair value of stock options and SARs is calculated using

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the Black-Scholes option-pricing model and the fair value of restricted stock is based on the fair value of the stock on the date of grant.

The Company accounts for stock compensation arrangements with non-employees using a fair value approach. Under this approach, the stock compensation related to 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 six months ended June 30, 2012 and 2011, the Company recognized stock-based compensation expense as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Employee compensation	$	77,020		$	7,866		$	140,980		$	176,898
Consultant compensation (reduction in compensation)	(375		)	(3,176		)	(4,130		)	(1,440		)
Total stock-based compensation	76,645			4,690			136,850			175,458
Less: consultant compensation expense (reduction in expense) capitalized as proved property	(211		)	(1,588		)	(11		)	(720		)
Stock-based compensation expense	$	76,856		$	6,278		$	136,861		$	176,178

Stock Options

The following table summarizes the stock option activity in the equity incentive plans from January 1, 2012 through June 30, 2012:

	Shares Underlying Stock Options	Weighted-Average Exercise Price
Outstanding at January 1, 2012	8,182,647	$	1.37
Granted	1,936,485	$	0.23
Exercised	—	—
Forfeited	6,254	$	0.25
Cancelled	214,664	$	0.93
Outstanding at June 30, 2012	9,898,214	$	1.10
Exercisable at June 30, 2012	7,243,567	$	1.52

During the first six months of 2012, the Company granted 1,936,485 options to purchase common stock with exercise prices ranging from $0.18 to $0.30 per share. These options have a two-year vesting period and expire five years from the grant date.

The following table summarizes information related to the outstanding and vested options as of June 30, 2012:

	Outstanding Options		Vested Options
Number of shares	9,898,214		7,243,567
Weighted-Average Remaining Contractual Life	2.9 years		2.4 years
Weighted-Average Exercise Price	$	1.10	$	1.52
Aggregate intrinsic value	$	6,000	$	1,000

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The aggregate intrinsic value in the table above represents the total pretax intrinsic value based on the fair value of the Company’s common stock of $0.18 as of June 30, 2012, which would have been received by the option holders had they exercised their options as of that date.

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

As of June 30, 2012, there is $352,964 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 2.9 years.

Restricted Stock

The following table summarizes the restricted stock activity from January 1, 2012 through June 30, 2012:

	Restricted Stock	Weighted-Average Grant Date Fair Value
Outstanding at January 1, 2012	184,500	$	0.36
Granted	250,000	$	0.18
Vested	2,400	$	0.22
Forfeited	—	—
Outstanding at June 30, 2012	432,100	$	0.25

As of June 30, 2012, there is $89,123 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 2.9 years.

SARs

Effective October 1, 2011, the Company’s non-employee directors agreed to reduce their monthly compensation and in exchange, on October 5, 2011, the Company granted SARs related to a total of 500,000 shares of the Company’s common stock to these directors. As of December 31, 2011, the SARs were recorded as a liability of $10,924. The SARs provide the right to receive a lump sum cash payment equal to the value of the product of (a) the excess of (i) the fair market value of one share of common stock on the date of exercise, over (ii) $0.25, which is an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (b) the number of shares as to which an award has been exercised (“Appreciation Amount”). The SARs vested on January 31, 2012 and were automatically exercised on February 1, 2012. The fair market value of the common stock on the date of exercise was below $0.25 per share and therefore the Appreciation Amount was zero and no cash payment was made.

Effective February 28, 2012, the Company granted another SARs award (“February SARs”) related to a total of 1,000,000 shares of our common stock to these directors.  As of June 30, 2012, the SARs were recorded as a liability of $6,816.The February SARs provide the right to receive a lump sum cash payment equal to the value of the product of (a) the excess of (i) (A) the fair market value of one share of common stock on the date of exercise or (B) $2.00, whichever is less, over (ii) $0.30, which is an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (b) the number of shares as to which an award has been exercised. The February SARs vest on January 31, 2013 and will be automatically exercised on February 1, 2013.

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NOTE 8 — CREDIT FACILITY

The Company’s prior $250 million revolving credit facility (“Prior Credit Facility”) matured on June 29, 2012 and was repaid in full.

The Company is discussing new borrowing arrangements with potential lenders and while the Company currently believes that it will be able to find a new lender, there can be no assurance that it will be able to obtain adequate financing on acceptable terms or at all. For example, the Company’s recent results of operations and volatility in oil and gas prices as well as in the domestic credit and capital markets generally may negatively affect the availability and terms of financing. If the Company is able to secure new borrowing arrangement, it expects that such arrangement will include less favorable terms, including with respect to the cost of borrowing and financial covenants, than those of the Credit Facility.  If the Company is unable to secure a new borrowing arrangement, it will lose a primary source of liquidity and will be required to fund its business and operations going forward with cash flow from operations and cash on hand.  There is no guarantee that the Company will be able to do so, in which case it may have to significantly reduce its spending and may be unable to execute its existing short-term and long-term business plan, and its liquidity and results of operations may be materially adversely affected.

Interest on borrowings under the Prior Credit Facility accrued at variable interest rates at either a Eurodollar rate or an alternate base rate (“ABR”). The Eurodollar rate was calculated as LIBOR plus an applicable margin that, as amended, varied from 2.75% (for periods in which the Company had utilized less than 50% of the borrowing base) to 3.75% (for periods in which the Company had utilized at least 90% of the borrowing base). The ABR, as amended, was 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 had utilized less than 50% of the borrowing base) to 2.75% (for periods in which the Company had utilized at least 90% of the borrowing base).

NOTE 9 — 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 Company’s policy is to recognize transfers in and/or out

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of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below in all periods presented.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and December 31, 2011 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
June 30, 2012
Liabilities:
Warrant derivatives	$	—	$	—	$	2,837,500	$	2,837,500
December 31, 2011
Assets:
Commodity derivatives	$	—	$	856,358	$	—	$	856,358
Liabilities:
Warrant derivatives	$	—	$	—	$	4,235,000	$	4,235,000

As of June 30, 2012, the Company’s warrant derivative financial instrument is comprised of the Warrants issued by the Company to purchase 30,250,000 shares of common stock. The Warrants are valued using a binomial lattice-based valuation model and are classified as Level 3 in the fair value hierarchy. The lattice-based valuation technique is utilized because it embodies all of the requisite assumptions (including the underlying price, exercise price, term, volatility, and risk-free interest-rate) that are necessary to measure the fair value of these instruments. The valuation policies are determined by the Chief Accounting Officer and are approved by the Chief Executive Officer. Fair value measurements are discussed with the Company’s audit committee, as deemed appropriate. Each quarter, the Chief Accounting Officer and the Chief Executive Officer update the inputs used in the fair value calculations and internally review the changes from period to period for reasonableness. The Company uses data from its peers as well as from external sources in the determination of the volatility and risk free interest rates used in the fair value calculations. A sensitivity analysis is performed as well to determine the impact of the inputs on the ending fair value estimate. Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument due to both internal and external market factors. In addition, option-based techniques are highly sensitive to volatility assumptions, particularly since the trading price of the Company’s common stock has a high-historical volatility. With all other factors remaining constant as of June 30, 2012:

(i)the warrant derivative liability would decrease by approximately $1.9 million for a $0.10 decrease in the trading price of our common stock and would increase by approximately $2.3 million for a $0.10 increase in the trading price of our common stock; and

(ii)the warrant derivative liability would increase by approximately $490,000 for a 10% increase in the volatility rate and would decrease by approximately $417,000 for a decrease in the volatility rate of 10%.

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A summary of the Warrants issued by the Company is as follows:

	Number of Warrants	Exercise Price		Weighted Average Remaining Contractual Life
Warrants outstanding as of 12/31/11	30,250,000	$	0.35	54.1 months
Warrants issued	—			—
Warrants outstanding as of 6/30/12	30,250,000	$	0.35	48.0 months

The significant assumptions used in the valuation of the warrant derivative liability as of June 30, 2012 are as follows:

Exercise price	$0.35 per share
Volatility	95.5%
Term of Warrants	60 months
Risk-free interest rate	1% - 2%

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:

	Warrant Derivative
Balance as of January 1, 2012	$	(4,235,000	)
Total gains (realized or unrealized):
Included in earnings	1,397,500
Included in other comprehensive income	—
Issuances	—
Settlements	—
Transfers in and out of Level 3	—
Balance as of June 30, 2012	$	(2,837,500	)
Change in unrealized gains included in earnings relating to instruments still held as of June 30, 2012	$	1,397,500

The carrying amounts of cash and cash equivalents, accounts receivable, note receivable, accounts payable and accrued liabilities approximate fair values because of the short-term maturities and or liquid nature of these assets and liabilities. The estimated fair value of the 2015 Notes of $28,590,552 and $31,443,000 as of June 30, 2012 and December 31, 2011, respectively, was determined using a discounted cash flow and option pricing model.

NOTE 10 - STATEMENTS OF CASH FLOWS

During the six months ended June 30, 2012, the Company’s non-cash investing and financing activities consisted of the following transactions:

·Conversion of 8,935 shares of Preferred Stock into 1,489,166 shares of common stock.

·Settlement of a $121,000 liability with a prepaid deposit.

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·Additions to oil and gas properties included in accounts payable of $116,000.

During the six months ended June 30, 2011, the Company’s non-cash investing and financing activities consisted of the following transactions:

·      Conversion of 34,600 shares of Preferred Stock into 5,766,667 shares of common stock.

·Additions to oil and gas properties included in accounts payable of $654,011.

Cash paid for interest during the six months ended June 30, 2012 and 2011 was $1,353,761 and $1,823,015, respectively. There was no cash paid for income taxes during the six months ended June 30, 2012 and 2011.

NOTE 11 — LEGAL PROCEEDINGS

The Company is party to various legal proceedings arising out of the normal course of business.  The most significant legal proceeding to which the Company is subject is summarized below.  The ultimate outcome of the Clean Water Act Compliance Order matter 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 the outcome of this proceeding to have a material adverse affect on its financial position, results of operations or cash flows.

Clean Water Act Compliance Order Matter

On October 3, 2011, the Company received a compliance order from the United States Environmental Protection Agency (“EPA”) Region 8 under the authority of the federal Clean Water Act.  The compliance order alleges that the Company violated the Clean Water Act by discharging fill material into wetlands adjacent to the Green River in Utah without authorization on two occasions: once when it constructed an access road to a future well location in either 2004 or 2005 and once when it constructed an access road and a well pad in 2007 or 2008.  The compliance order directs the Company to remove all dredged or fill material alleged to have been placed in the wetlands and to restore the wetlands to their pre-impact condition and grade, which would require that the Company plug and abandon the well alleged to have been installed in a wetlands area.  The compliance order does not seek any civil penalties for the alleged violations.  The Company disagrees with some of the factual contentions in the compliance order, and it has had a number of discussions with the EPA concerning the order.  However, it has been unable to negotiate a successful resolution of the alleged violations with EPA, and as a result, it filed a lawsuit in federal district court in the District of Colorado on June 25, 2012.  The lawsuit seeks judicial review of the compliance order, specifically review of EPA’s contention that the affected areas are wetlands, or if they are wetlands, whether they are wetlands that are subject to federal regulatory jurisdiction under the Clean Water Act.  The Company is not able to predict the outcome of this matter at this time.

NOTE 12 — GUARANTOR SUBSIDIARIES

On August 31, 2011, the Company filed a Form S-3 shelf registration statement with the SEC, which was declared effective on September 20, 2011. Under this registration statement, the Company may from time to time offer and sell securities including common stock, preferred stock, depositary shares, warrants and 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”). The stand-alone parent entity, Gasco Energy, Inc., has insignificant independent assets and no operations. Therefore, supplemental financial information on a condensed consolidating basis of the Guarantor

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Subsidiaries is not required. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the Guarantor Subsidiaries, except those imposed by applicable law.

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

Overview

We are 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

Environmental Impact Statement

In June 2012, the Bureau of Land Management (“BLM”) signed the Record of Decision on the Environmental Impact Statement that authorizes the development of our Uinta Basin field in Duchesne and Uintah Counties, Utah. This field includes our core Riverbend Project.

Our project will tap an existing gas field that already has 135 producing wells and extensive infrastructure, pipelines and roads. We will also continue to explore for oil and gas in other parts of the project area. The project area is located primarily on 177,644 acres of BLM-administered lands.

Prior Credit Facility

Our prior revolving credit facility matured on June 29, 2012 and we repaid all of the borrowings outstanding thereunder at such time. At the same time, we monetized our remaining commodity derivatives for $677,868.

Green River Oil Wells

In December 2011, we began drilling two wells to the Green River Formation, both in which we currently own a 50% working interest. These wells were successfully completed during January 2012.  The wells are on artificial lift and continue to produce oil as expected.  We expect to drill additional Green River oil wells during the fourth quarter of 2012.  Gasco recently installed improved lifting equipment on each of the Green River wells that were drilled during the first half of 2012.

Drilling Plans

Our Uinta Basin drilling and completions program contemplates a capital expenditure budget of approximately $3.6 million for the drilling and completion of six gross (1.0 net) new Green River Formation oil wells and six gross (2.0 net) new-drill natural gas wells. However, due to the low gas price environment and permitting delays, we do not expect to drill any natural gas wells in Utah this year and expect to spend only $0.9 million of our 2012 budget for the drilling of the Green River Formation oil wells. All of the Green River Formation oil wells within the drilling program are in the permitting process.  While actual timing of the drilling of the wells is dependent upon receipt of the approved permits, we believe we will have the necessary inventory of permits to begin drilling during the fourth quarter of 2012.

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California Projects

Willow Springs

The exploration well drilled in this area tested non-commercial rates of oil in the Phacoides Formation and our partner moved up the well bore to test additional potential pay horizons.  Two tests were made of the Monterey Shale in an off-structure position.  While both zones indicated decent quality reservoir characteristics, both zones encountered non-commercial rates of hydrocarbons.  Based upon all of the testing results, our partner made the decision to plug and abandon the well.  While the Willow Springs well did not find commercial hydrocarbons, it did confirm our structural geologic model by finding oil within the Phacoides Formation and confirmed the existence of the Monterey Shale reservoir.

Our partner has the option of spudding a second well within the Willow Springs acreage before March 2013.

Antelope Valley Trend

In order to complete the processing of the large Antelope Valley 3D seismic survey, our partner has been granted a one-year extension in the spudding of the first test earning well at our Antelope Valley Trend of prospects.  The first test well will spud before July 2013.  In exchange for the drilling extension, our partner has also committed to spudding a well on the Southwest Cymric prospect prior to December 31, 2013.

Northwest McKittrick

Permit issuance continues to be delayed within the California Fish and Wildlife Department.  Our partner is waiting on final approval of a “takings” value for endangered species mitigation.  Upon approval, payment can be made to the Kern Water Bank and a permit to drill will be issued.  We believe that the first earning well will be drilled prior to December 31, 2012.

Oil and Gas Production Summary

The following table presents our production and price information during the three and six months ended June 30, 2012 and 2011. The Mcfe calculations assume a conversion of six Mcf for each Bbl of oil.

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Natural gas production (Mcf)	562,942		1,030,767		1,394,709		1,943,842
Average sales price per Mcf	$	2.26	$	4.47	$	2.57	$	4.28
Oil production (Bbl)	4,209		12,904		14,094		20,478
Average sales price per Bbl	$	78.57	$	88.80	$	85.36	$	83.60
Production (Mcfe)	588,196		1,108,191		1,479,273		2,066,710

Our equivalent oil and gas production decreased by 50% and 28% during the three and six months ended June 30, 2012 as compared to the three and six months ended June 30, 2011, respectively. The decrease in production reflects the conveyance of a 50% interest in certain of our Uinta Basin properties to our joint venture partner as part of the Uinta Basin Transaction which closed on March 22, 2012.

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Liquidity and Capital Resources

General

We have historically generated cash from operations from the sale of oil and natural gas with the exception of the first six months of 2012, and have relied in the past primarily on the issuance of equity, borrowings under our prior revolving credit facility and farm-out and other similar types of transactions to fund working capital and the acquisition of our prospects and leases.  For the six months ended June 30, 2012, we incurred a net loss of $10,209,703 and had negative cash flow from operations of $3,467,152.  As of June 30, 2012, we had an accumulated deficit of $232,785,468.

On March 22, 2012, we closed the Uinta Basin Transaction, pursuant to which we (i) sold to Wapiti an undivided 50% interest in certain of our Uinta Basin producing oil and gas assets for $18.0 million in cash and $1.19 million in the form of a promissory note receivable from Wapiti (which was paid in full during the second quarter of 2012) and (ii) transferred to Wapiti an undivided 50% of our interest in our Uinta Basin non-producing oil and gas assets in exchange for, among other agreements, Wapiti’s commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets.

Of Wapiti’s $30.0 million funding commitment, $15.0 million will be paid on our behalf, and we have agreed to provide an additional $7.5 million of drilling and completion costs. Accordingly, the total program will be $37.5 million; provided that, if on February 23, 2013, the five-year New York Mercantile Exchange (“NYMEX”) natural gas strip pricing is at least $5.00/MMBtu, the drilling and completion program will be expanded by $6.25 million to $43.75 million with Wapiti paying for $5.0 million and us paying for $1.25 million of the additional costs.

We used approximately $10.5 million of the proceeds from the Uinta Basin Transaction to repay outstanding borrowings under our prior revolving credit facility. We expected to use the remaining proceeds for our capital expenditures consisting of approximately $5.0 million for our drilling program which includes the drilling of 13 wells, our continued up-hole recompletion program targeting natural gas and for additional investment in existing and new California oil and gas prospects in the San Joaquin Basin as well as for working capital, acquisitions of oil and natural gas properties and other general corporate purposes. However, due to the low gas price environment and permitting delays, we do not expect to drill any natural gas wells in Utah this year and expect to spend only $3.9 million of our 2012 budget.

Our prior revolving credit facility matured in June 2012, at which time we repaid all of the outstanding borrowings thereunder. We are discussing new borrowing arrangements with potential lenders and while we currently believe that we will be able to find a new lender, there can be no assurance that we will be able to obtain adequate financing on acceptable terms or at all.  For example, our recent results of operations and volatility in oil and gas prices, as well as in the domestic credit and capital markets generally, may negatively affect the availability and terms of financing.  If we were to secure a new borrowing arrangement, we expect that such arrangement will include less favorable terms, including with respect to the cost of borrowing and financial covenants, than those of our prior revolving credit facility.  If we are unable to secure a new borrowing arrangement, we will lose a primary source of liquidity and be required to fund our business and operations going forward without outside capital.

We believe that cash on hand (including proceeds from the Uinta Basin Transaction) as well as future cash flow from operations will be sufficient to fund our anticipated cash requirements for working capital purposes and normal capital expenditures through the second quarter of 2013.  However, there can be no assurance regarding these matters given that we will require significant additional capital to fund our future drilling

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activities and to meet our future debt maturities.  Failure to generate operating cash flow or to obtain additional financing for the development of our properties could result in substantial dilution of our property interests or delay or cause indefinite postponement of further exploration and development of our prospects with the possible loss of our properties.  This could cause us to alter our business plans, including further reducing our exploration and development plans.

In particular, we face uncertainties relating to our ability to generate sufficient cash flows from operations to fund the level of capital expenditures required for oil and gas exploration and production activities and for working capital purposes. We intend to fund our anticipated cash requirements through the second quarter of 2013, including our 2012 capital budget of which we expect to spend $3.9 million, primarily through cash on hand and cash flows from operations, although we cannot assure you that cash on hand and cash flows from operations will be sufficient to fund such requirements.

Our inability to secure replacement financing for the prior revolving credit facility or otherwise access future borrowings will significantly limit our ability to fund or increase our operating budget and to execute our growth plans, and our liquidity and results of operations may be materially adversely affected.  If we need additional liquidity for future activities, we may be required to consider several options for raising such funds, such as selling additional securities, selling assets or executing farm-out 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.

Sources and Uses of Funds

The following table summarizes our sources and uses of cash for each of the six months ended June 30, 2012 and 2011.

	For the Six Months EndedJune 30,
	2012			2011
Net cash (used in) provided by operations	$	(3,467,152	)	$	1,923,715
Net cash provided by (used in) investing activities	15,181,883			(4,850,540		)
Net cash (used in) provided by financing activities	(8,544,969		)	7,057,654
Net increase in cash	3,169,762			4,130,829

Cash provided by operations decreased by $5,390,867 from June 30, 2011 to June 30, 2012.  The decrease in cash provided by operations was primarily due to a $5,240,436 decrease in oil and gas revenue caused by a 28% decrease in equivalent production and a 40% decrease in gas prices partially offset by a 2% increase in the oil prices received during the first six months of 2012, and a $320,673 increase in workover expenses during the first six months of 2012.

Our investing activities during the first six months of 2012 and 2011 included our development and exploration activities, fixed asset additions and the change in advances from joint interest owners. The investing activity during the first six months of 2012 also included the sales proceeds from the Uinta Basin Transaction (see Note 3 — Asset Sales of the accompanying unaudited condensed consolidated financial statements).

The financing activity during the first six months of 2012 included $2.0 million in borrowings and $10,544,969 of repayments under our prior revolving credit facility. The financing activity during the first six

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months of 2011 included $6.0 million in proceeds from the issuance of common stock and warrants, $2.0 million in borrowings under our prior revolving credit facility and the payment of $942,346 in costs associated with the issuance of common stock and warrants and our 5.5% Convertible Senior Notes due 2015 (“2015 Notes”).

2012 Capital Budget

Our capital expenditure budget for our 2012 oil and natural gas activities has been set at $5.0 million. The 2012 capital expenditure budget was allocated among our drilling program which includes the drilling of 13 Green River Formation oil wells and new-drill natural gas wells, our continued up-hole recompletion program targeting natural gas and our additional investment in existing and new California oil and natural gas prospects in the San Joaquin Basin. However, due to the low gas price environment and permitting delays, we do not expect to drill any natural gas wells in Utah this year and expect to spend only $0.9 million of our 2012 budget for the drilling of the Green River Formation oil wells. Our 2012 capital expenditure program will be funded primarily from cash received from the closing of the Uinta Basin Transaction and cash on hand. See “Liquidity and Capital Resources” above.

Risk Management

We have historically used 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.  However, these derivative instruments could limit the prices we could actually realize and therefore may reduce oil and natural gas revenues in the future. During June 2012, we monetized our outstanding commodity derivatives but we intend enter into future derivatives when it becomes beneficial for us to do so. See Part I, Item 3 “Quantitative and Qualitative Disclosures About Market Risk” for further discussion on our risk management policies.

Results of Operations

The Second Quarter of 2012 Compared to the Second Quarter of 2011

Oil and Gas Revenue and Production

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

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	Three Months Ended June 30,				Year over Year Change
	2012		2011		Amount			Percentage
Natural gas production (Mcf)	562,942		1,030,767		(467,825		)	(45	)%
Average sales price per Mcf	$	2.26	$	4.47	$	(2.21	)	(49	)%
Natural gas revenue	$	1,273,178	$	4,609,574	$	(3,336,396	)	(72	)%
Oil production (Bbl)	4,209		12,904		(8,695		)	(67	)%
Average sales price per Bbl	$	78.57	$	88.80	$	(10.23	)	(11	)%
Oil revenue	$	330,695	$	1,145,897	$	815,202		71	%
Total oil and gas revenue	$	1,603,873	$	5,755,471	$	(4,151,598	)	(72	)%
Equivalent production (Mcfe)	588,196		1,108,191		(519,995		)	(47	)%

The decrease in oil and gas revenue of $4,151,598 during the second quarter of 2012 compared with the second quarter of 2011 was comprised of a 47% decrease in equivalent oil and gas production and a 49% decrease in gas prices from $4.47 in 2011 to $2.26 in 2012 and an 11% decrease in average oil prices. The decrease in equivalent oil and gas production was primarily due to the Uinta Basin Transaction and normal production declines. The $4,151,598 decrease in oil and gas revenue during the first quarter of 2012 represents a decrease of $2,864,020 related to the equivalent production decrease and a decrease of $1,287,578 related to the decrease in gas prices partially offset by the increase in oil prices.

Lease Operating Expenses

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

	For the Three Months Ended June 30,				Year over Year Change
	2012		2011		Amount			Percentage
Direct operating expenses and overhead	$	854,740	$	1,203,274	$	(348,534	)	29	%
Workover expense	236,949		295,766		(58,817		)	20	%
Total operating expenses	$	1,091,689	$	1,499,040	$	(407,351	)	27	%
Operating expenses per Mcfe	$	1.86	$	1.35	$	0.51		59	%
Production and property taxes	$	60,773	$	208,694	$	(147,921	)	(71	)%
Production and property taxes per Mcfe	$	0.10	$	0.19	$	(0.09	)	(47	)%
Total lease operating expense	$	1,152,462	$	1,707,734	$	(555,272	)	(33	)%
Total lease operating expense per Mcfe	$	1.96	$	1.54	$	0.42		27	%

Lease operating expense decreased $555,272 during the second quarter of 2012 compared with the second quarter of 2011. The decrease is primarily due to the conveyance of a 50% interest in certain of our properties in the Uinta Basin Transaction which closed during March 2012.

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Transportation and Processing

Transportation and processing costs of $518,394 ($0.88 per Mcfe) and $901,384 ($0.81 per Mcfe) during the three months ended June 30, 2012 and 2011, respectively, represent the costs we incurred to transport and process the gas production from our wells. The decrease of $382,990 in these expenses during the second quarter of 2012 reflects lower transportation and processing costs related to the 45% decrease in gas production due to the Uinta Basin Transaction and normal production declines.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation,  amortization and accretion expense during the second quarters of 2012 and 2011 is comprised of depletion expense related to our oil and gas properties, depreciation expense of furniture, fixtures and equipment and accretion expense related to our asset retirement obligation. This expense decreased $337,505 during the second quarter of 2012 compared to the second quarter of 2011 primarily due to our production decline, combined with the decrease in the full cost pool resulting from property impairment during the first quarter of 2012, as discussed below, and the Uinta Basin Transaction during March 2012.

Impairment

As of June 30, 2012, our full cost pool exceeded the ceiling limitation based on the average, first-day-of-the-month oil and gas prices of $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012. Therefore, impairment expense of $3,755,000 was recorded during the quarter ended June 30, 2012.

General and Administrative Expense

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

	For the Three Months Ended June 30,						Year over Year Change
	2012			2011			Amount			Percentage
Total general and administrative costs	$	1,395,655		$	1,370,597		$	25,058		2	%
General and administrative costs allocated to drilling, completion and operating activities	(359,891		)	(431,533		)	(71,642		)	(17	)%
General and administrative expense	$	1,035,764		$	939,064		$	96,700		10	%
General and administrative expenses per Mcfe	$	1.76		$	0.85		$	0.91		107	%
Total stock-based compensation costs	$	76,645		$	4,690		$	71,955		153	%
Stock-based compensation costs capitalized	211			1,588			(1,377		)	(87	)%
Stock-based compensation	$	76,856		$	6,278		$	70,578		112	%
Stock-based compensation per Mcfe	$	0.13		$	0.00		$	(0.13	)
Total general and administrative expense including stock-based compensation	$	1,112,620		$	945,342		$	167,278		18	%
Total general and administrative expense per Mcfe	$	1.89		$	0.85		$	1.04		122	%

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General and administrative expense increased by $167,278 during the second quarter of 2012 as compared with the second quarter of 2011 primarily due to the legal and consulting expenses associated with the Uinta Basin Transaction combined with a $70,578 increase in stock-based compensation as the result of the issuance of certain stock options and restricted stock during June 2012.

Interest Expense

Interest expense increased $108,070 during the second quarter of 2012 as compared with the second quarter of 2011, primarily due to the increase in discount amortization associated with our 2015 Notes.

Derivative (Losses) Gains

Derivative (losses) gains during the quarters ended June 30, 2012 and 2011 are comprised of realized and unrealized gains and losses on our commodity derivative instruments and unrealized gains on our warrant derivative liability. The unrealized derivative (losses) gains represent the changes in the fair value of our derivative assets and liabilities and the realized derivative gains represent the net settlements and monetization from our commodity derivative counterparty based on each month’s settlement during the quarter.

Amortization of Deferred Income from Sale of Assets

The amortization of the deferred income from the sale of assets during the quarters ended June 30, 2012 and 2011 represents the amortization of the excess of proceeds received over the carrying value of our gathering system and evaporative facilities sold during March 2010.

The First Six Months of 2012 Compared to the First Six Months of 2011

Oil and Gas Revenue and Production

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

	Six Months Ended June 30,				Year over Year Change
	2012		2011		Amount			Percentage
Natural gas production (Mcf)	1,394,709		1,943,842		(549,133		)	(28	)%
Average sales price per Mcf	$	2.57	$	4.28	$	(1.71	)	(40	)%
Natural gas revenue	$	3,581,042	$	8,312,605	$	(4,731,563	)	(57	)%
Oil production (Bbl)	14,094		20,478		(6,384		)	(31	)%
Average sales price per Bbl	$	85.36	$	83.60	$	1.76		2	%
Oil revenue	$	1,203,098	$	1,771,971	$	(565,876	)	(32	)%
Total oil and gas revenue	$	4,784,140	$	10,024,576	$	(5,240,436	)	(52	)%
Equivalent production (Mcfe)	1,479,273		2,066,710		(587,437		)	(28	)%

The decrease in oil and gas revenue of $5,240,436 during the first six months of 2012 compared with the first six months of 2011 was attributable to a 28% decrease in equivalent oil and gas production and a 40% decrease in gas prices from $4.28 in 2011 to $2.57 in 2012 partially offset by a 2% increase in average oil prices. The decrease in equivalent oil and gas production was primarily due to the Uinta Basin Transaction and normal

39

production declines. The $5,240,436 decrease in oil and gas revenue during the first six months of 2012 represents a decrease of $2,882,141 related to the equivalent production decrease and a decrease of $2,358,295 related to the decrease in gas prices partially offset by an increase in oil prices.

Lease Operating Expenses

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

	For the Six Months Ended June 30,				Year over Year Change
	2012		2011		Amount			Percentage
Direct operating expenses and overhead	$	1,768,287	$	2,015,420	$	(247,133	)	(12	)%
Workover expense	941,588		620,915		320,673			52	%
Total operating expenses	$	2,709,875	$	2,636,335	$	73,540		3	%
Operating expenses per Mcfe	$	1.83	$	1.28	$	0.55		43	%
Production and property taxes	$	130,588	$	412,831	$	(282,243	)	(68	)%
Production and property taxes per Mcfe	$	0.09	$	0.20	$	(0.11	)	(55	)%
Total lease operating expense	$	2,840,463	$	3,049,166	$	(208,703	)	(7	)%
Total lease operating expense per Mcfe	$	1.92	$	1.48	$	0.44		30	%

Lease operating expense decreased $208,703 during the first six months of 2012 compared with the first six months of 2011. The decrease is primarily due to the conveyance of a 50% interest in certain of our properties in the Uinta Basin Transaction which closed during March 2012 partially offset by a $320,673 increase in workover expense related to the removal of critical velocity reduction strings, modification of cap strings and scale treatment and removal from existing wells during the first six months of 2012.

Transportation and Processing

Transportation and processing costs were $1,175,366 ($0.79 per Mcfe) and $1,703,099 ($0.82 per Mcfe) for the six months ended June 30, 2012 and 2011, respectively. The decrease of $527,733 in these expenses during the second quarter of 2012 reflects lower transportation and processing costs related to the 28% decrease in gas production due to the Uinta Basin Transaction and normal production declines.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation and amortization expense during the first six months of 2012 and 2011 decreased $337,302 primarily due to the production decline combined with the decrease in the full cost pool resulting from the property impairments during the first and second quarters of 2012 discussed below and the Uinta Basin Transaction during March 2012.

Impairment

As of June 30, 2012 and March 31, 2012 our full cost pool exceeded the ceiling limitation based on the average, first-day-of-the-month oil and gas prices of $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012 and $82.58 per barrel and $2.94 per Mcf during the 12-month period ended March

40

31, 2012. Therefore, impairment expense of $8,055,000 was recorded during the six months ended June 30, 2012.

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 Six Months Ended June 30,						Quarter over Quarter Change
	2012			2011			Amount			Percentage
Total general and administrative costs	$	2,740,632		$	2,751,857		$	(11,225	)	(1	)%
General and administrative costs allocated to drilling, completion and operating activities	(359,891		)	(856,530		)	496,639			58	%
General and administrative expense	$	2,380,741		$	1,895,327		$	485,414		26	%
General and administrative expenses per Mcfe	$	1.61		$	0.92		$	0.69		75	%
Total stock-based compensation costs	$	136,850		$	175,458		$	(36,608	)	(21	)%
Stock-based compensation costs capitalized	11			720			(709		)	(98	)%
Stock-based compensation	$	136,861		$	176,178		$	(39,317	)	(22	)%
Stock-based compensation per Mcfe	$	0.09		$	0.08		$	0.01		12	%
Total general and administrative expense including stock-based compensation	$	2,517,602		$	2,071,505		$	446,097		21	%
Total general and administrative expense per Mcfe	$	1.70		$	1.00		$	0.70		70	%

General and administrative expense including stock-based compensation increased by $446,097 during the first six months of 2012 as compared with the first six months of 2011. Total general and administrative costs remained fairly consistent year over year however, the allocation of such costs to operating activities decreased by $496,639 during 2012 as compared to the same period of 2011 due to reduced operational activity during the first six months of 2012.

Interest Expense

Interest expense decreased $27,056 during the first six months of 2012 as compared with the same period in 2011, primarily due to the decrease in borrowings under the Prior Credit Facility during 2012.

Gain on Sale of Assets

The gain on sale of assets during the first six months of 2012 represents the gain from the Uinta Basin Transaction.

Derivative Gains

Derivative gains during the first six months of 2012 increased $1,414,854 primarily due to the increase in the unrealized gain on the warrant derivative resulting from the decrease in the trading price of our common stock and the monetization of our remaining commodity derivatives.

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Interest Income

Interest income increased $10,916 during the first six months of 2012 as compared with the first six months of 2011 primarily due to the interest on the promissory note receivable that we received as part the Uinta Basin Transaction. The promissory note was repaid in full during May 2012.

Off-Balance Sheet Arrangements

From time to time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of June 30, 2012, the off-balance sheet arrangements and transactions that we have entered into include 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 our liquidity or availability of, or requirements for, capital resources.

Recently Issued Accounting Pronouncements

Effective January 1, 2011, we adopted Fair Accounting Standards Board guidance that requires enhanced disclosure detail in the Level 3 reconciliation for fair value measurements. The adoption had no impact on our consolidated financial position, results of operations or cash flows. Refer to Note 9 — Fair Value Measurement of the accompanying unaudited condensed consolidated financial statements for further details regarding our assets and liabilities measured at fair value.

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ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2011 10-K.

We are exposed to a variety of market risks, including commodity price risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we were a party at June 30, 2012, and from which we may incur future gains or losses from changes in commodity prices or market interest rates. We do not enter into derivative or other financial instruments for speculative or trading purposes.

Hypothetical changes in the price of our common stock and volatility rates chosen for the following estimated sensitivity analyses are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in in the price of our common stock and volatility rates, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Further, our cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by placing these funds with major financial institutions with high credit ratings.   Our receivables are comprised of oil and gas revenue receivables and joint interest billings receivable, which amounts are due from a limited number of entities. Therefore, collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized; however, to date, we have had minimal bad debts.

Warrant Derivative Risk

On June 15, 2011, we issued warrants to purchase 18,750,000 shares of common stock and on August 3, 2011, we issued warrants to purchase 11,500,000 shares of common stock (collectively the “Warrants”).  The Warrants have an  initial exercise price of $0.35 per share (subject to adjustment) with a sixty-month term, as further described in Note 2 — Significant Accounting Policies of the accompanying unaudited condensed consolidated financial statements.  The Warrants contain a contingent cash settlement provision at the option of the holder and accordingly, are classified as a derivative liability and are subject to the classification and measurement standards for derivative financial instruments. Estimating fair values of derivative financial instruments requires the development of significant and subjective estimates that may, and are likely to, change over the duration of the instrument with related changes in internal and external market factors. In addition, option-based techniques are highly volatile and sensitive to changes in the trading price of our common stock, which has a high-historical volatility. With all other factors remaining constant as of June 30, 2012:

(i)the warrant derivative liability would decrease by approximately $1.9 million for a $0.10 decrease in the trading price of our common stock and would increase by approximately $2.3 million for a $0.10 increase in the trading price of our common stock; and

(ii)the warrant derivative liability would increase by approximately $490,000 for a 10% increase in the volatility rate and would decrease by approximately $417,000 for a 10% decrease in the volatility rate.

Commodity Price Risk

During June 2012, we monetized our remaining commodity derivative for $677,868 and do not have any commodity derivative contracts outstanding as of June 30, 2012.

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ITEM 4 - CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (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 ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act 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, including our principal executive and principal financial officers or persons performing similar functions, as appropriate to allow such persons to make timely decisions regarding required disclosures.

Based upon the results of our evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2012, at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f)  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.

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 consolidated financial statements included herein.  We do not expect the outcome of the proceedings discussed therein to have a material adverse affect on our financial position, results of operations or cash flows.

Item 1A - Risk Factors

Except as set forth below,there have been no material changes in our risk factors as previously disclosed in Part 1, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2011. In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in our 2011 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this Quarterly Report on Form 10-Q and in our 2011 Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

We currently do not have access to a credit facility. If we are unable to secure adequate financing to replace the prior credit facility, our liquidity and results of operations may be materially adversely affected.

Our prior credit facility matured in June 2012, at which time we repaid all of the outstanding borrowings

44

thereunder. We are discussing new borrowing arrangements with other lenders and while we currently believe that we will be able to find a replacement lender, there can be no assurance that we will be able to obtain adequate financing on acceptable terms or at all. For example, our recent results of operations and volatility in oil and gas prices, as well as in the domestic credit and capital markets generally, may negatively affect the availability and terms of financing. If we were to secure a new borrowing arrangement, we expect that such arrangement will include less favorable terms, including with respect to the cost of borrowing and financial covenants, than those of our prior revolving credit facility.  If we are unable to secure a new borrowing arrangement, we will lose a primary source of liquidity and be required to fund our business and operations going forward without outside capital.

A challenge to the EPA’s Clean Air Act designation of the Uintah Basin as “unclassifiable” could result in that area being determined to not be in attainment of the national ambient air quality standard for ozone, which could result in increased permitting, air pollution control, and operating costs for us.

On July 20, 2012, three environmental or public interest organizations filed a petition in the United States Court of Appeals for the District of Columbia Circuit that seeks judicial review of the EPA determination that the Uintah Basin in Utah is “unclassifiable” under the Clean Air Act national ambient air quality standard for ozone.  The plaintiffs contend that the existing ambient air quality monitoring data for the Uintah Basin shows that the area is in not in attainment of the ozone standard, and the EPA therefore violated the Clean Air Act when it made its “unclassifiable” determination.  If the plaintiffs’ suit is successful, the most likely scenario is that the EPA will designate the area as an ozone non-attainment area and the area will become subject to the more stringent permitting and pollution control regulations applicable to non-attainment areas under the Clean Air Act.  If this occurs, our operations in the Uintah Basin would be required to obtain additional permits and install additional air pollution controls, which would result in delays and increased costs to develop our leases in the Uintah Basin and which could have an adverse effect on our business, financial condition, and results of operations.

Item 6 — Exhibits

The following is a list of exhibits filed or furnished (as indicated) as part of this Quarterly Report on Form 10-Q.  Where so noted, exhibits which were previously filed are incorporated herein by reference.

Exhibit Number	Exhibit
2.1	Purchase and Sale Agreement dated February 23, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
2.2	Development Agreement dated March 22, 2012, between Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.2 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
2.3	Closing Agreement dated March 22, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.3 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).

45

3.1	Restated and Amended Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
3.2	Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).
3.3	Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).
3.4	Second Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).
3.5	Certificate of Amendment to Articles of Incorporation, dated September 20, 2010 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated September 15, 2010, filed on September 20, 2010, File No. 001-32369).
3.6	Certificate of Designations, Preferences and Rights of Series B Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement dated April 16, 2003, filed April 17, 2003, File No. 333-104592).
3.7	Certificate of Designation for Series C Convertible Preferred Stock dated as of June 22, 2010 (incorporated herein 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).
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.
101.INS***	XBRL Instance Document
101.SCH***	XBRL Schema Document
101.CAL***	XBRL Calculation Linkbase Document
101.LAB***	XBRL Label Linkbase Document
101.PRE***	XBRL Presentation Linkbase Document
101.DEF***	XBRL Taxonomy Extension Definition Linkbase Document

46

*	Filed herewith.
**	Furnished herewith.
***	Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

47

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: July 31, 2012	By:	/s/ Peggy A. Herald
		Peggy A. Herald, Vice President and
		Chief Accounting Officer
		(Principal Financial Officer
		and Duly Authorized Officer)

48

EXHIBIT INDEX

Exhibit Number	Exhibit
2.1	Purchase and Sale Agreement dated February 23, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
2.2	Development Agreement dated March 22, 2012, between Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.2 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
2.3	Closing Agreement dated March 22, 2012, by and among Gasco Production Company and Wapiti Oil & Gas II, L.L.C. (incorporated herein by reference to Exhibit 2.3 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
3.1	Restated and Amended Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
3.2	Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).
3.3	Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).
3.4	Second Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).
3.5	Certificate of Amendment to Articles of Incorporation, dated September 20, 2010 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated September 15, 2010, filed on September 20, 2010, File No. 001-32369).
3.6	Certificate of Designations, Preferences and Rights of Series B Convertible Preferred Stock (incorporated herein by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement dated April 16, 2003, filed April 17, 2003, File No. 333-104592).

49

3.7	Certificate of Designation for Series C Convertible Preferred Stock dated as of June 22, 2010 (incorporated herein 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).
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.
101.INS***	XBRL Instance Document
101.SCH***	XBRL Schema Document
101.CAL***	XBRL Calculation Linkbase Document
101.LAB***	XBRL Label Linkbase Document
101.PRE***	XBRL Presentation Linkbase Document
101.DEF***	XBRL Taxonomy Extension Definition Linkbase Document

*	Filed herewith.
**	Furnished herewith.
***	Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

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