10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2012

or

o TRANSITION 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	(I.R.S. Employer
incorporation or organization)	Identification No.)
7979 E. Tufts Avenue, Suite 1150, Denver, CO	80237
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (303) 483-0044

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
COMMON STOCK, $0.0001 PAR VALUE	NYSE MKT LLC

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

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 xNo 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 Act). Yes o No x

As of June 29, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the outstanding shares of common stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the shares of common stock outstanding, for this purpose, as if they may be affiliates of the registrant) was approximately $30,216,255 based on a price of $0.18 per share, which was the closing price per share as reported on the NYSE MKT LLC on such date. As of March 6, 2013, 169,749,981 shares of common stock, par value $0.0001 per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information required by Part III of this Annual Report on Form 10-K is incorporated by reference from portions of the registrant’s definitive proxy statement relating to its 2013 annual meeting of stockholders to be filed pursuant to Regulation 14A within 120 days of December 31, 2012. Other items incorporated by reference are listed in the Exhibit Index of this Annual Report on Form 10-K.

Table of Contents

Part I
Item 1.	Business	10
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	49
Item 2.	Properties	50
Item 3.	Legal Proceedings	58
Item 4.	Mine Safety Disclosures	59
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	60
Item 6.	Selected Financial Data	60
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	61
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	79
Item 8.	Financial Statements and Supplementary Data	80
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	121
Item 9A.	Controls and Procedures	121
Item 9B.	Other Information	124

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Part III
Item 10.	Directors, Executive Officers and Corporate Governance	124
Item 11.	Executive Compensation	124
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	124
Item 13.	Certain Relationships and Related Transactions, and Director Independence	124
Item 14.	Principal Accounting Fees and Services	125
Part IV
Item 15.	Exhibits, Financial Statement Schedules	125

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Some of the information in this Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical fact included in this report, including, without limitation, statements regarding Gasco Energy, Inc. and its consolidated subsidiaries’ (collectively, “Gasco,” the “Company,” “we,” “our” or “us”) future financial position, expectations with respect to liquidity, capital resources and ability to continue as a going concern, business strategy, budgets, projected costs and plans and objectives 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 Form 10-K 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 in (1) “Item 1A.— Risk Factors,” “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Item 7A—Quantitative and Qualitative Disclosure About Market Risk” and elsewhere in this report, and (2) our reports and registration statements filed from time to time with the Securities and Exchange Commission (“SEC”). 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 among the important factors that could cause future results to differ materially and adversely from any projected, forecasted, estimated or budgeted amounts that we have discussed in this report:

·our ability to maintain adequate cash flow from operations or to obtain adequate financing to fund our capital expenditures, meet working capital needs and our related ability to continue as a going concern;

·the volatility and recent declines in our stock price, and our ability to regain and maintain compliance with the NYSE MKT LLC’s (the “Exchange”) continued listing requirements;

·our ability to meet our firm commitment delivery obligations in our transportation and processing agreements or otherwise satisfy minimum volume deficiency payment obligations;

·our ability to pursue strategic restructuring, refinancing or other transactions which may be necessary to our ability to continue as a going concern, and which ability is likely to be limited in light of our current liquidity situation and recent results of operations;

·our ability to remain in compliance with the terms and conditions of our outstanding convertible senior notes and warrants, and in the event we are unable to remain in compliance with the terms and conditions of such securities, our ability to pay any accelerated indebtedness or meet any repurchase obligations required under the governing documents for such securities;

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·our ability to maintain relationships with suppliers, customers, employees, stockholders and other third parties in light of our current liquidity situation and recent results of operations;

·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;

·our ability to successfully operate our business within the restrictions imposed on us by the indenture governing our senior notes;

·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 gathering, transportation or processing facilities of our natural gas, which would negatively affect our ability to deliver our natural gas production for sale;

·marketing of oil and natural gas;

·pipeline constraints;

·changes in 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; and

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

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Any of these factors could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us. 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.

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GLOSSARY OF NATURAL GAS AND OIL TERMS

The following is a description of the meanings of some of the natural gas and oil industry terms used in this Annual Report on Form 10-K.

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

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.

Earning well.A well capable of producing oil or gas in commercial quantities.

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.

GAAP. Generally accepted accounting principles in the United States.

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.

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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. For a discussion of PV-10 and standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure, see “Oil and Natural Gas Reserves” in “Item 2.—Properties.”

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.

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Proved properties. Properties with proved reserves.

Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage 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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PART I

ITEM 1 - BUSINESS

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 generating and developing 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. As of December 31, 2012, we held interests in 156,285 gross (57,950 net) acres located in Utah and California. As of December 31, 2012, we held an interest in 133 gross (40 net to our interest) producing wells and three gross (one net) shut-in wells located on these properties.

We were incorporated on April 21, 1997 under the laws of the State of Nevada.  We operated as a shell company until December 31, 1999.

2012 and Recent Highlights

Outlook

Due to the significant extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated.  As such, there is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013.  We have not allocated any amounts to the 2013 capital budget.  Our prior revolving credit facility matured in June 2012, at which time we repaid all of the outstanding borrowings thereunder. While we have attempted to secure a replacement facility, we have been unable to do so on acceptable terms and we are no longer actively in discussions to obtain a replacement facility.  There can be no assurance that we will be able to adequately finance our operations or execute our existing short-term and long-term business plans, and our liquidity and results of operations are likely to be materially adversely affected if we are unable to generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity.  We have engaged a financial advisor to assist us in evaluating such potential strategic alternatives. It is possible these strategic alternatives will require us to make a pre-package, pre-arranged or other type of filing for protection under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against us). These factors raise substantial doubt about our ability to continue as a going concern.  For additional information regarding our current liquidity situation, please see “Liquidity and Capital Resources” in Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Uinta Basin Joint Venture

On March 22, 2012, we closed a transaction (the “Uinta Basin Transaction”) whereby, pursuant to the Purchase and Sale Agreement (the “Purchase Agreement”) dated February 23, 2012, between our 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, we (i) sold to Wapiti an undivided 50% of our 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 repaid in full during the second quarter of 2012, and (ii) transferred to Wapiti an undivided 50% of our interest in certain of 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.

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 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. If we are not able to pay our share of the above costs, we may lose certain rights granted under the Development Agreement and related operating agreements, including the right to continue as operator or contract operator of the properties, the right to make proposals or elect to participate in operations under the Development Agreement or any operating agreement, the right to call, attend and vote at meetings of the operating committee, the right to transfer our interest in the properties and the joint venture, the right to acquire Wapiti’s interest in the properties under the right of first offer provisions of the Development Agreement and the right to acquire its pro rata share of additional properties acquired by Wapiti within the area of mutual interest identified in the Development Agreement. We have not incurred any costs to date and there is substantial doubt regarding our ability to fund our share of the drilling and completion 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 us 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 us and 80% by Wapiti, (b) after the Drilling Term but before Payout, 32.5% by us 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 us 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, we 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)

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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.  However, to the extent that Gasco Production Company, as operator under these agreements, becomes insolvent, bankrupt or is placed into receivership, it will be deemed to have resigned as operator or the other party may have termination rights.  Wapiti and we 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 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.

Due to low natural gas prices and permitting delays, we did not drill any natural gas wells in Utah from the closing of the Uinta Basin Transaction through the remainder of 2012.

NYSE MKT LLC Communications

On December 6, 2012, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange set forth in Section 1003(f)(v) of the NYSE MKT LLC Company Guide (the “Company Guide”) because our common stock has traded at a low price per share for a substantial period of time.  We have not yet determined what action, if any, we will take in response to this notice.  In the notice, the Exchange predicates our continued listing on the Exchange on us effecting a reverse stock split of our common stock by June 6, 2013.

On January 11, 2013, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange set forth in Section 1003(a)(iv) of the Company Guide, which applies if a listed company has sustained losses which are so substantial in relation to its overall operations or its existing financial resources, or its financial condition has become so impaired that it appears questionable, in the opinion of the Exchange, as to whether such company will be able to continue operations and/or meet its obligations as they mature.

In order to maintain our listing, we were required to submit a plan of compliance (a “Plan”) addressing how we intend to regain compliance with Section 1003(a)(iv) of the Company Guide by June 30, 2013.  We provided the Exchange with a Plan on February 11, 2013, that addressed how we intend to regain to compliance with Section 1003(a)(iv) of the Company Guide. Pursuant to the Plan, we intend to lower costs, rationalize assets, refocus our development program toward oil and liquids, especially in the Green River Formation, and continue our California program with the potential goal of expanding our California model.  The Plan also considers strategic alternatives, including the debt restructuring and sales of assets, if necessary.  However, there can be no assurance that the Plan will be accepted by the Exchange or that we will be able to achieve compliance with the Exchange’s continued listing standards within the required time frame.  If the Plan is not accepted, we will be subject to delisting proceedings.

Furthermore, if the Plan is accepted but we are not in compliance with the continued listing standards of the Company Guide by June 30, 2013, or if we do not make progress consistent with the Plan, the Exchange staff will initiate delisting proceedings as it deems appropriate.

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Environmental Impact Statement

In June 2012, the U.S. Bureau of Land Management (“BLM”) signed the Record of Decision (“ROD”) 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. However on January 18, 2013, certain non-governmental environmental organizations, including the Southern Utah Wilderness Alliance (“SUWA”), filed a suit against the BLM challenging the ROD and alleging that the BLM failed to comply with the requirements of the National Environmental Policy Act, as amended (“NEPA”), and its implementing regulations.  On February 13, 2013, SUWA voluntarily submitted notice of dismissal of the suit to the District Court. For more information, see “Item 3 — Legal Proceedings — NEPA Suit.”

Our project will tap an existing gas field that already has 133 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 gross acres of BLM-administered lands.

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 pump and continue to produce oil as expected.

During the third quarter 2012, we implemented a workover program to target by-passed oil in older Wasatch / Mesaverde oil wells and Green River oil wells.  Since the workover program commenced in the second half of 2012, we have performed eight workovers in the Green River Formation which have yielded a per-well average of a 15% to 20% increase in net oil production, as compared to rates recorded prior to the well workovers.

We believe that the workover program presents a low-cost opportunity to boost oil production in advance of the new-drill Green River oil program that is expected to commence during the third quarter of 2013, depending on rig availability.  We continue to identify wells suitable for by-passed oil workovers, and have identified an additional three wells for workover activities and further production enhancement.

Drilling Plans

Our six-well Green River oil well program is now fully permitted.  However, the newly issued permits include burrowing owl and golden eagle drilling stipulations that will delay the spudding of these six wells until the third quarter of 2013.  Five additional Green River oil well locations are in the process of being permitted by regulatory agencies and we anticipate that these permits will be issued before the third quarter of 2013 and added to the drilling schedule along with the six-well Green River oil well program.  We are also in the process of permitting our Uinta Basin natural gas pad-well drilling program.

We have a participating interest in a horizontal well (7.14% working interest/non-operated) to test the productive potential of the oil-prone C-Shoal member of the Green River Formation.  The well, with a proposed 4,250 foot lateral length, will be operated by an industry partner that has successfully drilled numerous horizontal Green River oil wells in the Uinta Basin.  The operator spud the well in February 2013.

As described previously, there is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and

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forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. These factors raise substantial doubt about our ability to continue as a going concern.  Our drilling plans will be adjusted or completely terminated if we do not have adequate cash flow to fund these projects. For example, we have not allocated any amounts to the 2012 capital budget.

Working Interest Acquisition

During December 2012, we acquired additional working interests in 32 producing wells in the Riverbend area of Utah, in which we have a working interest and operate, for $177,620. The acquired interests range from 4% to 10% per well with an average of 8% per well and represented an estimated increase to our reserves of approximately 596,000 Mcfe.

California Projects

Willow Springs

The exploratory 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 13, 2013.

Antelope Valley

In order to complete the processing of the large Antelope Valley 3D seismic survey, our partner was granted a one-year extension in the spudding of the first test earning well at our Antelope Valley prospects.  The first test well is expected to be spud before July 2013.  In exchange for the drilling extension, our partner has agreed to pay for all lease rentals between July 1, 2012 and the spudding of the first exploratory well. Our partner has also committed to spudding a well on the Southwest Cymric prospect prior to December 31, 2013.

Northwest McKittrick

The operator of the Northwest McKittrick prospect recently reached total depth on the first of three earning wells on which we are carried for a 20% working interest.  Well logs identified the presence of a structure which helps confirm our geologic model; however, the well penetrated the primary objective 300 feet down-dip from the targeted depth.

As part of the terms of the farm-out agreement, the partner in Northwest McKittrick has until March 12, 2013 to spud the second test well to continue to fully earn into the prospect. Our partner has notified us that they don’t intend to drill a second well. We are currently seeking a replacement partner for this project.

Southwest Cymric

During January 2012, we entered into an arrangement with an exploration and production company which operates in California, pursuant to which we received a $750,000 prospect fee related to certain of our California acreage. The fee reimbursed costs that we have invested in the area and provides us with a potential carried interest of 20% in one well to be drilled on the acreage. Our arrangement with the

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operator requires them to spud this well prior to January 18, 2014 in order to earn their share of the prospect.

Gas Processing Agreements

On March 22, 2012, we entered into an Amended and Restated Gas Gathering and Processing Agreement (the “Amended and Restated Monarch Agreement”) with Monarch Natural Gas, LLC, a Delaware limited liability company (“Monarch”), which amends, restates and replaces the Gas Gathering and Processing Agreement effective March 1, 2010 (the “Existing Monarch Agreement”).  Pursuant to the terms of the Existing Monarch Agreement, we dedicated the gas production from all of our Utah acreage to Monarch and Monarch agreed to provide gathering, compression and processing services to us.

Under the Amended and Restated Monarch Agreement, Monarch agreed, among other things, to (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 Amended and Restated Monarch Agreement also provides that we are committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and we are obligated to pay for any shortfall following the end each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the agreement.

In connection with the Amended and Restated Monarch Agreement, we also entered in to the QPC Transportation Agreement pursuant to which we agreed to enter into separate transportation services agreements for firm transportation services. We are currently committed to deliver to QPC for transportation services a minimum of 25,000 MMBtu/day.

During the year ended December 31, 2012, the Amended and Restated Monarch Agreement covered the gathering, processing, compressing and delivery of our gross production of natural gas from all of our Utah acreage from wellheads to points of sale.

Effective February 7, 2013, Chipeta Processing LLC (“Chipeta”) began processing the natural gas production from our Utah acreage through a cryogenic processing facility that was built by Chipeta. Pursuant to the Chipeta Processing Agreement, which we signed on September 21, 2011 and subsequently amended on December 1, 2012, we reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing and 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 primary term of the Chipeta Processing Agreement began upon the completion of the building of Chipeta’s facility on February 7, 2013.  Under this agreement, we are committed to deliver, on average, at least 90% of our contracted cryogenic capacity of 25,000 Mcf/d (the “Minimum Daily Quantity”) during each monthly accounting period.  Following the first twelve monthly accounting periods, Chipeta may determine whether we failed to deliver equal to or greater than the Minimum Daily Quantity multiplied by the number of days in the annual accounting period.  If we delivered less than the quantity we committed to deliver, we would be required to pay a deficiency payment equal to the contracted cryogenic processing fee multiplied by the deficient quantity. In addition, to the extent that Chipeta has reasonable grounds for uncertainty regarding the performance of our obligations under our gas processing agreement, including a material change in our creditworthiness, Chipeta may sell our natural gas and apply amounts received against any amounts we owe to Chipeta, set off any amount owed to us against amounts owed to Chipeta or cease processing our natural gas until our account is current, with interest.  Chipeta may also demand adequate assurance of performance from us, which may be in the form of a standby irrevocable letter of credit, prepayment or performance bond or guaranty.

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Since the beginning of the primary term of the Chipeta Processing Agreement, Chipeta has provided all of our natural gas processing services, and we have not produced any amounts of natural gas in excess of the Excluded Production.  Monarch and QPC continue to gather and transport our natural gas. Please read “Item 1A—Risk Factors—Pursuant to the Gas Processing Agreement with Chipeta and the Amended and Restated Monarch Agreement, we may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments” and “Item 2.—Properties—Delivery Commitments.”

Director Stock Appreciation Right and Stock Option Grants

Effective February 28, 2012, we granted stock appreciation rights (“February SARs”) related to a total of 1,000,000 shares of our common stock to our non-employee directors.  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 greater, 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 vested on January 31, 2013 and were automatically exercised on February 1, 2013. Since the market value of the common stock was lower than $0.25, no payments were made.

Additionally, effective February 28, 2012, we granted a total of 500,000 options to purchase common stock with a strike price of $0.30 per share to our non-employee directors. The options have a two-year vesting period and expire five years from the grant date.

Appointment of Vice President of Business Development and Operations

Effective March 1, 2012, we hired Mr. Richard P. Crist as Vice President, Business Development and Exploration, a newly created position that will add additional experience and expertise to our senior management team.

Markets and Customers

We focus our exploitation activities on locating natural gas and petroleum.  The success of our operations is dependent primarily upon prevailing and future prices for natural gas and, to a lesser extent, oil.  Higher market prices may allow us to produce more natural gas or oil economically and therefore would positively impact our financial condition.  Conversely, declines in natural gas or oil prices may have a material adverse affect on our financial condition, profitability and liquidity.  Natural gas and oil prices are set by broad market forces, which have historically been and will likely continue to be volatile in the future.  Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control. Natural gas currently is selling at significantly lower prices than oil on an energy equivalent basis due to excess natural gas in storage and excess production compared to demand. Significant or extended price declines may adversely affect the amount of oil and natural gas that we can produce economically.

The principal markets for these commodities are natural gas transmission pipeline and marketing companies, utilities, refining companies and private industry end-users. We currently distribute the gas that we produce through a single interstate pipeline.  Any constraints on the capacity of this pipeline could adversely affect our ability to sell production and, in certain circumstances, may limit our ability to sell any or all of our production in a given period.  If this pipeline were to become unavailable, we would incur additional costs to secure a substitute facility in order to deliver the gas that we produce.

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Because we do not own or operate any natural gas pipelines or distribution facilities, we rely on third parties to construct and operate additional interstate pipelines to increase our ability to bring our production to market.  Any significant change affecting these facilities or our failure to obtain timely access to existing or future facilities on acceptable terms could restrict our ability to conduct normal operations.  Delays in the commencement of operations of new pipelines, the unavailability of new pipelines or other facilities due to market conditions, mechanical reasons or otherwise could have an adverse impact on our results of operations and financial condition.

Any failure by the transportation, gathering or processing facility thereto to timely perform its obligations under the gas transportation, gathering and processing agreements may limit our ability to deliver production into the interstate pipeline where it is sold.  A delay or reduction in the amount of natural gas that we sell as a result of a failure by the transportation, gathering or processing facility to timely perform such obligations could have a material adverse effect on our business, financial condition or results of operations.

Historically, nearly all of our sales have been to a few customers. The majority of our production was sold to one customer, Anadarko Petroleum Corporation (“Anadarko”), during each of the years ended December 31, 2012, 2011 and 2010. For the years ended December 31, 2012, 2011 and 2010, purchases by the following companies exceeded 10% of our total oil and natural gas revenues.

	For the Years Ended December 31,
	2012			2011			2010
Revenues associated with EnWest Marketing LLC (“EnWest”) purchases	$	2,098,841		$	2,974,294		$	2,604,206
Revenues associated with Anadarko purchases	$	6,232,285		$	14,339,564		$	16,294,083
Percentage of oil and natural gas revenues attributable to:
EnWest	24		%	16		%	13		%
Anadarko	70		%	78		%	83		%

While Anadarko and EnWest currently purchase the majority of our production, we do not believe that the loss of a single purchaser, including Anadarko and EnWest, would materially affect our business because there are other potential purchasers in the areas in which we sell our production. However, we may not be able to find other purchasers who would purchase our production on terms comparable to our current arrangements.

Competition

Our natural gas and petroleum exploitation development and production activities take place in a highly competitive and speculative business atmosphere.  In seeking suitable natural gas and petroleum properties for acquisition, we compete with a number of other companies operating in our areas of interest, including large oil and gas companies and other independent operators.  Many of our competitors have greater financial resources than we do, which is exacerbated due to our current liquidity position.  Also, many have been engaged in the exploration and production business for a much longer time than we have or not only explore for and produce, but also market natural gas and oil and other products on a regional, national or worldwide basis. Many of our competitors also have a substantially larger operating staff than we do.  These competitors may be able to pay more for productive natural gas and oil properties and exploratory prospects and define, evaluate, bid for and purchase a greater number of properties and prospects than us.  In addition, these competitors may have a greater ability to continue exploration activities during periods of low market prices.  Our ability to acquire additional properties and to discover

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reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

As discussed under “Item 1A.—Risk Factors,” we are required to obtain drilling and right of way permits for our wells, and there is no assurance that such permits will be available timely or at all.

The prices of our products are controlled by regional, domestic and world markets.  However, competition in the petroleum and natural gas exploitation, development and production industry also exists in the form of competition to acquire the most promising acreage blocks and obtaining the most favorable prices for transporting the product.  We, and the projects in which we participate, are relatively small compared to other petroleum and natural gas exploitation, development and production companies. As a result, we may have difficulty acquiring additional acreage and/or projects, and may have difficulty arranging for the transportation of the oil or natural gas we produce. We also face competition in obtaining natural gas and oil drilling rigs and in providing the manpower to operate them, as well as providing related services.

Seasonal Nature of Business

Generally, demand for natural gas decreases during the summer months, and increases during the winter months.  Seasonal anomalies such as mild winters or abnormally hot summers sometimes lessen this fluctuation.  In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer.  This can also lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other natural gas and oil operations in certain areas. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Industry and Geographic Information

We operate in one industry segment, which is the exploitation, development and production of natural gas and petroleum.  Our current operational activities are conducted in, and our consolidated revenues are generated from markets principally within the Rocky Mountain region of the United States, and we have no long-lived assets located outside the United States.

Environmental and Occupational Safety and Health Matters

We are subject to stringent federal, regional, state, and local laws and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection.  These laws and regulations may require the acquisition of permits before conducting drilling or other regulated activities, limit or prohibit operations on environmentally sensitive lands such as wetlands or wilderness areas, require capital expenditures to limit or prevent emissions or discharges, impose specific safety and health criteria addressing worker protection, and place restrictions on the management of wastes.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.  Any changes in environmental laws and regulations that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, disposal or cleanup requirements could have an adverse effect on our financial position and results of operations.  We may be unable to pass on such increased compliance costs to our customers.  Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.  While we believe that we are in substantial

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compliance with current environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that this trend will continue in the future.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as “Superfund,” and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.  These persons include the current and past owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site.  Under CERCLA, these “responsible persons” may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment.  We generate materials in the course of our operations that may be regulated as hazardous substances.  We also may incur liability under the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, which impose requirements relating to the management and disposal of nonhazardous and hazardous solid wastes.  While there exists an exclusion from the definition of hazardous wastes for “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy,” which allows such wastes to be regulated under RCRA’s less stringent nonhazardous waste provisions or state laws, there remains the possibility that some or all of these currently excluded wastes could be reclassified as hazardous wastes in the future.  A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position.  In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, including paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous waste.

We currently own or lease, and have in the past owned or leased, properties that for a number of years have been used for the exploration and production of oil and gas.  Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for recycling or disposal.  In addition, some of these properties may have been operated by third parties whose disposal or release of petroleum hydrocarbons or other wastes was not under our control.  These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws.  Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination or to perform remedial operations to prevent future contamination.

The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and gas wastes, into state or federal waters.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the U.S. Environmental Protection Agency (“EPA”) or the state.  Spill prevention, control and countermeasure plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.  In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.  The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit.  The Clean Water Act provides for the

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assessment of administrative, civil and criminal penalties for any unauthorized discharge of oil in harmful quantities and imposes liabilities for the costs of removing an oil spill.

Hydraulic fracturing is an important and common industry practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production.  We routinely use hydraulic fracturing techniques in many of our drilling and completion programs.  Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, as amended (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels.  In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations.  In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.  Some states have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities.  Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.  We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities.  Nevertheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.  The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014.  Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our hydraulic fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our pollution liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

The Clean Air Act, as amended (“CAA”), and comparable state laws restricts the emission of air pollutants from many sources, including oil and gas operations.  These laws and any implementing

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regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants.  The need to obtain permits has the potential to delay the development of oil and natural gas projects.  Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues.  For example, on August 16, 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs.  With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted:  wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells.  All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012.  However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015.  These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2013. We are currently reviewing this new rule and assessing its potential impacts on our operations.  Compliance with these requirements could increase our costs of development and production, which costs could be significant.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions.  Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis.  These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.  In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among other things, onshore oil and natural gas procession activities, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.  In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.  In California, where we own or control leaseholds in acreage, the state has adopted a GHG cap-and-trade program that entered into force in January 2013 and imposes compliance obligations upon certain industrial GHG emitters.  The California market held its first auction for GHG allowances in November 2012.  Because we conduct no operations in California, we do not expect that this state cap-and-trade program will have a material adverse effect on our operations. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on

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operations and reduce demand for refined products.  Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations and such requirement also could adversely affect demand for the oil and natural gas we produce.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods.  If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance.  Another possible consequence of climate change is increased volatility in seasonal temperatures.  The ultimate market for some of our natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce.  Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience substantially colder temperatures than their historical averages.  As a result, it is difficult to predict how the market for our fuels would be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it could have an adverse effect on our business.

Oil and natural gas exploration, development and production activities on federal lands, including Indian lands and lands administered by the “BLM, are subject to the National Environmental Policy Act, as amended.  NEPA requires federal agencies, including the BLM, to evaluate major agency actions, such as, for example the issuance of certain permits, which have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement (“EIS”) that may be made available for public review and comment.  We have worked with the BLM in the preparation and completion of an EIS in connection with certain proposed exploration and production operations in the Uinta Basin of Utah.  As previously discussed, in June 2012, the BLM signed and issued the Record of Decision on the EIS that authorizes the development of our Uinta Basin field upon federal lands in Duchesne and Uintah Counties, Utah.  This field includes our core Riverbend Project.  However on January 18, 2013, certain non-governmental environmental organizations, including the Southern Utah Wilderness Alliance, filed a suit against the BLM, challenging the ROD issued by that agency.  In its complaint, SUWA alleges that the BLM failed to comply with the requirements of NEPA and its implementing regulations.  SUWA was seeking, among other things, that the ROD and EIS be set aside, the effect of which would void the BLM’s authorization for us to proceed with our planned project.  Only recently, on February 13, 2013, SUWA voluntarily submitted notice of dismissal of the suit to the District Court. Because SUWA voluntarily withdrew its suit, it has the opportunity to refile the suit at a later date. Whether SUWA will refile this suit at a later date is currently unknown to us. While any future suit by SUWA or any other third party that seeks to set aside the ROD issued by the BLM for our planned project in the Uinta Basin field in Utah could, if successful, have a material adverse effect on our ability to perform the planned project, we would not expect the outcome of such proceeding to have a material adverse effect on our financial position, results of operations or cash flows. See “Legal Proceedings—NEPA Suit” for more information on this matter.

Environmental laws such as the Endangered Species Act, as amended (“ESA”), may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States, and prohibits taking of endangered species. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or

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modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA.  If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required.  Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year.  The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Corporate Office

Our corporate office is located at 7979 E. Tufts Avenue, Suite 1150, Denver, Colorado, where we lease 11,170 square feet through May 31, 2017.

Insurance Matters

As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is unavailable or because premium costs are considered prohibitive.  A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations or cash flows.  We maintain insurance at customary industry levels to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of certain prohibited substances into the environment.  Such insurance might not cover the complete amount of such a claim and would not cover fines or penalties for a violation of an environmental law.  In analyzing our operations and insurance needs, we compare premium costs to the likelihood of material loss of production. Based on this analysis, we carry the following policies: property insurance, commercial general liability, umbrella liability, fiduciary liability, and control of well.

Employees

As of March 6, 2013, we had 25 full-time employees.

Available Information

We file annual, quarterly and current reports, proxy statements and other information electronically with the SEC.  You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549.  You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  The SEC maintains an internet site,

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www.sec.gov, that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including our filings.

Our internet address is www.gascoenergy.com.  We make available free of charge on or through our internet site our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. None of the information on our website should be considered incorporated into or a part of this Annual Report on Form 10-K.

ITEM 1A. Risk Factors

Described below are known material risks that we believe are applicable to our business and the oil and natural gas industry in which we operate. There may be additional risks that are not presently material or known to us. You should carefully consider each of the following material risks and all other information set forth in this Annual Report.

If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected and you could lose part or all of your investment in our securities.

Risks Related to Our Liquidity and Indebtedness

We currently anticipate that our cash on hand as well as forecasted cash flows from operations will only be sufficient to fund our anticipated cash requirements for working capital purposes and normal capital expenditures through the second quarter of 2013.  If we are unable to generate sufficient cash flows, secure additional capital or otherwise restructure or refinance our business, we would not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against us).

Our consolidated financial statements included in this Annual Report on Form 10-K (“Annual Report”) have been prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the next twelve months.  However, due to the significant extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated.  For example, we had net losses and negative cash flow from operations for the three and twelve months ended December 31, 2012 and at December 31, 2012 had an accumulated deficit of $244,808,156.  There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013.  This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of our cash management strategy discussed below, some or all of which may not prove to be correct and may result in our inability to meet cash requirements prior to the second quarter of 2013. Our prior revolving credit facility matured in June 2012, at which time we repaid all of the outstanding borrowings thereunder. While we have attempted to secure a replacement facility, as of the date of this Annual Report, we have been unable to do so on acceptable terms and are no longer actively in discussions to obtain a replacement facility.  Furthermore, we may not achieve

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profitability from operations in the near future or at all and we may continue to experience significant losses.  These factors raise substantial doubt about our ability to continue as a going concern.

As of December 31, 2012, we had $45,168,000 aggregate principal amount of our 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”) outstanding.  The 2015 Notes bear interest at a rate of 5.50% per annum, payable in cash semi-annually in arrears on April 5th and October 5th of each year.  Our failure to make an interest payment on the 2015 Notes, if not cured within 30 days, or the delisting of our common stock from the Exchange would result in a default under the indenture governing the 2015 Notes, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes.

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 resulting in 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 fund the level of capital expenditures required for oil and gas exploration and production activities. We intend to fund our anticipated cash requirements through the second quarter of 2013 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. If they are not, our liquidity and results of operations will be materially adversely affected and we would not be able to continue as a going concern.

To continue as a going concern, we must generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity.  The urgency of our liquidity constraints may require us to pursue such a transaction at an inopportune time.  Moreover, our ability to successfully implement, and the cost of, any such transaction will depend on numerous factors, including:

·demand and prices for natural gas and oil;

·general economic conditions;

·strength of the credit and capital markets;

·our ability to successfully execute our operational strategies, and our operating and financial performance;

·our ability to remain in compliance with our debt and equity instruments;

·our ability to remain in compliance with our operational agreements, including our gas processing, gathering and transportation agreements;

·our counterparties refraining from exercising any remedies available as a result of the determination that we are insolvent or unable to perform in accordance with the contract;

·our stock price, and ability to regain and maintain compliance with the Exchange’s continued listing requirements;

·our ability to maintain relationships with our suppliers, customers, employees, stockholders and other third parties; and

·market uncertainty in connection with our ability to continue as a going concern as well as investor confidence in us.

If we fail to generate sufficient operating cash flows, secure additional capital or otherwise restructure or refinance our business before the end of the second quarter of 2013, we will not have adequate liquidity to fund our operations and meet our obligations (including our debt payment obligations), we will not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against us).  If we file for bankruptcy protection, our business and operations will be subject to certain risks.

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A bankruptcy filing by or against us would subject our business and operations to various risks, including but not limited to, the following:

·a bankruptcy filing by or against us may adversely affect our business prospects, including our ability to continue to obtain and maintain the contracts necessary to operate our business on competitive terms;

·a bankruptcy filing by or against us may cause an event of default under the indenture governing the 2015 Notes;

·certain provisions in our operating agreements may be triggered such that we would be deemed to have resigned as operator or the agreements may be terminated by the other party;

·we may be unable to retain and motivate key executives and employees through the process of reorganization, and we may have difficulty attracting new employees;

·there can be no assurance as to our ability to maintain or obtain sufficient financing sources for operations or to fund any reorganization plan and meet future obligations;

·there can be no assurance that we will be able to successfully develop, prosecute, confirm and consummate one or more plans of reorganization that are acceptable to the bankruptcy court and our creditors, equity holders and other parties in interest; and

·the value of our common stock could be reduced to zero as result of a bankruptcy filing.

We also cannot assure you that our common stock will be liquid or that it will remain listed on the Exchange as described in greater detail below.

In order to address our liquidity constraints and in addition to our ongoing efforts to secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity, we have embarked on a cash management strategy to enhance and preserve as much liquidity as possible. This plan contemplates us, among other things:

·reducing expenditures by eliminating, delaying or curtailing discretionary and non-essential spending, and not designating any capital budget for 2013;

·managing working capital;

·delaying certain drilling projects;

·pursuing farm-out and other similar types of transactions to fund working capital needs;

·evaluating our options for the divestiture of certain assets;

·considering asset purchases through the issuance of equity;

·investigating merger opportunities; and

·restructuring and reengineering our organization and processes to reduce operating costs and increase efficiency.

We cannot provide any assurances that we will be successful in accomplishing any of these plans or that any of these actions can be effected on a timely basis, on satisfactory terms or maintained once initiated. Furthermore, our cash management strategy, if successful, may limit certain of our operational and strategic initiatives designed to grow our business over the long term.

Our stock price has been volatile and any investment in our common stock could suffer a significant decline or total loss in value. Furthermore, we are not currently in compliance with and cannot assure you that we will be able to regain and maintain compliance with the continued listing standards of the Exchange.

Because we face significant uncertainties relating to our ability to generate sufficient cash flows from operations and to continue to operate our business, our stock price is volatile and any investment in our

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common stock could suffer a significant decline in value.  Furthermore, we may not be able to regain or maintain compliance with the continued listing standards of the Exchange.  The Exchange requires companies to meet certain continued listing criteria as outlined in the Company Guide.  We are currently not in compliance with such criteria.  We have received formal notices from the Exchange regarding noncompliance with the Exchange’s continued listing criteria.

On December 6, 2012, we received a notice indicating that we do not satisfy the continued listing standards set forth in Section 1003(f)(v) of the Company Guide because our common stock has traded at a low price per share for a substantial period of time.  We have not yet determined what action, if any, we will take in response to this notice.  In the notice, the Exchange predicates our continued listing on the Exchange on us effecting a reverse stock split of our common stock by June 6, 2013.

On January 11, 2013, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards set forth in Section 1003(a)(iv) of the Company Guide, which applies if a listed company has sustained losses which are so substantial in relation to its overall operations or its existing financial resources, or its financial condition has become so impaired that it appears questionable, in the opinion of the Exchange, as to whether such company will be able to continue operations and/or meet its obligations as they mature.

We provided the Exchange with a Plan on February 11, 2013, to address how we intend to regain to compliance with Section 1003(a)(iv) of the Company Guide. Pursuant to the Plan, we intend to lower costs, rationalize assets, refocus our development program toward oil and liquids, especially in the Green River Formation, and continue our California program with the potential goal of expanding our California model.  The Plan also considers strategic alternatives, including the debt restructuring and sales of assets, if necessary.  However, there can be no assurance that the Plan will be accepted by the Exchange or that we will be able to achieve compliance with the Exchange’s continued listing standards within the required time frame. If the Plan is not accepted, we will be subject to delisting proceedings.

Furthermore, if we are not in compliance with the continued listing standards of the Company Guide by June 30, 2013, or if we do not make progress consistent with the Plan, the Exchange staff will initiate delisting proceedings as it deems appropriate.

The delisting of our stock from the Exchange could result in even further reductions in our stock price, would substantially limit the liquidity of our common stock, and materially adversely affect our ability to raise capital or pursue strategic restructuring, refinancing or other transactions on acceptable terms, or at all.  Delisting from the Exchange could also have other negative results, including the potential loss of confidence by suppliers and employees, the loss of institutional investor interest and fewer business development opportunities. Furthermore, delisting may result in an event of default under the indenture governing our 2015 Notes, which requires that we list the shares of common stock that may be issued upon conversion of the 2015 Notes and the Preferred Stock on the Exchange or any other U.S. national or regional securities exchange.

Pursuant to the Gas Processing Agreement with Chipeta and the Amended and Restated Monarch Agreement, we may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments.

Pursuant to our Gas Processing Agreement with Chipeta, we dedicated certain of our natural gas production from our acreage in Utah to Chipeta for processing. We reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing and 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 primary term of the Chipeta Processing Agreement began upon the completion of the building of Chipeta’s facility on February 7, 2013.  Under this agreement, we are committed to deliver, on

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average, at least 90% of our contracted cryogenic capacity of 25,000 Mcf/d during each monthly accounting period, which is referred to as the Minimum Daily Quantity.  Following the first twelve monthly accounting periods, Chipeta may determine whether we failed to deliver equal to or greater than the Minimum Daily Quantity multiplied by the number of days in the annual accounting period.  If we delivered less than the quantity we committed to deliver, we would be required to pay a deficiency payment equal to the contracted cryogenic processing fee multiplied by the deficient quantity.

Pursuant to the Amended and Restated Monarch Agreement, Monarch agreed, among other things, to release and waive its existing right to process the “Excluded Production” and 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 after three years from the beginning of primary term of the Chipeta Processing Agreement, which was February 7, 2013. The Amended and Restated Monarch Agreement also provides that we are committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and we are obligated to pay for any shortfall following the end each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the agreement.

Pursuant to the QPC Transportation Agreement, we are also committed to deliver to QPC 25,000 MMBtu/day for firm transportation services.

There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations. The maximum undiscounted deficiency payments under the Chipeta Processing Agreement, the Amended and Restated Monarch Agreement and the QPC Transportation Agreement, over the full terms of these contracts, are estimated to be approximately $59 million. Of this amount, approximately $40 million would be owed to Chipeta, $8.5 million would be owed to Monarch and $12.5 million would be owed to QPC. These amounts are owed regardless of whether we deliver any natural gas quantities to the applicable parties.  If we are unable to fund additional drilling projects, and based on our December 31, 2012 reserve estimates, assuming no future drilling and constant gas prices, we estimate that we could have a reasonably possible minimum production shortfall of approximately 54,000 MMcf valued at approximately $37 million in aggregate deficiency payment obligations on an undiscounted gross basis.

We are considering several alternatives to mitigate the reasonably possible estimated production shortfall such as the sale of our firm commitment positions, seeking relief from the firm commitments because of the permitting delays in the area and the purchase of production quantities to meet our minimum production requirements. Also, future increases in gas prices would increase the related reserve estimates and reduce possible shortfalls. However, there is no assurance we will be successful in accomplishing these actions should there be a deficiency. Accordingly, we have not accrued any amounts as of December 31, 2012 as it is not probable or reasonably estimable.  Please read “Item 1—Business—2012 and Recent Highlights—Gas Processing Agreements” and “Item 2.—Properties—Delivery Commitments” for more information.

We have incurred losses and may continue to incur losses in the future. In addition, we have a significant accumulated deficit as of December 31, 2012.

During the years ended December 31, 2012 and 2011, we incurred net losses of $22,232,391 and $7,301,645, respectively.  Furthermore, as of December 31, 2012, we had an accumulated deficit of $244,493,156.  During these periods, our cash flows were insufficient to provide working capital for our ongoing overhead, the funding of our lease acquisitions and the exploration and development of our properties. Because we may face similar shortfalls in the future, and in light of the volatile nature of commodity prices and other uncertainties described in this “Item 1A.— Risk Factors” and elsewhere in this Annual Report, we may be unable to successfully develop any prospects that we have or acquire any

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additional properties without adequate financing and 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.

Lack of access to the credit market could negatively impact our ability to operate our business and to execute our business strategy.

Due to the changes in the global credit market in the recent past, there has been deterioration in the credit and capital markets and access to financing is limited and uncertain.  If the capital and credit markets continue to experience weakness and the availability of funds remains limited, we may incur increased costs associated with any additional financing we may require for future operations or we may be unable to obtain such financing at all.  For example, we have been unable to secure adequate alternative financing to replace our revolving credit facility which expired in June 2012.  Our suppliers may also be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations, each of which could adversely affect our operations.

In addition, some financial institutions and insurance companies have reported significant deterioration in their financial condition. Our forward-looking statements assume that our insurers and other institutions with whom we do business will be able to fulfill their obligations under the various insurance policies or other contracts that we may have with such parties.  If these third parties were unable to perform under such agreements, and if we were unable to find suitable replacements at a reasonable cost, our results of operations, liquidity and cash flows could be adversely impacted.

The indenture governing our 2015 Notes imposes restrictions on us that may affect our ability to successfully operate our business.

The indenture governing our 2015 Notes imposes certain operational and financial restrictions on us that limit our ability to:

·incur additional indebtedness;

·create liens;

·sell our assets to, or consolidate or merge with or into, other companies;

·make investments and other restricted payments, including dividends; and

·engage in transactions with affiliates.

Generally, the restrictions under our indenture could limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities.

Our failure to comply with any material provision or covenant of our indenture, including, among other things, failure to pay any installment of interest or principal on the 2015 Notes, failure to issue shares of common stock upon conversion of the 2015 Notes when required to be delivered, delisting of our common stock from the Exchange, commencement by us of a voluntary bankruptcy proceeding, or entry of a bankruptcy order or decree against us, could result in a default which would, absent a waiver or amendment, require immediate repayment of the 2015 Notes and potentially trigger certain provisions in our operating agreements.  For example, under the JOA and contract operating agreements in connection

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with the Uinta Basin Transaction pursuant to which we serve as operator, if we become insolvent or bankrupt or are placed into receivership, we will be deemed to have resigned as operator or the other party may have termination rights.  If this were to occur, we cannot assure you that our assets would be sufficient to repay in full the money owed to our debt holders.  In addition, to the extent it was necessary to address any anticipated covenant compliance issues prior to default, we may be required to sell a portion of our assets or issue additional securities, which would be dilutive to our existing shareholders.  Given the condition of current credit and capital markets and our current liquidity position, any sale of assets or issuance of additional securities may not be available on terms acceptable to us or at all.

Risks Related to Our Business and Industry

Lower oil and natural gas prices and other factors, including downward revisions of the present value of our proved reserves and increased drilling expenditures without current additions to proved reserves, have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values. We are subject to the full cost ceiling limitation which has resulted in past write-downs of estimated net reserves and may result in a write-down in the future if commodity prices continue to decline.

We may be required to write down the carrying value of our gas and oil properties when gas and oil prices are low or if there are substantial downward adjustments to our estimated proved reserves, increases in the estimates of development costs or deterioration in exploration results. Because we have elected to use the full cost accounting method, we are subject to quarterly calculations of a “ceiling” or limitation on the amount of our oil and gas properties that can be capitalized on our balance sheet.  As explained below, the discounted present value of our proved reserves is a major component of the ceiling calculation and the risk that we will be required to write down the carrying value of oil and natural gas properties increases when natural gas and oil prices are depressed or volatile.  Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges against current earnings.

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

If the net capitalized costs of our oil and gas properties exceed the cost ceiling, we are subject to a ceiling test write-down of our estimated net reserves to the extent of such excess. The present value of estimated future net revenues is computed by applying the twelve month trailing average first-of-month prices of gas and oil to estimated future production of proved gas and oil reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. Expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling applicable in the subsequent period.

As of March 31, 2012, June 30, 2012, September 30, 2012 and December 31, 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, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012, $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012, and $80.25 per barrel and $2.15 per Mcf of gas

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during the 12-month period ended December 31, 2012. Therefore, impairment expense of $16,486,000 was recorded during the year ended December 31, 2012.

Our evaluation of impairment of unproved properties incorporates our expectations of developing unproved properties given current and forward-looking economic conditions and commodity prices. Investments in unproved properties with a carrying value of approximately $31,486,314 as of December 31, 2012, including capitalized interest costs, are assessed periodically to ascertain whether impairment has occurred. Impairments in such properties may result from lower commodity prices, expiration of leases, inability to find partners, inadequate financing or unsuccessful drilling results. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized, or is reported as a period expense, as appropriate. If an impairment of unproved properties results in a reclassification to proved oil and gas properties, the ceiling test cushion would be reduced.

We believe that the majority of our remaining unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before we can explore or develop it further, or by making decisions that further exploration and development activity will not occur.

During the year ended December 31, 2012, we reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification is comprised of a $7,000,000 decrease in the carrying value of our Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012. During 2011, we reclassified $660,000 of acreage costs in Nevada into proved property as we relinquished our control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects.

Lower oil and natural gas prices have historically and may continue to negatively impact our ability to produce economically.

Lower natural gas and oil prices have resulted in significant decreases in our revenue, and have adversely affected the amount of oil and natural gas that we can produce economically. A reduction in production has resulted in a shortfall in our expected cash flows and caused us to significantly reduce our capital spending.  Additional financing may not be available on acceptable terms or at all. This reduction has also resulted in our having to make substantial downward adjustments to our estimated proved reserves. The price per barrel of oil reflects our blend of oil and condensate. If the prices for oil and gas decrease materially from year end 2012 prices, we will be unable to economically develop most of our acreage. Any of these factors could negatively impact our ability to replace our production and our ability to continue as a going concern.

Oil and natural gas prices are volatile. The extended decline in commodity prices has adversely affected, and in the future will continue to adversely affect, our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.

Our financial condition, operating results, and future rate of growth depend primarily upon the prices that we receive for our oil and natural gas. Prices also affect our cash flow available for capital expenditures and are likely to affect our ability to access the credit and capital markets. Natural gas and oil prices are set by broad market forces, which historically have been and are likely to remain volatile in the future. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

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·changes in the global supply and demand for natural gas and oil;

·commodity processing, gathering and transportation availability;

·domestic and global political and economic conditions;

·the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

·weather conditions, including hurricanes;

·technological advances affecting energy consumption;

·an increase in alternative fuel sources;

·higher fuel taxes and other regulatory actions;

·an increase in fuel economy;

·additional domestic and foreign governmental regulations; and

·the price and availability of alternative fuels.

Our success is influenced by natural gas prices in the specific area where we operate, and these prices may be lower than prices at major markets.

Regional natural gas prices may move independent of broad industry price trends.  Because some of our operations are located outside major markets, we are directly impacted by regional natural gas prices regardless of major market pricing. All of our natural gas production is currently located in, and all of our future natural gas production is anticipated to be located in, the Rocky Mountain Region of the United States.  The gas prices that we and other operators in the Rocky Mountain region have received and are receiving are at a discount to gas prices in other parts of the country.

Additional factors that can cause price volatility for crude oil and natural gas within this region are:

·the availability of gathering systems with sufficient capacity to handle local production;

·seasonal fluctuations in local demand for production;

·local and national gas storage capacity;

·interstate pipeline capacity; and

·the availability and cost of gas transportation facilities from the Rocky Mountain region.

It is impossible to predict natural gas and oil price movements with certainty. A substantial or extended decline in natural gas and oil prices would materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance capital expenditures.

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The enactment of derivatives legislation and regulation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate fluctuations and other risks associated with our business.

To mitigate the impact of lower commodity prices on our cash flows, we sometimes enter into commodity derivative instruments, however we do not currently have any derivative instruments.  See Note 6 — Derivatives of the accompanying consolidated financial statements for further discussion.

On July 21, 2010  new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Colombia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap”, “security-based swap”, “swap dealer” and “major swap participant”.  The Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements).  In addition new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time.  Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized.  As a result it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us and the timing of such effects. The Act may also require the counterparties to any future derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.  The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, and increase our exposure to less creditworthy counterparties. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.  Our revenues could therefore be adversely affected if a consequence of Act is to lower commodity prices.  Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

We have entered into a significant joint venture. This joint venture restricts our operational and corporate flexibility; actions taken by our joint venture partner may materially impact our financial position and results of operation; and we may not realize the benefits we expect to realize from this joint venture.

On March 22, 2012, we closed the Uinta Basin Transaction with Wapiti, and in connection with such closing, we (i) sold to Wapiti an undivided 50% of our 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 payable by Wapiti, which was repaid in full during the second quarter of 2012, and (ii) transferred to Wapiti an undivided 50% of our interest in certain of 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.

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In addition, as part of the Uinta Basin Transaction, Gasco Production Company entered the Development Agreement with Wapiti, which includes terms and conditions of a drilling program to develop the subject properties.  The following aspects of this joint venture could materially impact Gasco:

·The development of these properties is subject to the terms and conditions of the Development Agreement with Wapiti, and we no longer have the flexibility to control the development of these properties.  For example, the Development Agreement sets forth required capital expenditure programs that each party must participate in unless the parties mutually agree to change such programs. If we are not able to pay our share of the costs, we may lose certain rights granted under the Development Agreement and related operating agreements, including the right to continue as operator or contract operator of the properties, the right to make proposals or elect to participate in operations under the Development Agreement or any operating agreement, the right to call, attend and vote at meetings of the operating committee, the right to transfer our interest in the properties and the joint venture, the right to acquire Wapiti’s interest in the properties under the right of first offer provisions of the Development Agreement and the right to acquire its pro rata share of additional properties acquired by Wapiti within the area of mutual interest identified in the Development Agreement.  If we do not timely meet our financial commitments under the Development Agreement, our rights to participate in the joint venture will be adversely affected.  In addition, each joint venture party has the right to elect to participate in acreage acquisitions in certain a defined area of mutual interest.

·The Development Agreement assigns to each party designated areas over which that party will manage and control operations. We could incur liability as a result of action taken by our joint venture partner.

·In exchange for an undivided 50% of our interest in our Uinta Basin non-producing oil and gas assets, Wapiti has made a commitment to fund $30.0 million of the drilling and completion costs associated with the exploration and development of the subject assets, including the payment of $15 million of costs to be paid on our behalf.  Thus, the benefits we anticipate receiving in the joint venture depends in part upon the rate at which new wells are drilled and developed in the joint venture, which could fluctuate significantly from period to period.  Moreover, the performance of these third party obligations is outside of our control.  The inability or failure of Wapiti to pay its funding commitment, including costs to be paid on our behalf during the drilling term, could increase our costs of operations or result in reduced drilling and production of oil and gas or loss of rights to develop the oil and gas properties held by the joint venture.

·The Development Agreement prohibits any transfer of our interests in the joint venture assets, prior to the end of the drilling term, unless Wapiti consents in its sole discretion.  These restrictions may preclude transactions that could be beneficial to our shareholders.

·Disputes between us and our joint venture partner may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.

A failure by our gathering, transportation or processing facilities to perform its obligations under our natural gas gathering, transportation and processing agreements may negatively affect our ability to deliver our natural gas production for sale.

Pursuant to the Amended and Restated Monarch Agreement, a gas gathering agreement, we rely on Monarch to gather and deliver our natural gas production from wellheads to points of sale. Additionally, pursuant to the gas gathering agreement, Monarch is required to connect to the gathering system future

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wells that we drill within an area of mutual interest established thereunder. Pursuant to the QPC Transportation Agreement, we rely on QPC to transport our natural gas production, and pursuant to the Chipeta Processing Agreement, we rely on Chipeta to process our natural gas production.  Any failure by Monarch, QPC or Chipeta, or any successor thereto to timely perform its obligations under the applicable agreements may limit our ability to deliver production into the interstate pipeline where it is sold.  A delay or reduction in the amount of natural gas that we sell as a result of a failure by Monarch, QPC or Chipeta to timely perform their obligations could have a material adverse effect on our business, financial condition or results of operations.

During the year ended December 31, 2012, the Amended and Restated Monarch Agreement covered the gathering, processing, compressing and delivery of our gross production of natural gas from all of our Utah acreage from wellheads to points of sale. Our agreement with Monarch was modified upon the commencement of the Chipeta Processing Agreement. Since the beginning of the primary term of the Chipeta Processing Agreement, Chipeta has provided all of our natural gas processing services, and Monarch has not processed any of our natural gas.  Monarch and QPC continue to gather and transport our natural gas. Please read “2012 and Recent Highlights—Gas Processing Agreements” in “Item 1.—Business.”

Our ability to market the oil and natural gas that we produce is essential to our business. Pipeline constraints may limit our ability to sell production and may negatively affect the price at which we sell our production, which could have an adverse impact on our results of operations and financial condition.

Several factors beyond our control may adversely affect our ability to market the oil and gas that we discover.  These factors include the proximity, capacity and availability of oil and gas pipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection.  The extent of these factors cannot be accurately predicted, but any one or a combination of these factors may result in our inability to sell our oil and gas at prices that would result in an adequate return on our invested capital.

We currently distribute the natural gas that we produce through a single interstate pipeline. Any constraints on the capacity of this pipeline could adversely affect our ability to sell production and, in certain circumstances, may limit our ability to sell any or all of our production in a given period. If this pipeline were to become unavailable, we would incur additional costs to secure a substitute facility in order to deliver the gas that we produce. In addition, although we currently have access to firm transportation for the majority of our current gas production, there is no assurance that we will be able to procure additional transportation on terms satisfactory to us, or at all, if we increase our production through our drilling program or acquisitions.

Because we do not own or operate any natural gas lines or distribution facilities, we rely on third parties to construct additional interstate pipelines to increase our ability to bring our production to market.  Any significant change affecting these facilities or our failure to obtain timely access to existing or future facilities on acceptable terms could restrict our ability to conduct normal operations.  Delays in the commencement of operations of new pipelines, the unavailability of the new pipelines or other facilities due to market conditions, mechanical reasons or otherwise could have an adverse impact on our results of operations and financial condition. Pipeline capacity constraint could also lead to heightened price competition on such pipeline, which would reduce the price at which we are able to sell the production that does flow. A reduction in the amount of natural gas that we can sell or the price at which such natural gas can be sold could have a material adverse effect on our business, financial condition or results of operations.

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Further, interstate transportation and distribution of natural gas is regulated by the federal government through the Federal Energy Regulatory Commission (“FERC”). FERC sets rules and carries out administratively the oversight of interstate markets for natural gas and other energy policy.  Additionally, state regulators have powers over sale, supply and delivery of natural gas and oil within their state borders.  While we do employ certain companies to represent our interests before state regulatory agencies, our interests may not receive favorable rulings from any state agency, or some future occurrence may drastically alter our ability to enter into contracts or deliver natural gas to the market.

Approximately 6% of our proved reserves are classified as proved developed non-producing and may ultimately prove to be less than estimated.

At December 31, 2012, approximately 6% of our total proved reserves were classified as proved developed non-producing.  It will take substantial capital to recomplete or drill our non-producing reserves.  Our estimate of proved reserves at December 31, 2012 assumes that we will spend an estimated $0.9 million in future development costs in 2013 to develop these reserves.  As described previously, there is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013. These factors raise substantial doubt about our ability to continue as a going concern.  Our drilling plans will be adjusted or completely terminated if we do not have adequate cash flow to fund these projects. For example, we have not allocated any amounts to the 2013 capital budget. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.

Our proved reserves are estimates and depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates that may turn out to be inaccurate. Any material inaccuracies in these in these reserve estimates or underlying assumptions could cause the quantity and value of our oil and gas reserves, and our revenue, profitability, and cash flow, to be materially different from our estimates.

Estimating accumulations of natural gas and oil is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering, production and other technical data the extent, quality and reliability of which can vary.  The process also requires certain economic assumptions, some of which are mandated by the SEC. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves.

There are many uncertainties inherent in estimating natural gas and oil reserves and their values, many of which are beyond our control.  Estimates of economically recoverable natural gas or oil reserves and of future net cash flows necessarily depend on many variables and assumptions, such as:

·historical natural gas or oil production from that area, compared with production from other producing areas;

·assumptions concerning the effects of regulations by governmental agencies;

·assumptions concerning future prices;

·assumptions concerning future operating costs;

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·assumptions concerning severance and excise taxes; and

·assumptions concerning development costs and workover and remedial costs.

Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from our estimates.  Any significant variance could materially affect the quantities and present value of our reserves.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development and prevailing gas and oil prices.  Our reserves may also be susceptible to drainage by operators on adjacent properties.

For these reasons, estimates of the economically recoverable quantities of natural gas or oil attributable to any particular group of properties, classifications of those reserves based on risk recovery and estimates of the future net cash flows expected from them prepared by different engineers, or by the same engineer at different times may vary substantially.  Because of this, our reserve estimates may materially change at any time.

The most accurate method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data.  The accuracy of the decline analysis method generally increases with the length of the production history.  Since most of our wells had been producing for less than ten years as of December 31, 2012, their production history is relatively short, so other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir were used in conjunction with the decline analysis method to determine our estimates of proved reserves as of December 31, 2012.  As our properties are produced over time and more data is available, the estimated proved reserves will be redetermined on an annual basis and may be adjusted based on that data. These adjustments could result in downward revisions of our reserve estimates.

It should not be assumed that the present value of future net cash flows included herein is the current market value of our estimated proved oil and gas reserves.  In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on the unweighted arithmetic average of the first-day-of-the-month commodity prices for the trailing twelve months and development and production costs on the date of estimate.  Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. This price and rate are not necessarily the most appropriate price or discount factor based on prices and interest rates in effect from time to time and risks associated with our reserves or the natural gas and oil industry in general. Current or actual future prices and costs may be materially higher or lower.  Actual future net cash flows also will be affected by factors such as:

·the amount and timing of actual production;

·supply and demand for natural gas or oil;

·actual prices received for natural gas in the future being different than those used in the estimate;

·curtailments or increases in consumption of natural gas or oil;

·changes in governmental regulations or taxation; and

·the timing of both production and expenses in connection with the development and production of natural gas or oil properties.

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The exploration and development of oil and natural gas properties involves substantial risks that may materially and adversely affect us.

Our future success will largely depend on the success of our exploration drilling program. The business of exploring for and producing oil and natural gas involves a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome.  Drilling oil and gas wells involves the risk that the wells will be unproductive or that, although productive, the wells do not produce oil and/or gas in economic quantities.  The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including, but not limited to:

·unexpected drilling conditions;

·blowouts, fires or explosions with resultant injury, death or environmental damage;

·pressure or irregularities in formations;

·equipment failures or accidents;

·adverse weather conditions;

·compliance with governmental requirements and laws, present and future; and

·shortages or delays in the availability of drilling rigs or water for hydraulic fracturing and the delivery of equipment.

A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well.  In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.  Furthermore, our operations are conducted in the Rocky Mountain region of the United States. The weather in this area can be extreme and can cause interruption in our exploration and production operations. Severe weather can result in damage to our facilities entailing longer operational interruptions and significant capital investment. Additionally, our operations are subject to disruption from winter storms and severe cold, which can limit operations involving fluids and impair access to our facilities.

If we experience any one or more of these risks, our business, financial condition and results of operations could be materially and adversely affected.

Natural gas and oil reserves are depleting assets, and the failure to replace our reserves would adversely affect our production and cash flows.

Our future natural gas and oil production depends on our success in finding or acquiring new reserves.  If we fail to replace reserves, our level of production and cash flows would be adversely impacted.  Production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics.  Our total proved reserves will decline as reserves are produced unless we conduct successful exploration and development activities and/or acquire properties containing proved reserves.  Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves has recently been impaired because of a decline in cash flow from operations and external sources of capital are currently limited or unavailable.  Further, we may not be

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successful in exploring for, developing or acquiring additional reserves, which could have a material adverse effect on our financial condition, future cash flows and results of operations.

Delays in obtaining drilling permits could have a material adverse effect on our ability to develop our properties in a timely manner.

The average processing time at the BLM in Vernal, Utah for an application to drill on federal leases has been increasing and currently is approximately 24 months or longer. Approximately 80% of our gross acreage in Utah is located on federal leases. If we are delayed in procuring sufficient drilling permits for our federal properties, we may shift more of our drilling in Utah to our state leases, the permits for which require an average processing time of approximately 60 days. While such a shift in resources would not necessarily affect the rate of growth of our cash flow, it would result in a slower growth rate of our total proved reserves, because a higher percentage of the wells drilled on the state leases would be drilled on leases to which proved undeveloped reserves may already have been attributed.  Additionally, if the development of our acreage located on federal lands is delayed significantly by the permitting process, we may have to operate at a loss for an extended period of time. Such delays could result in impairments of the carrying value of our unproved properties and could impact the ceiling test calculation.

We may have difficulty managing any growth in our business.

Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources.  If we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources.  The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Technological changes could affect our operations.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement such new technologies at substantial costs, some of which we may be unable to bear due to our current liquidity position. In addition, many other natural gas and oil companies have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may be unable to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. If one or more of the technologies that we currently use or may implement in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, it could have a material adverse effect on our financial condition, future cash flows and results of operations.

Competition in the natural gas and oil industry is intense.Our competitors may have greater resources which could enable them to pay a higher price for properties and to better withstand periods of low market prices for hydrocarbons.

The petroleum and natural gas industry is intensely competitive, and we compete with other companies with greater resources.  This disparity is currently exacerbated due to our current liquidity position.  Many of these companies not only explore for and produce petroleum and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis.  Many of

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our competitors are large, well-established companies that have a substantially larger operating staff and greater capital resources than we do and, in many instances, have been engaged in the natural gas and oil business for a much longer time than we have.  These companies may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase more properties and prospects than our financial and human resources permit.  As a result, we may have difficulty acquiring additional acreage and/or projects, and may have difficulty arranging for the transportation of the oil or natural gas we produce when compared with our larger and better capitalized competitors. We also face competition in obtaining natural gas and oil drilling rigs and in providing the manpower to operate them, as well as providing related services. Our competitors may be able to spend more on the existing and changing technologies that we believe are and will be increasingly important to the current and future success of natural gas and oil companies. In addition, such companies may have a greater ability to continue exploration activities during periods of low hydrocarbon market prices.  Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Increased competitive pressure could have a material adverse effect on our financial condition, future cash flows and results of operations.

Acquisition prospects are difficult to assess and may pose additional risks to our operations.

Where appropriate, we may evaluate and pursue acquisition opportunities on terms our management considers favorable.  The successful acquisition of natural gas and oil properties requires an assessment of:

·recoverable reserves;

·exploration potential;

·future natural gas and oil prices;

·operating costs;

·potential environmental and other liabilities; and

·permitting and other environmental authorizations required for our operations.

In connection with such an assessment, we would expect to perform a review of the subject properties that we believe is generally consistent with industry practices.  Nonetheless, the resulting conclusions are inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies.  Inspections may not always be performed on every facility or well, and structural and environmental liabilities, such as, for example, subsurface ground water contamination, are not necessarily observable even when an inspection is undertaken.  Future acquisitions could pose additional risks to our operations and financial results, including:

·problems integrating the purchased operations, personnel or technologies;

·unanticipated costs;

·diversion of resources and management attention from our exploration business;

·entry into regions or markets in which we have limited or no prior experience; and

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·potential loss of key employees, particularly those of the acquired organization.

We may suffer losses or incur liability for events that we have, or that the operator of a property has, chosen not to insure against.

The natural gas and oil business involves many operating hazards, such as:

·well blowouts, fires and explosions;

·surface craterings and casing collapses;

·uncontrollable flows of natural gas, oil or well fluids;

·pipe and cement failures;

·formations with abnormal pressures;

·stuck drilling and service tools;

·pipeline and tank ruptures or spills;

·natural disasters; and

·releases of toxic natural gas.

Any of these events could cause substantial losses to us as a result of:

·injury or death;

·damage to and destruction of property, natural resources and equipment;

·pollution and other environmental damage;

·      regulatory investigations and penalties;

·suspension of operations; and

·repair and remediation costs.

Insurance against every operational risk is not available at economic rates. We may suffer losses from hazards that we cannot insure against or that we have, or the operator thereof has, chosen not to insure against because of high premium costs or other reasons.  We could also be responsible for environmental damage caused by previous owners of property from whom we purchased leases.  As a result, we may incur substantial liabilities to third parties or governmental entities. If these liabilities are not covered by our insurance, paying them could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties. The payment of any such liabilities may have a material adverse effect on our business, financial condition and results of operations.

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We may incur losses as a result of title deficiencies in the properties in which we invest.

If an examination of the title history of a property that we have purchased reveals a petroleum and natural gas lease that has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless.  In such an instance, the amount paid for such petroleum and natural gas lease or leases would be lost.

It is our practice in acquiring petroleum and natural gas leases or undivided interests in petroleum and natural gas leases not to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease.  Rather, we will rely upon the judgment of petroleum and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

If there are any title defects in the properties in which we hold an interest, we may not be able to proceed with our exploration and development of the lease site or may suffer a monetary loss, including as a result of performing any necessary curative work prior to the drilling of a petroleum and natural gas well.

Our operations could be adversely impacted by security breaches, including cyber-security breaches, which could affect our production of oil and natural gas or could affect other parts of our business.

We face security exposure, including cyber-security exposure, from unauthorized access to our facilities and computer systems.  This exposure includes unauthorized access to sensitive information; malicious damage to our facilities, infrastructure, and computer systems; malicious damage to third-party facilities, infrastructure, and computer systems; safety exposure for our employees and contractors; and disruptions of our operations.  Although we utilize various procedures and controls to mitigate these exposures, there can be no assurances that these procedures and controls will be sufficient to prevent such events from occurring.  Cyber-security exposures in particular are evolving and include malicious software, unauthorized access to confidential data and disruptions to operations that use computers and data systems.  We do not carry business interruption insurance.  Any of these security breaches could have a material adverse affect on our consolidated financial position, results of operations and cash flows.

Because our reserves and production are concentrated in a small number of properties in one primary geographic location, production problems or significant changes in reserve estimates related to any property could have a material impact on our business.

Our reserves and production primarily come from a small number of producing properties in Utah.  If mechanical problems with the wells or production facilities (including salt water disposal, pipelines, compressors and processing plants), depletion, weather or other events adversely affect any particular property, we could experience a significant decline in our production, which could have a material adverse effect on our cash flows, financial condition and results of operations. In addition, if the actual reserves associated with any one of our properties are less than estimated, our overall reserve estimates could be materially and adversely affected.

Shortages of supplies, equipment and personnel may adversely affect our operations.

The natural gas and oil industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies may be substantially increased and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases.  We do not have a drilling rig under contract at this time.  If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our

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ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our business, financial condition and results of operations could be materially and adversely affected.

Our success depends on our key management personnel, the loss of any of whom could disrupt our business.

The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management.  The loss of services of any of our key managers — including Mr. Grant, our President and Chief Executive Officer, Mr. Decker, our Executive Vice President and Chief Operating Officer and Ms. Herald, our Vice President and Chief Accounting Officer—could have a material adverse effect on our business, financial condition and results of operations.  We have not obtained “key man” insurance for any of our management.

Our directors are engaged in other businesses which may result in conflicts of interest.

Certain of our directors also serve as directors of other companies or have significant shareholdings in other companies operating in the oil and gas industry. Our Chairman, Charles Crowell, also serves on the Board of Directors of Derek Oil & Gas Corporation. King Grant, our President, Chief Executive Officer and director is a member of the Board of Directors of Battalion Energy. Richard S. Langdon, another one of our directors, is President and Chief Executive Officer of KMD Operating Company LLC, a private exploration and production company active in onshore California. Mr. Langdon is also the President and Chief Executive Officer of Sigma Energy Ventures with E&P activities in the Texas Gulf Coast. Further, Mr. Langdon is a member of the Board of Directors of Constellation Energy Partners LLC (“CEP”), a public limited liability company focused on the acquisition, development and exploitation of oil and natural gas properties and related midstream assets. CEP’s activities are currently focused in the Black Warrior Basin of Alabama and in the Cherokee Basin in Oklahoma and Kansas. Another of our directors, Richard Burgess, serves on the Board of Michigan Oil and Gas Association and Potential Gas Committee. We estimate that all of our outside directors spend up to 10% of their time on our business.

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

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

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These proposed changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain domestic production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or

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similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase our taxable income and negatively impact the value of an investment in us.

We are subject to complex governmental laws and regulations which may expose us to significant costs and liabilities and adversely affect the cost, manner or feasibility of conducting our business.

Our petroleum and natural gas exploration and production interest and operations are subject to stringent and complex federal, state and local laws and regulations relating to the operation and maintenance of our facilities, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment and otherwise relating to environmental protection.  Oil and natural gas operations are also subject to federal, state, provincial and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. We may be required to make large expenditures to comply with these regulatory requirements.  Legislation affecting the petroleum and natural gas industry is under constant review for amendment and expansion.  Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the petroleum and natural gas industry, some of which carry substantial penalties for failure to comply.  Any increases in the regulatory burden on the petroleum and natural gas industry created by new legislation would increase our cost of doing business and adversely affect our profitability.

Failure to comply with these laws and regulations applicable to our interests and operations could result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders enjoining or limiting some or all of our operations, any of which could have a material adverse effect on our financial condition.  Legal requirements are sometimes unclear or subject to reinterpretation and may be frequently changed in response to economic or political conditions.  As a result, it is hard to predict the ultimate cost of compliance with these requirements or their effect on our interests and operations.  In addition, existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations may have a material adverse effect on our financial condition, future cash flows and results of operations.

Climate change legislation and regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In December 2009, the EPA determined that emissions of GHG present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has adopted regulations under existing provisions of the CAA that establish PSD and Title V permit reviews for GHG emissions from certain large stationary sources.  Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis.  The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which includes certain of our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.  In the absence of such federal climate legislation, a number of state and regional efforts,

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including a GHG cap-and-trade program adopted by California, have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.  If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products.  Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an essential and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations such as shales.  We expect to use hydraulic fracturing techniques in many of our future natural-gas drilling programs.  The process involves the injection of water, proppants, and additives under pressure into a targeted subsurface formation.  The water and pressure create fractures in the rock formations, which are held open by the proppants, such as sand, enabling the oil or natural gas to flow to the wellbore.  The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority under the SDWA over hydraulic fracturing activities involving diesel fuel published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels.  In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations.  In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.  Some states have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities.  Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.  If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.  The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014.  Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies,

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depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

Our operations are subject to environmental and occupational health and safety laws and regulations that may expose us to significant costs and liabilities.

Our oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing occupational health and safety aspects of our operations, the discharge of materials into the environment, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting drilling or other regulated activities; restriction of types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; application of specific health and safety criteria addressing worker protection; and imposition of substantial liabilities for pollution resulting from our operations.  Numerous governmental authorities, such as the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations and due to historical industry operations and waste disposal practices.  Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken.  Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages.  In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our business, financial condition or results of operations.  Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, or waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance. Please read “Governmental Regulations and Environmental Laws” in “Item 1.—Business.”

Current and future economic conditions in the United States and key international markets may materially adversely impact our operating results.

Our operations are affected by local, national and international economic conditions and the condition of the natural gas and oil industry.  The United States and other world economies are slowly recovering from a recession, which began in 2008.  Although growth has resumed, it is modest and certain economic data indicates the United States and worldwide economies may require some time to recover.  There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years.  In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved.  Global economic growth

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drives demand for energy from all sources, including fossil fuels.  A lower future economic growth rate will result in decreased demand growth for our natural gas production and oil, as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

Market deterioration could also jeopardize the performance of certain counterparty obligations, including those of our insurers and customers.  Although we assess the creditworthiness of our counterparties, prolonged business decline or disruptions as a result of economic slow down or lower commodity prices could lead to changes in a counterparty’s liquidity and increase our exposure to credit risk and bad debts.  In the event any such party fails to perform, our financial results could be adversely affected and we could incur losses and our liquidity could be negatively impacted.

Risks Related to Our Capital Stock

Our common stock has experienced, and may continue to experience, price volatility and low trading volume.

The trading price of our common stock has been and may continue to be subject to large fluctuations and has traded at a low price per share for a substantial period of time, which may result in losses to investors.  In addition, on December 6, 2012, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange as a result of the low price per share.  The Exchange predicates our continued listing on the Exchange on us effecting a reverse stock split of our common stock by June 6, 2013. We also received a notice from the Exchange on January 11, 2013 indicating that we do not satisfy the continued listing standards in connection with sustained losses or impaired financial condition. Please read “Item 1.—Business—2012 and Recent Highlights— NYSE MKT LLC Communications” above for more information.

Our stock price may increase or decrease in response to a number of events and factors, including:

·the results of our exploratory drilling;

·trends in our industry and the markets in which we operate;

·our ability to remain in compliance with our operational agreements, including our gas processing, gathering and transportation agreements;

·changes in the market price of the commodities we sell;

·changes in financial estimates and recommendations by securities analysts;

·acquisitions and financings;

·quarterly variations in operating results;

·the operating and stock price performance of other companies that investors may deem comparable to us;

·an inability to regain and maintain compliance with the listing requirements of the Exchange; and

·issuances, purchases or sales of blocks of our common stock.

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This volatility may adversely affect the price of our common stock regardless of our operating performance. See “Item 5.—Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for further discussion.

A substantial number of shares of our common stock will be eligible for future sale upon conversion of the 2015 Notes (or shares of preferred stock issuable upon conversion of the 2015 Notes), and the sale of those shares could adversely affect our stock price. Our stockholders will experience substantial dilution if the 2015 Notes are converted.

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 shares of preferred stock, which are convertible into common stock. Pursuant to the terms of the Exchange Agreements entered into in connection with the issuance of the 2015 Notes (or shares of preferred stock issuable upon conversion of the 2015 Notes) we listed an additional 21,433,135 shares of common stock on the Exchange. The initial conversion price for converting the 2015 Notes into common stock is equal to $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into preferred stock (with certain exceptions), is equal to $100, which is equal to a conversion rate of ten shares of preferred stock per $1,000 principal amount of 2015 Notes.

Specifically, the 2015 Notes and preferred stock entitle the holders thereof to voluntarily convert such securities at any time into an aggregate principal amount of approximately 107.1 million shares of common stock.  In September 2010, 30% of the 2015 Notes were automatically converted into an aggregate amount of 305,754 shares of preferred stock, which were convertible into an aggregate of approximately 51.0 million shares of common stock. As of December 31, 2012, we have 182,065 shares of preferred stock outstanding which are convertible into approximately 30.3 million shares of common stock. Any shares of common stock issued upon conversion of the 2015 Notes or preferred stock will result in significant dilution to our existing stockholders.

Additionally, all of the shares of common stock issued upon conversion of the 2015 Notes and preferred stock are immediately eligible for resale in the public markets under Rule 144 of the Securities Act. If a significant portion of these shares were to be offered for sale at any given time, the public market for our common stock and the value of our common stock owned by our stockholders could be adversely affected. Any such sales, or the anticipation of the possibility of such sales, could depress the market price of our common stock.

If our outstanding warrants are exercised, our stock price could be adversely affected and our stockholders may experience substantial dilution.

In 2011, we issued warrants (“Warrants”) to purchase up to an aggregate of 30,250,000 shares of common stock are exercisable, at the option of the holder, subject to the terms of Warrants. 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 we make a distribution of our assets to all of our stockholders, holders of the Warrants may be entitled to participate. All of the shares of common stock issued upon exercise of the Warrants are immediately eligible for resale in the public markets. Any such sales, or the anticipation of the possibility of such sales, could depress the market price of our common stock. Additionally, upon issuance shares of common stock upon exercise of the Warrants, if any, our existing stockholders may incur significant dilution of their interests.

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Shares eligible for future sale may cause the market price for our common stock to drop significantly, even if our business is doing well.

If our existing shareholders sell our common stock in the market, or if there is a perception that significant sales may occur, the market price of our common stock could drop significantly.  In such case, our ability to raise additional capital in the financial markets at a time and price favorable to us might be impaired.  In addition, our board of directors has the authority to issue additional shares of our authorized but unissued common and preferred stock without the approval of our shareholders, subject to certain limitations under the rules of the Exchange.  Additional issuances of our common stock would dilute the ownership percentage of existing shareholders and may dilute the earnings per share of our common stock.  As of December 31, 2012, we had 169,749,981 shares of common stock issued and outstanding, 9,506,943 outstanding options to purchase common stock, 336,000 outstanding shares of unvested restricted stock and outstanding Warrants to purchase 30,250,000 shares of common stock.  An additional 11,466,640 shares of common stock are issuable under our long term incentive plan.

Assuming all of our outstanding Warrants, preferred stock, and 2015 Notes are converted at the applicable conversion prices, the number of shares of our common stock outstanding would increase by approximately 135,874,173 shares to approximately 305,624,154 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).

We have not previously paid dividends on our common stock and we do not anticipate doing so in the foreseeable future.

We have not in the past paid, and do not anticipate paying in the foreseeable future, cash dividends on our common stock. Our Indenture contains covenants that restrict our ability to pay dividends on our common stock. Additionally, any future decision to pay a dividend and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.

We have anti-takeover provisions in our articles of incorporation and by-laws that may discourage a change of control.

Our articles of incorporation and bylaws contain several provisions that could delay or make more difficult the acquisition of us through a hostile tender offer, open market purchases, proxy contest, merger or other takeover attempt that a stockholder might consider in his or her best interest, including those attempts that might result in a premium over the market price of our common stock.

Under the terms of our articles of incorporation and as permitted under Nevada law, we have elected not to be subject to Nevada’s anti-takeover law.  This law provides that specified persons who, together with affiliates and associates, own, or within three years did own, 15% or more of the outstanding voting stock of a corporation cannot engage in specified business combinations with the corporation for a period of three years after the date on which the person became an interested stockholder.  With the approval of our stockholders, we may amend our articles of incorporation in the future to become subject to the anti-takeover law.  This provision would then have an anti-takeover effect for transactions not approved in advance by our board of directors, including discouraging takeover attempts that a stockholder might consider in his or her best interest or that might result in a premium over the market price for the shares of our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2 - PROPERTIES

Petroleum and Natural Gas Properties

Riverbend Project

The Riverbend Project comprises approximately 114,569 gross acres in the Uinta Basin of northeastern Utah, of which we held interests in approximately 41,077 net acres as of December 31, 2012. Historically, our engineering and geologic focus has been concentrated on natural gas and condensate charged formations in the Uinta Basin: the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.  A typical well drilled into these formations may encounter multiple distinct natural gas sands, silts and shales located between approximately 6,000 and 15,000 feet in depth that are completed using up to twelve staged recompletions. As of December 31, 2012, we held an interest in 133 gross (40 net to our interest) producing wells and three gross (one net) shut-in wells located on these properties.  For additional information on the operations and recent developments in connection with the Riverbend Project, please see “Item 1.—Business—2012 and Recent Highlights—Green River Oil Wells” above for more information.

Working Interest Acquisition

During December 2012, we acquired additional working interests in 32 producing wells, in the Riverbend area of Utah, in which we have a working interest and operate, for $177,620. The acquired interests range from 4% to 10% per well with an average of 8% per well and represent an estimated increase to our current reserves of approximately 596,000 Mcfe.

Southern California Project

As of December 31, 2012, we had a leasehold interest in approximately 41,716 gross (16,873 net) acres in Kern County in Southern California.  For additional information on the operations and recent developments in connection with the Willow Springs, Antelope Valley and Northwest McKittrick, please see “Item 1—Business—2012 and Recent Highlights—California Projects” above for more information.

Capital Expenditure Budget

It is unclear whether we will have sufficient resources to fund a capital expenditure budget for 2013 and whether we will be able to continue as a going concern. We have not allocated any amounts to the 2013 capital budget. Due to the significant extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated.  There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013.  This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of our cash management strategy discussed elsewhere herein, some or all of which may not prove to be correct and may result in our inability to meet cash requirements prior to the second quarter of 2013.  See “Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

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Oil and Natural Gas Reserves

Our estimated proved reserves and related future net revenues, PV-10 and standardized measure of discounted future net cash flows at December 31, 2012 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2012 through December 2012, and were held constant throughout the life of the properties.  These prices, weighted by production over the lives of the proved reserves were $80.25 per Bbl for oil and oil equivalents and $2.15 per Mcf for natural gas.

For more information on our reserves, please read “Production and Reserve Information” in “Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

Company Reserve Estimates

Our proved reserve information as of December 31, 2012 included in this Annual Report was estimated by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. A copy of NSAI’s summary reserve report is included as Exhibit 99.1 to this Annual Report. See Note 21 — Supplemental Oil and Gas Reserve Information (Unaudited) to the accompanying consolidated financial statements for further discussion. In accordance with SEC guidelines, NSAI’s estimates of future net revenues from our properties, and the pre-tax present value of discounted future net cash flows (“PV-10”) and standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period January 2012 through December 2012, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.

The tables below set forth information as of December 31, 2012 with respect to our estimated proved reserves, the associated present value of discounted future net cash flows and the standardized measure of discounted future net cash flows. Neither the PV-10 nor the standardized measure is intended to represent the current market value of the estimated oil and natural gas reserves we own. All of our proved undeveloped reserves as of December 31, 2012 became uneconomic at these prices and as a result were not included in the December 31, 2012 reserve estimates. Our estimate of proved reserves at December 31, 2012 assumes that we will spend an estimated $0.9 million in future development costs in 2013 to develop these reserves. For more information see “Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—2013 Capital Budget.”

All of our proved reserves are located within the state of Utah.

	Mcf of Gas	Bbls of Oil	Total Mcfe
Total Proved Developed Reserve Quantities:	12,603,717	251,599	14,113,311

	Proved Undeveloped		Proved Developed		Total
Present Value of Discounted Future Net Cash Flows (a):	$	0	$	10,317,600	$	10,317,600

(a)Present value of discounted future net cash flows represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the

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period January 2012 through December 2012 and were held constant throughout the life of the properties. The average prices weighted by production over the lives of the proved reserves used in the reserve report were $2.15 per Mcf of gas and $80.25 per Bbl of oil. All of our proved undeveloped reserves became uneconomic at these prices and as a result were not included in the December 31, 2012 reserve estimates. These prices should not be interpreted as a prediction of future prices.

Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Therefore, the PV-10 amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to our properties.

Non-GAAP Present Value Reconciliation

Management uses discounted future net cash flows, which are calculated without deducting estimated future income tax expenses, and the present value thereof as one measure of the value of our current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While future net revenue and present value are based on prices, costs and discount factors which are consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 is considered to be a non-GAAP financial measure; however as of December 31, 2012, the PV-10 and the standardized measure of discounted future net cash flows are equal because the effects of estimated future income tax expenses are zero.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

Our proved reserve information as of December 31, 2012 included in this Annual Report was estimated by our independent petroleum engineers, NSAI, in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers and definitions and guidelines established by the SEC.  NSAI was founded in 1961 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers Registration No. F-2699.

Our Executive Vice President and Chief Operating Officer, Michael K. Decker, is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for the coordination of the third-party reserve reports provided by NSAI. Mr. Decker has over 35 years of experience in the oil and gas industry ranging from exploration, development and operations to mergers and acquisitions.  He holds a BS degree in Geological Engineering from the Colorado School of Mines. Prior to joining us in 2001, Mr. Decker served as the Vice President of Exploitation of Prima Energy Corporation, a NASDAQ-traded oil and gas company.

Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI report are Mr. Craig H. Adams and Mr. William J. Knights.  Mr. Adams has been practicing consulting petroleum engineering at NSAI since 1997. Mr. Adams is a Licensed Professional Engineer in the State of Texas (License No. 68137) and has over 26 years of practical experience in petroleum engineering with over 21 years experience in the estimation and evaluation of oil and gas reserves.  He graduated from Texas Tech University in 1985 with a Bachelor of Science Degree in Petroleum Engineering.  Mr. Knights has been practicing consulting petroleum geology at NSAI since 1991. Mr. Knights is a Licensed Professional Geoscientist in the State of Texas, Geology (License No. 1532) and

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has over 32 years of practical experience in petroleum geosciences, with over 22 years experience in the estimation and evaluation of reserves.  He graduated from Texas Christian University in 1981 with a Bachelor of Science Degree in Geology and in 1984 with a Master of Science in Geology.  Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers, and both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The other technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

We also maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. In the fourth quarter, our technical team meets regularly with representatives of NSAI to review properties and discuss methods and assumptions used in NSAI’s preparation of the year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the NSAI reserve report is reviewed by our audit committee with representatives of NSAI and internal technical staff. Additionally, our senior management reviews and approves any internally estimated significant changes to our proved reserves on a quarterly basis.

Reserve Technologies

Proved reserves are those quantities of oil and natural 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. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available down well and production data, and well test data.

Reserve Sensitivities

The following table discloses information regarding the sensitivity of our estimated proved oil and gas reserves to price fluctuations.

Price Case	Oil (MBbls)	Gas (MMcf)	Oil and Gas Equivalent (MMcfe)	PV-10
SEC pricing (a)	251.6	12,604	14,113	$	10,317,600
Scenario 1 (b)	278.3	14,596	16,266	$	14,025,200
Scenario 2 (c)	217.2	9,762	11,066	$	7,006,200

(a)This case represents pricing under SEC rules under which the prices used are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period January

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2012 through December 2012. The oil and gas prices used in this scenario, weighted by production over the lives of the proved reserves are $80.25 per Bbl of oil and $2.15 per Mcf of gas.

(b)Scenario 1 estimates total proved reserves assuming a 10% price increase in both the oil and the gas price used in the SEC pricing scenario.

(c)Scenario 2 estimates total proved reserves assuming a 10% price decrease in both the oil and the gas price used in the SEC pricing scenario.

Volumes, Prices and Operating Expenses

The following table presents information regarding the production volumes, average sales prices received (excluding the impact of our hedges) and average production costs for the periods presented associated with our sales of natural gas and oil for the periods indicated.

	For the Years Ended December 31,
	2012		2011		2010
Natural gas production (Mcf)	2,406,512		3,659,790		4,105,139
Average sales price per Mcf	$	2.82	$	4.20	$	4.15
Oil production (Bbl)	25,805		36,852		40,532
Average sales price per Bbl	$	81.38	$	80.75	$	64.45
Equivalent production of oil and gas (Mcfe)	2,561,342		3,880,902		4,348,331
Selected Operating Expenses per Mcfe:
Lease operating	$	1.96	$	2.08	$	1.18
Production and property taxes	$	0.10	$	0.18	$	0.20
General and administrative	$	1.88	$	1.27	$	1.55
Depreciation, depletion and amortization	$	1.07	$	0.91	$	0.82
Impairment	$	6.44	$	—	$	—

Development, Exploration and Acquisition Capital Expenditures

The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities:

	For the Years Ended December 31,
	2012		2011		2010
Property acquisition costs:
Unproved	$	2,490,305	$	2,094,969	$	313,238
Proved	177,620		—		481,947
Exploration costs	2,599,168		3,864,866		968,683
Development costs	13,818		2,506,176		5,151,909
Total	$	5,280,911	$	8,466,011	$	6,915,777

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Productive Oil and Gas Wells

The following summarizes our producing and shut-in oil and gas wells as of December 31, 2012.

	Productive Oil and Gas Wells
	Gross	Net
Producing oil wells	17	8.4
Shut-in oil wells	1	0.5
Producing gas wells	116	31.6
Shut-in gas wells	2	0.5
Total wells	136	41.0

Oil and Natural Gas Acreage

Exploration and Productive Acreage

The following table sets forth our ownership interest in undeveloped and developed leasehold acreage, in the areas indicated as of December 31, 2012. The table does not include acreage that we have a contractual right to acquire or to earn through drilling projects, or any other acreage for which we have not yet received leasehold assignments. In certain leases, our ownership is not the same for all depths; therefore, the net acres in these leases are calculated using the greatest ownership interest at any depth. Generally this greater interest represents our ownership in the primary objective formation.

	Undeveloped Acres		Developed Acres
	Gross	Net	Gross	Net
Utah	109,369	38,677	5,200	2,400
California	41,716	16,873	—	—
Total acres	151,085	55,550	5,200	2,400

Undeveloped Acreage

The following table summarizes our ownership interest in the gross and net undeveloped acreage in the areas indicated that will expire in each of the next three years.

	Expiring in 2013		Expiring in 2014		Expiring in 2015
	Gross	Net	Gross	Net	Gross	Net
Utah	800	400	1,911	620	—	—
California	4,064	1,878	1,221	610	2,468	1,149
Total	4,864	2,278	3,132	1,230	2,468	1,149

Our acreage positions are maintained by the payment of delay rentals or by the existence of a producing well on the acreage. As of December 31, 2012, approximately 80% of the gross acreage that we hold is located on federal lands, approximately 17% of the acreage is located on state lands and 3% is located on land owned by individuals.  It has been our experience that the permitting process related to the

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development of acreage on federal lands is more time consuming and expensive than the permitting process related to acreage on state lands.  We have generally been able to obtain state permits within 60 days, while obtaining federal permits has taken approximately 24 months or longer.  If we are delayed in procuring sufficient drilling permits for our federal properties, we will shift more of our drilling in Utah to our state leases. While such a shift in resources would not necessarily affect the rate of growth of our cash flow, it would result in a slower growth rate of our total proved reserves, because a higher percentage of the wells drilled on the state leases will be drilled on leases to which proved undeveloped reserves may already have been attributed. Additionally, if the development of our acreage located on federal lands is delayed significantly by the permitting process, we may have to operate at a loss for an extended period of time. Such delays could result in impairments of the carrying value of our unproved properties and could impact the ceiling test calculation. During the year ended December 31, 2012, we reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification is comprised of a $7,000,000 decrease in the carrying value of our Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012. During 2011, we reclassified $660,000 of acreage costs in Nevada into proved property as we relinquished our control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects. After these impairments, the aggregate carrying value of our unproved acreage is approximately $31,486,314 as of December 31, 2012.

Drilling Activity

The following table sets forth our drilling activity during the years ended December 31, 2012, 2011 and 2010. As of December 31, 2011, we had two wells in progress and these wells were completed during January 2012.

	For the Years Ended December 31,
	2012		2011		2010
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells:
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total wells	—	—	—	—	—	—
Development Wells:
Productive	2	1	—	—	—	—
Dry	—	—	—	—	—	—
Total wells	2	1	—	—	—	—

Delivery Commitments

Pursuant to our Gas Processing Agreement with Chipeta, we dedicated certain of our natural gas production from our acreage in Utah to Chipeta for processing. We reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing and 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 primary term of the Chipeta Processing Agreement began upon the completion of the building of Chipeta’s facility on February 7, 2013.  Under this agreement, we are committed to deliver, on average, at least 90% of our contracted cryogenic capacity of 25,000 Mcf/d (the “Minimum Daily Quantity”) during each monthly accounting period.  Following the first twelve monthly accounting periods, Chipeta may determine whether we failed to deliver equal to or greater than the Minimum Daily Quantity multiplied by the number of days in the annual accounting period.  If we delivered less than the quantity we committed to deliver, we would be required to pay a deficiency payment equal to the

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contracted cryogenic processing fee multiplied by the deficient quantity. In addition, to the extent that Chipeta has reasonable grounds for uncertainty regarding the performance of our obligations under our gas processing agreement, including a material change in our creditworthiness, Chipeta may sell our natural gas and apply amounts received against any amounts we owe to Chipeta, set off any amount owed to us against amounts owed to Chipeta or cease processing our natural gas until our account is current, with interest.  Chipeta may also demand adequate assurance of performance from us, which may be in the form of a standby irrevocable letter of credit, prepayment or performance bond or guaranty.

Pursuant to the Amended and Restated Monarch Agreement, Monarch agreed, among other things, to release and waive its existing right to process the first 50,000 MMBtu/day of our gas delivered to Monarch’s gathering system, referred to as the Excluded Production, and 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, after three years from the beginning of primary term of the Chipeta Processing Agreement, which was February 7, 2013. More specifically, we are required to commit or cause to be committed $50 million for drilling and completing new wells by February 2016, or else the Excluded Production may be reduced by an amount up to 20,000 MMBtu/day. The Amended and Restated Monarch Agreement also provides that we are committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and we are obligated to pay for any shortfall following the end of each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the agreement.

In connection with the Amended and Restated Monarch Agreement, we also entered in to the QPC Transportation Agreement, pursuant to which we agreed to enter into separate transportation services agreements for firm transportation services. We are committed to deliver to QPC for transportation services a minimum of 25,000 MMbtu/day.

Since the beginning of the primary term of the Chipeta Gas Processing Agreement, Chipeta has provided all of our natural gas processing services, and we have not produced any amounts of natural gas in excess of the Excluded Production.  Monarch and QPC continue to gather and transport our natural gas.

There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations. The maximum undiscounted deficiency payments under the Chipeta Gas Processing Agreement, the Amended and Restated Monarch Agreement and the QPC Transportation Agreement, over the full terms of these contracts, are estimated to be approximately $59 million. Of this amount, approximately $40 million would be owed to Chipeta, $8.5 million would be owed to Monarch and $12.5 million would be owed to QPC. These amounts are owed regardless of whether we deliver any natural gas quantities to the applicable parties. If we are unable to fund additional drilling projects, and based on our December 31, 2012 reserve estimates, assuming no future drilling and constant gas prices, we estimate that we could have a reasonably possible minimum production shortfall of approximately 54,000 MMcf valued at approximately $37 million in aggregate deficiency payment obligations on an undiscounted gross basis.

We are considering several alternatives to mitigate the reasonably possible estimated production shortfall such as the sale of our firm commitment positions, seeking relief from the firm commitments because of the permitting delays in the area and the purchase of production quantities to meet our minimum production requirements. Also, future increases in gas prices would increase the related reserve estimates and reduce possible shortfalls. However, there is no assurance we will be successful in accomplishing these actions should there be a deficiency. Accordingly, we have not accrued any amounts as of December 31, 2012 as it is not probable or reasonably estimable.  Please read “Item 1A.—Risk Factors—Pursuant to the Gas Processing Agreement with Chipeta and the Amended and Restated Monarch

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Agreement, we may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments.”

Please read “Item 1.—Business—2012 and Recent Highlights—Gas Processing Agreements” above for more information.

Office Space

We lease approximately 11,170 square feet of office space in Denver, Colorado. The average annual rent expense over the term of the lease is approximately $216,000 and the lease terminates on May 31, 2017.

ITEM 3 - LEGAL PROCEEDINGS

Clean Water Act Compliance Order Matter

On October 3, 2011, we received a compliance order from the EPA Region 8 under the authority of the federal Clean Water Act.  The compliance order alleges that we violated the Clean Water Act by discharging fill material into wetlands adjacent to the Green River in Utah without authorization on two occasions: (i) once when we constructed an access road to a future well location in either 2004 or 2005 and (ii) once when we constructed an access road and a well pad in 2007 or 2008.  The compliance order directs us 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 us to 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.  We disagree with some of the factual contentions in the compliance order, and we have had a number of discussions with the EPA concerning the order.  However, we have been unable to negotiate a successful resolution of the alleged violations with the EPA, and as a result, we 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 the 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.  On September 5, 2012, the EPA, represented by the Department of Justice, answered, and the United States separately counterclaimed for an injunction seeking substantially the same relief that the EPA seeks in the compliance order but also requesting civil penalties for each day of alleged discharges of fill material and each day of alleged violation of the compliance order.  We have answered the EPA’s counterclaim.  In late January 2013, pursuant to a Scheduling Order before the court, we submitted a brief in support of our claims under the original suit filed in June 2012.  We are not able to predict the outcome of this matter at this time.

NEPA Suit

In June 2012, the BLM signed and issued a Rule of Decision on the EIS that authorizes the development of our Uinta Basin field upon federal lands in Duchesne and Uintah Counties, Utah.  This field includes our core Riverbend Project.  However on January 18, 2013, certain non-governmental environmental organizations, including the Southern Utah Wilderness Alliance, or SUWA, filed a suit against the BLM, challenging the ROD issued by that agency.  In its complaint, SUWA alleges that the BLM failed to comply with the requirements of NEPA and its implementing regulations.  SUWA was seeking, among other things, that the ROD and EIS be set aside, the effect of which would void the BLM’s authorization for us to proceed with its planned project. Only recently, on February 13, 2013, SUWA voluntarily submitted notice of dismissal of the suit to the District Court. Because SUWA voluntarily withdrew its suit, it has the opportunity to refile the suit at a later date. Whether SUWA will refile this suit at a later date is currently unknown to us. While any future suit by SUWA or any other third party that seeks to set aside the ROD issued by the BLM for our planned project in the Uinta Basin field in Utah could, if

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successful, have a material adverse effect on our ability to perform the planned project, we would not expect the outcome of such proceeding to have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Hat Creek Settlement

In February 2013, we settled a claim with one of our working interest owners, Hat Creek Energy LLC (“Hat Creek”), in connection with a well that was operated by us and owned by both parties. Hat Creek filed the claim on April 2, 2012 in the Denver District Court, alleging that Hat Creek did not consent to certain reworking operations performed by us in violation of the joint operating agreement, and that Hat Creek’s working interest in the well was impaired as a result.  Hat Creek sought damages of not less than $200,000, and we sought counterclaim damages for receivables owed by Hat Creek and for the reworking costs.  We settled this claim for $315,000 consisting of a $160,000 cash payment to Hat Creek and the forgiveness of $155,000 in accounts receivable owed to us by Hat Creek. In addition, the settlement provides that we will receive Hat Creek’s ownership interest in the well.  The final settlement has been accrued in the accompanying consolidated financial statements and is dependent upon the completion of the final settlement documents.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5 - MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

The Company’s common stock is currently traded on the Exchange under the symbol “GSX.”  As of March 6, 2013, the Company had 164 record shareholders of its common stock.

The following table sets forth, for the periods indicated, the high and low sales prices per share of the Company’s common stock as reported on the Exchange for the periods reflected.

	High		Low
2011
First Quarter	$	0.63	$	0.35
Second Quarter	0.48		0.20
Third Quarter	0.37		0.18
Fourth Quarter	0.24		0.15
2012
First Quarter	$	0.33	$	0.18
Second Quarter	0.26		0.22
Third Quarter	0.21		0.10
Fourth Quarter	0.16		0.07

Dividends

We have never declared or paid cash dividends on our common stock. Our management anticipates that we will retain future earnings, if any, to satisfy our operational and other cash needs and does not anticipate that dividends will be paid on our common stock in the foreseeable future. Furthermore, our 2015 Notes contain covenants that restrict the payment of dividends. See further discussion in Note 5 — Senior Convertible Notes of the accompanying financial statements.

ITEM 6 - SELECTED FINANCIAL DATA

The following table sets forth selected financial data derived from our historical consolidated financial statements and related notes regarding our financial position and results of operations as the dates indicated. Certain reclassifications have been made to prior financial data to conform to the current presentation. The financial information is an integral part of, and should be read in conjunction with, the consolidated financial statements and notes thereto included in Item 8 hereof. Information concerning significant trends in financial condition and results of operations is contained in “Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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	For the Years Ended December 31,
	2012			2011			2010		2009			2008
Summary of Operations
Natural gas revenue	$	6,779,540		$	15,359,973		$	17,053,924	$	13,801,679		$	32,328,579
Oil revenue	2,100,133			2,975,635			2,612,233		1,916,757			3,306,253
General & administrative expense	4,818,644			4,933,691			6,743,539		8,130,151			9,211,806
Impairment	16,486,000			—			—		41,000,000			3,500,000
Net (loss) income	(22,232,391		)	(7,301,645		)	10,127,020		(50,188,171		)	14,513,945
Net (loss) income per share
Basic	(0.13		)	(0.05		)	0.08		(0.47		)	0.14
Diluted	(0.13		)	(0.05		)	0.08		(0.47		)	0.13

	As of December 31,
	2012		2011			2010			2009			2008
Balance Sheet
Working capital (deficit)	$	2,320,812	$	(6,589,677	)	$	(254,000	)	$	8,440,548		$	10,894,674
Cash and cash equivalents	2,938,086		1,965,967			1,994,542			10,577,340			1,053,216
Property, plant and equipment, net	45,124,043		75,208,168			69,704,454			67,335,582			128,712,579
Total assets	53,854,291		84,654,236			80,010,429			104,741,713			153,885,508
Noncurrent liabilities	31,118,034		30,720,738			30,018,127			101,587,581			97,196,768
Stockholders’ equity (deficit)	17,703,631		39,655,225			41,935,252			(4,193,399		)	44,042,888

ITEM 7 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data included elsewhere in this report.

Forward-Looking Statements

Please refer to the section entitled “Cautionary Statement Regarding Forward-Looking Statements” and “Item 1A.—Risk Factors,” for a discussion of factors which could affect the outcome of forward-looking statements used in this report.

Overview

We are a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon prospects, primarily in the Rocky Mountain region. Our business strategy is to enhance shareholder value by generating and developing high-potential exploitation resources in this area. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to those 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.

Due to the significant extended decline in the natural gas market and in sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated.  As such, there is substantial doubt

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regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013.  Our prior revolving credit facility matured in June 2012, at which time we repaid all of the outstanding borrowings thereunder.  While we have attempted to secure a replacement facility, we have been unable to do so on acceptable terms and we are no longer actively in discussions to obtain a replacement facility.  There can be no assurance that we will be able to adequately finance our operations or execute our existing short-term and long-term business plans, and our liquidity and results of operations are likely to be materially adversely affected if we are unable to generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity. We have engaged a financial advisor to assist us in evaluating such potential strategic alternatives. It is possible these strategic alternatives will require us to make a pre-package, pre-arranged or other type of filing for protection under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against us).  As a result of these factors, there is substantial doubt about our ability to continue as a going concern. For additional information regarding our current liquidity situation, please see “Liquidity and Capital Resources” below.

See “2012 and Recent Highlights” in “Item 1—Business”

2013 Capital Budget

We have not allocated any amounts to the 2013 capital budget. As discussed above, due to the significant extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated.  There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013.  This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of our cash management strategy discussed below, some or all of which may not prove to be correct and may result in our inability to meet cash requirements prior to the second quarter of 2013.  See “Liquidity and Capital Resources.”

Summary of Capital Expenditures

The following table summarizes our capital expenditures during 2012 by reconciling the cash paid for acquisitions, development and exploration included within the Consolidated Statement of Cash Flows in Item 8.

Cash paid for acquisitions, development and exploration	$	5,756,886
Cash spent for 2011 property costs that were accrued at 12/31/11	(830,000		)
Capital expenditures for 2012 projects	$	4,926,886
Lease acquisitions and related costs	$	2,490,305
Facilities and equipment costs	99,975
Drilling, completion and recompletion activity	2,336,606
Capital expenditures for 2012 projects	$	4,926,886

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Production and Reserve Information

The following tables present certain of our production information for each of the three years ended December 31, 2012 and our estimated proved reserves as of December 31 of each year presented. The Mcfe calculations assume a conversion of 6 Mcf for each Bbl of oil. The decrease in oil and gas production and reserve quantities during 2012 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.

	For the Years Ended December 31,
	2012		Change				2011		Change				2010
Natural gas production (Mcf)	2,406,512		(1,253,278	)	(34	)%	3,659,790		(445,349	)	(11	)%	4,105,139
Average sales price per Mcf	$	2.82	(1.38	)	(33	)%	$	4.20	0.05		1	%	$	4.15
Year-end proved gas reserves (Mcf)	12,603,717		(24,194,593	)	(66	)%	36,798,310		(2,927,750	)	(7	)%	39,726,060
Oil production (Bbl)	25,805		(11,047	)	(30	)%	36,852		(3,680	)	(9	)%	40,532
Average sales price per Bbl	$	81.38	0.64		1	%	$	80.75	16.30		25	%	$	64.45
Year-end proved oil reserves (Bbl)	251,599		(250,456	)	(50	)%	502,055		37,396		8	%	464,659
Production (Mcfe)	2,561,342		(1,319,560	)	(34	)%	3,880,902		(467,429	)	(11	)%	4,348,331
Year-end proved reserves (Mcfe)	14,113,311		(25,697,329	)	(65	)%	39,810,640		(2,703,374	)	(6	)%	42,514,014

Our natural gas production decreased by approximately 34% during 2012 as compared with 2011 and by approximately 11% during 2011 as compared with 2010. The production decrease during 2012 is primarily due to the Uinta Basin Transaction as well as normal production declines and the decrease in 2011 is the result of fewer completions of up-hole zones during 2011, third-party gathering system throughput issues and normal production declines.

Our proved reserve quantities decreased by approximately 65% and 6% during the years ended December 31, 2012 and 2011, respectively, primarily due to the Uinta Basin Transaction in 2012, revisions of previous estimates resulting from well performance on certain of our wells and production declines during both years that were not offset by the extensions and discoveries in each year. The revisions of reserve estimates during 2011 were primarily due to better than anticipated well performance related to behind pipe reserves that began producing during the year.

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	Natural Gas		Oil
	Mcf		Bbls
Proved Reserves:
Balance, December 31, 2009	44,229,950		450,858
Extensions and discoveries	—		—
Revisions of previous estimates	632,807		68,912
Sales of reserves in place	(2,213,000	)	(19,000	)
Purchases of reserves in place	1,181,442		4,421
Production	(4,105,139	)	(40,532	)
Balance, December 31, 2010	39,726,060		464,659
Extensions and discoveries	—		33,382
Revisions of previous estimates	732,040		40,866
Sales of reserves in place	—		—
Purchases of reserves in place	—		—
Production	(3,659,790	)	(36,852	)
Balance, December 31, 2011	36,798,310		502,055
Extensions and discoveries	—		10,400
Revisions of previous estimates	(10,110,081	)	(28,351	)
Sales of reserves in place	(12,251,600	)	(210,500	)
Purchases of reserves in place	573,600		3,800
Production	(2,406,512	)	(25,805	)
Balance, December 31, 2012	12,603,717		251,599

	Gas	Oil
	Mcf	Bbls
Proved Developed Reserves
Balance, December 31, 2012	12,603,717	251,599
Balance, December 31, 2011	36,798,310	502,055
Balance, December 31, 2010	39,726,060	464,659

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 years ended December 31, 2012 and 2011, 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 year ended December 31, 2012, we incurred a net loss of $22,232,391 and had negative cash flow from operations of $3,668,672.  As of December 31, 2012, we had an accumulated deficit of $244,808,156.

Our consolidated financial statements included in this Annual Report have been prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the next twelve months.  However, due to the significant

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extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, we have not been able to recover our exploration and development costs as anticipated.  For example, we had net losses and negative cash flow from operations for the three and twelve months ended December 31, 2012 and at December 31, 2012 had an accumulated deficit of $244,808,156.  There is substantial doubt regarding our ability to generate sufficient cash flows from operations to fund our ongoing operations, and we currently anticipate that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013.  This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of our cash management strategy discussed below, some or all of which may not prove to be correct and may result in our inability to meet cash requirements prior to the second quarter of 2013. Our prior revolving credit facility matured in June 2012, at which time we repaid all of the outstanding borrowings thereunder. While we have attempted to secure a replacement facility, as of the date of this Annual Report, we have been unable to do so on acceptable terms and are no longer actively in discussions to obtain a replacement facility. Furthermore, we may not achieve profitability from operations in the near future or at all and we may continue to experience significant losses.  As a result of these factors, there is substantial doubt about our ability to continue as a going concern.

As of December 31, 2012, we had $45,168,000 aggregate principal amount of our 2015 Notes outstanding.  The 2015 Notes bear interest at a rate of 5.50% per annum, payable in cash semi-annually in arrears on April 5th and October 5th of each year.  Our failure to make an interest payment on the 2015 Notes, if not cured within 30 days, would result in a default under the indenture governing the 2015 Notes, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes.

In addition, the delisting of our common stock from the Exchange may also result in a default under the Indenture. We have received notices from the Exchange notifying us that we do not satisfy the Exchange’s continued listing standards. We submitted a Plan of compliance to the Exchange on February 11, 2013.  Pursuant to the Plan, we intend to lower costs, rationalize assets, refocus our development program toward oil and liquids, especially in the Green River Formation, and continue our California program with the potential goal of expanding our California model.  The Plan also considers strategic alternatives, including the debt restructuring and sales of assets, if necessary.  However, there can be no assurance that this Plan will be accepted by the Exchange or that we will be able to achieve compliance with the Exchange’s continued listing standards within the required time frame. If the Plan is not accepted, we will be subject to delisting proceedings.  Furthermore, if the Plan is accepted but we are not in compliance with the continued listing standards of the Company Guide by June 30, 2013, or if we do not make progress consistent with the Plan, the Exchange staff will initiate delisting proceedings as it deems appropriate.  Please read “Item 1—Business—2012 and Recent Highlights— NYSE MKT LLC Communications” for more information.

Pursuant to our JOA and contract operating agreements in connection with the Uinta Basin Transaction pursuant to which we serve as operator, if we become insolvent, bankrupt or are placed into receivership, we will be deemed to have resigned as operator or the other party may have termination rights. We also have commitments under our gas processing and transportation contracts as discussed in “Delivery Commitments” in “Item 2—Properties.”  We may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments.  Please read “Item 1A.—Risk Factors—Pursuant to the Gas Processing Agreement with Chipeta and the Amended and Restated Monarch Agreement, we may be required to make periodic deficiency payments for any shortfalls from the specified minimum volume commitments.”

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

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postponement of further exploration and development of our prospects resulting in the possible loss of our properties. This has caused us to alter our business plans, and we may be further required to reduce our exploration and development plans. For example, we have not allocated any amounts to the 2013 capital budget. In particular, we face uncertainties relating to our ability to fund the level of capital expenditures required for oil and gas exploration and production activities. We intend to fund our anticipated cash requirements through the second quarter of 2013 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. If they are not, our ability to continue as a going concern as well as to fund our operating budget will be significantly limited, and our liquidity and results of operations will be materially adversely affected.

To continue as a going concern, we must generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity. The urgency of our liquidity situation may require us to pursue such a transaction at an inopportune time. Moreover, our ability to successfully implement, and the cost of, any such transaction will depend on numerous factors, including:

·demand and prices for natural gas and oil;

·general economic conditions;

·strength of the credit and capital markets;

·our ability to successfully execute our operational strategies, and our operating and financial performance;

·our ability to remain in compliance with our debt and equity instruments;

·our stock price, and ability to regain and maintain compliance with the Exchange’s continued listing requirements;

·our ability to remain in compliance with our operational agreements, including our gas processing, gathering and transportation agreements;

·our counterparties refraining from exercising any remedies available as a result of the determination that we are insolvent or unable to perform in accordance with the contract;

·our ability to maintain relationships with our suppliers, customers, employees, stockholders and other third parties; and

·market uncertainty in connection with our ability to continue as a going concern as well as investor confidence in us.

If we fail to generate sufficient operating cash flows, secure additional capital or otherwise restructure or refinance our business before the end of the second quarter, we will not have adequate liquidity to fund our operations and meet our obligations (including our debt payment obligations), will not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against us).

A bankruptcy filing by or against us would subject our business and operations to various risks, including but not limited to, the following:

·a bankruptcy filing by or against us may adversely affect our business prospects, including our ability to continue to obtain and maintain the contracts necessary to operate our business on competitive terms;

·a bankruptcy filing by or against us may cause an event of default under the indenture governing the 2015 Notes;

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·certain provisions in our operating agreements may be triggered such that we would be deemed to have resigned as operator or the agreements may be terminated by the other party;

·we may be unable to retain and motivate key executives and employees through the process of reorganization, and we may have difficulty attracting new employees;

·there can be no assurance as to our ability to maintain or obtain sufficient financing sources for operations or to fund any reorganization plan and meet future obligations;

·there can be no assurance that we will be able to successfully develop, prosecute, confirm and consummate one or more plans of reorganization that are acceptable to the bankruptcy court and our creditors, equity holders and other parties in interest; and

·the value of our common stock could be reduced to zero as result of a bankruptcy filing.

In order to address our liquidity constraints and in addition to our ongoing efforts to secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide us with additional liquidity, we have embarked on a cash management strategy to enhance and preserve as much liquidity as possible. This plan contemplates us, among other things:

·reducing expenditures by eliminating, delaying or curtailing discretionary and non-essential spending, and not designating any capital budget for 2013;

·managing working capital;

·delaying certain drilling projects;

·pursuing farm-out and other similar types of transactions to fund working capital needs;

·evaluating our options for the divestiture of certain assets;

·considering asset purchases through the issuance of equity;

·investigating merger opportunities; and

·restructuring and reengineering our organization and processes to reduce operating costs and increase efficiency.

We cannot provide any assurances that we will be successful in accomplishing any of these plans or that any of these actions can be effected on a timely basis, on satisfactory terms or maintained once initiated. Furthermore, our cash management strategy, if successful, may limit certain of our operational and strategic initiatives designed to grow our business over the long term.

Uinta Basin Transaction

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. If we are not able to pay our share of the above costs, we may lose certain rights granted under the Development Agreement and related operating agreements, including the right to continue as operator or contract operator of the properties, the right to make proposals or elect to participate in operations under the Development Agreement or any operating agreement, the right to call,

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attend and vote at meetings of the operating committee, the right to transfer our interest in the properties and the joint venture, the right to acquire Wapiti’s interest in the properties under the right of first offer provisions of the Development Agreement and the right to acquire its pro rata share of additional properties acquired by Wapiti within the area of mutual interest identified in the Development Agreement. We have not incurred any costs to date and there is substantial doubt regarding our ability to fund our share of the drilling and completion costs. We have not incurred any costs to date and there is substantial doubt regarding our ability to fund our share of the drilling and completion 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 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 low natural gas prices and permitting delays, we did not drill any natural gas wells in Utah during the remainder of 2012.

Sources and Uses of Cash

The following table summarizes our sources and uses of cash for each of the three years ended December 31, 2012, 2011 and 2010.

	For the Years Ended December 31,
	2012			2011			2010
Net cash (used in) provided by operating activities	$	(3,668,672	)	$	(429,500	)	$	3,643,851
Net cash provided by (used in) investing activities	13,185,760			(9,847,128		)	18,474,645
Net cash (used in) provided by financing activities	(8,544,969		)	10,248,053			(30,701,294		)
Net cash flow	972,119			(28,575		)	(8,582,798		)

Cash provided by operations decreased by $3,239,172 during 2012 as compared with 2011 primarily due the decrease in oil and gas revenue resulting from the sale of approximately 50% of the working interest in certain of our properties. The decrease of $4,073,351 in cash provided by operations from 2010 to 2011 was primarily due to approximately $2,163,000 of workover expenses incurred in 2011 and a decrease in oil and gas revenue resulting from the production decline discussed previously.

Our investing activities during the three years ended December 31, 2012 related primarily to our development and exploration activities, fixed asset additions and changes in advances from joint interest owners. The activity during 2012 included the sales proceeds from the Uinta Basin Transaction and the activity during 2010 included proceeds of $24,309,000 associated primarily with the sale of our gathering and evaporative facilities and the sale of a partial working interest in 32 producing wells.

During the three years ended December 31, 2012, our financing activity included borrowings and repayments under our credit facility. The 2011 activity also included $8,713,053 in net proceeds from the issuance of common stock and warrants and the $400,000 for the repayment of certain convertible notes. The 2010 activity included the $54,400 repurchase of certain convertible notes and the payment of a deposit for $500,000.

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Schedule of Contractual Obligations

The following table summarizes the Company’s obligations and commitments to make future payments under its notes payable, operating leases, employment contracts, consulting agreements and service contracts for the periods specified as of December 31, 2012.

		Payments due by Period
		Total		Less than 1 year		1—3 years		3—5 years		More than5 years
Convertible 2015 Notes
Principal		$	45,168,000	$	—	$	45,168,000	$	—	$	—
Interest		6,866,163		2,484,240		4,381,923		—		—
Firm commitments	(a)	59,044,993		6,006,803		13,282,420		12,203,945		27,551,825
Operating leases		988,544		193,613		463,555		331,376		—
Employment & consulting contracts		950,000		770,000		180,000		—		—
Asset retirement obligations	(b)	815,660		—		—		—		815,660
Total		$	113,833,360	$	9,454,656	$	63,475,898	$	12,535,321	$	28,367,485

(a)These values represent the gross commitments to deliver fixed and determinable quantities of natural gas per our gathering, transportation and processing agreement with Monarch, QPC and Chipeta over the life of the contracts. These amounts are owed regardless of whether we deliver any natural gas quantities to the applicable parties. For more information, see “Item 2. — Properties — Delivery Commitments.”

(b)The accuracy and timing of the asset retirement obligations cannot be precisely determined in advance. See further discussion in Note 3 — Significant Accounting Policies—Asset Retirement Obligation of the accompanying consolidated financial statements.

Forward Sales Contracts

During March 2010, pursuant to the Base Contract for Sale and Purchase of Natural Gas with Anadarko Energy Services Company, dated December 1, 2007, we entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of our gross production through 2013 from the Uinta Basin. The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price. We account for our agreement to physically settle our production as an executory contract. We do not believe that the loss of this contract would materially affect our business because there are other potential purchasers in the areas in which we sell our production; however, we may not be able to find other purchasers who would purchase our production on terms comparable to our current arrangements.

Derivatives

Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. From time to time, we use 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. 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 

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2012, we monetized this contract for net proceeds of $677,868. See further discussion in “Item 7A—Quantitative and Qualitative Disclosures about Market Risk.”

Critical Accounting Policies and Estimates

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

Oil and Natural Gas Properties and Reserves

We follow the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Under the full cost method of accounting, 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 of the excess capitalized costs exceed this ceiling. As of March 31, 2012, June 30, 2012, September 30, 2012 and December 31, 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, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012, $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012, and $80.25 per barrel and $2.15 per Mcf of gas during the 12-month period ended December 31, 2012. Therefore, impairment expense of $16,486,000 was recorded during the year ended December 31, 2012.There was no impairment recorded during 2010 or 2011.

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

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

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

Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the quantities and present value of our reserves. For example, a 10% decrease in prices used to estimate our reserve quantities as of December 31, 2012 would result in a decrease in the present value of future net cash flows of approximately $3,311,400. In addition, we may adjust estimates of proved reserves to reflect production history, acquisitions, divestitures, ownership interest revisions, results of exploration and development and prevailing natural gas and oil prices. Our reserves may also be susceptible to drainage by operators on adjacent properties.

Impairment of Long-lived Assets

The cost of our unproved properties is withheld from the depletion base as described above, until it is determined whether or not proved reserves can be assigned to the properties. These properties are reviewed periodically for possible impairment. Our management reviews all unproved properties each quarter. If a determination is made that acreage will be expiring or that we do not plan to develop some of the acreage that is no longer considered to be prospective, we record an impairment of the acreage and reclassify the costs to the full cost pool. We estimate the value of these acres for the purpose of recording the related impairment. The impairments that we have recorded were estimated by calculating a per acre value from the total unproved costs incurred for the applicable acreage divided by the total net acres owned by us. This per acre estimate is then applied to the acres that we do not plan to develop in order to calculate the impairment. A change in the estimated value of the acreage could have a material impact on the total impairment recorded by us, calculation of depletion expense and the ceiling test analysis.

During the year ended December 31, 2012, we reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification was comprised of a $7,000,000 decrease in the carrying value of our Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012. During 2011, we reclassified $660,000 of acreage costs in Nevada into proved property as we relinquished our control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects.

Stock-Based Compensation

We account for stock option and SARs grants and restricted stock awards by recognizing compensation cost for stock-based awards based on the estimated fair value of the award. Compensation cost is measured at the grant date based on the fair value of the award and is recognized as an expense over the service period, which generally represents the vesting period. We use the Black-Scholes option valuation model to calculate the fair value of option and SARs awards and we use the intrinsic valuation method for the restricted stock awards. The Black-Scholes model requires us to estimate a risk free interest rate and the volatility of our common stock price. The use of a different estimate for any one of these components could have a material impact on the amount of calculated compensation expense.

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Derivatives

We have from time to time entered into certain commodity derivative instruments to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. We record all derivative instruments at fair value in the accompanying consolidated balance sheets. Changes in the fair value are to be recognized currently in earnings unless specific hedge accounting criteria are met. We recorded a change in the fair value of commodity derivative instruments of $(865,358), $671,399 and $(2,887,564) during the years ended December 31, 2012, 2011 and 2010, respectively. We also recorded a change in the fair value of our outstanding Warrants of $3,327,500 and $(199,375) during the years ended December 31, 2012 and 2011, respectively. In addition, during 2010 we recorded a change in fair value of an embedded derivative associated with the exchange of our 5.5% Convertible Senior Notes due 2011 (the “2011 Notes”) for 2015 Notes (the “Exchange Transaction”) of $(6,840,392). See Note 5 — Convertible Senior Notes to the accompanying consolidated financial statements.

As of December 31, 2011, the fair value of our natural gas costless collar agreement was a current asset of $865,358.During June 2012, we monetized this contract for net proceeds of $677,868. The fair value measurement of the commodity derivative assets and liabilities are measured based upon our valuation model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) notional quantities, (d) current market and contractual prices for the underlying instruments and (e) the counterparty’s credit risk. The unobservable inputs related to the volatility of the oil and gas commodity market are very significant in these calculations. See Note 11 — Fair Value Measurements to the accompanying consolidated financial statements for further discussion.

Our warrant derivative financial instrument as of December 31, 2012 and 2011 was a noncurrent liability of $907,500 and $4,235,000, respectively. The Warrants are valued using a binomial lattice-based valuation model. 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. 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.

Results of Operations

2012 Compared to 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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	Year Ended December 31,				Year over Year Change
	2012		2011		Amount			Percentage
Natural gas production (Mcf)	2,406,512		3,659,790		(1,253,278		)	(34	)%
Average sales price per Mcf	$	2.82	$	4.20	$	(1.38	)	(33	)%
Natural gas revenue	$	6,779,540	$	15,359,973	$	(8,580,433	)	(56	)%
Oil production (Bbl)	25,805		36,852		(11,047		)	(30	)%
Average sales price per Bbl	$	81.38	$	80.75	$	0.63		1	%
Oil revenue	$	2,100,133	$	2,975,635	$	(875,502	)	(29	)%
Total oil and gas revenue	$	8,879,673	$	18,335,608	$	(9,455,935	)	(52	)%
Equivalent production (Mcfe)	2,561,342		3,880,902		(1,319,560		)	(34	)%

The decrease in oil and gas revenue of $9,455,935 during the year ended December 31, 2012 compared with the year ended December 31, 2011 was comprised of a 34% decrease in equivalent oil and gas production and a 33% decrease in gas prices from $4.20 in 2011 to $2.82 in 2012 partially offset by a 1% increase 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 $9,455,935 decrease in oil and gas revenue during 2012 represents a decrease of $4,431,176 related to the equivalent production decrease and a decrease of $5,024,759 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 Year Ended December 31,					Year over Year Change
	2012			2011		Amount			Percentage
Direct operating expenses and overhead	$	3,710,855		$	5,670,033	$	(1,959,178	)	(34	)%
Workover expense	1,305,226			2,490,613		(1,185,387		)	(48	)%
Total operating expenses	$	5,016,081		$	8,160,646	$	(3,144,565	)	(38	)%
Operating expenses per Mcfe	$	1.96		$	2.10	$	(0.14	)	(7	)%
Severance tax refund	$	(305,825	)	$	—	$	(305,825	)	—
Severance tax refund per Mcfe	$	(0.12	)	$	—	$	(0.12	)	—
Production and property taxes	$	249,781		$	718,856	$	(469,075	)	(65	)%
Production and property taxes per Mcfe	$	0.10		$	0.19	$	(0.09	)	(47	)%
Total lease operating expense	$	4,960,037		$	8,879,502	$	(3,919,465	)	(44	)%
Total lease operating expense per Mcfe	$	1.94		$	2.29	$	(0.35	)	(15	)%

Lease operating expense decreased $3,919,465 during the year ended December 31, 2012 compared with the year ended December 31, 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 and a decrease in workover expenses because of fewer projects during 2012. The severance tax refund during 2012 represents the tax credit received for the workover projects that we performed.

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Transportation and Processing

Transportation and processing costs of $1,704,677 ($0.67 per Mcfe) and $2,759,780 ($0.71 per Mcfe) during the years ended December 31, 2012 and 2011, respectively, represent the costs we incurred to transport and process the gas production from our wells. The decrease of $1,055,103 in these expenses during 2012 reflects lower transportation and processing costs related to the 34% decrease in gas production due to the Uinta Basin Transaction and normal production declines and the 33% decrease in gas prices.

Depletion, Depreciation, Amortization and Accretion

Depletion, depreciation, amortization and accretion expense during the years ended December 31, 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 $793,112 during 2012 compared to 2011 primarily due to the production decline from the Uinta Basin Transaction, combined with the decrease in the full cost pool resulting from property impairments during 2012, as discussed below.

Impairment

As of March 31, 2012, June 30, 2012, September 30, 2012 and December 31, 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, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012, $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012, and $80.25 per barrel and $2.15 per Mcf of gas during the 12-month period ended December 31, 2012. Therefore, impairment expense of $16,486,000 was recorded during the year ended December 31, 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 Years Ended December 31,						Year over Year Change
	2012			2011			Amount			Percentage
Total general and administrative costs	$	6,023,259		$	6,166,845		$	(143,586	)	(2	)%
General and administrative costs allocated to drilling, completion and operating activities	(1,474,594		)	(1,556,887		)	82,293			5	%
General and administrative expense	$	4,548,665		$	4,609,958		$	(61,293	)	(1	)%
General and administrative expenses per Mcfe	$	1.78		$	1.19		$	0.59		50	%
Stock-based compensation	$	269,979		$	323,733		$	(53,754	)	(17	)%
Stock-based compensation per Mcfe	$	0.10		$	0.08		$	(0.02	)	(25	)%
Total general and administrative expense including stock-based compensation	$	4,818,644		$	4,933,691		$	(115,047	)	(2	)%
Total general and administrative expense per Mcfe	$	1.88		$	1.27		$	(0.61	)	(48	)%

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General and administrative expense including stock-based compensation expense decreased by $115,047 during the year ended December 31, 2012 as compared with the year ended December 31, 2011 primarily due to decreased consulting fees during 2012 and lower stock compensation expense related to the vesting of certain stock options.

Interest Expense

Interest expense increased $157,881 during the year ended December 31, 2012 as compared with the same period during 2011, primarily due to the increase in discount amortization associated with our 2015 Notes.

Gain on Sale of Assets

The gain on sale of assets during the year ended December 31, 2012 represents the gain from the Uinta Basin Transaction.

Derivative Gains

Derivative gains during the years ended December 31, 2012 and 2011 include the unrealized gains on our warrant derivative liability as well as the realized and unrealized gains and losses on our commodity derivative instruments. The unrealized derivative 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 period.

Amortization of Deferred Income from Sale of Assets

The amortization of the deferred income from the sale of assets during the years ended December 31, 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 February 2010.

2011 Compared to 2010

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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	For the Years Ended December 31,				Year over Year Change
	2011		2010		Value/Quantity			Percentage
Natural gas production (Mcf)	3,659,790		4,105,139		(445,349		)	(11	)%
Average sales price per Mcf	$	4.20	$	4.15	$	0.05		1	%
Natural gas revenue	$	15,359,973	$	17,053,924	$	(1,693,951	)	(10	)%
Oil production (Bbl)	36,852		40,532		(3,680		)	(9	)%
Average sales price per Bbl	$	80.75	$	64.45	$	16.30		25	%
Oil revenue	$	2,975,635	$	2,612,233	$	363,402		14	%
Total oil and gas revenue	$	18,335,608	$	19,666,157	$	(1,330,549	)	(7	)%
Equivalent production	3,880,902		4,348,331		(467,429		)	(11	)%

The decrease in oil and natural gas revenue of $1,330,549 during 2011 compared with 2010 was comprised of an 11% decrease in equivalent oil and gas production partially offset by increased oil and gas prices. The production decrease is the result of fewer completions of up-hole zones during 2011, third-party gathering system throughput issues and normal production declines. During 2011, the average oil and natural gas prices increased by $0.05 per Mcf and $16.30 per Bbl, respectively. The $1,330,549 decrease in oil and natural gas revenue during 2011 represents a decrease of $2,117,203 related to the equivalent production increase partially offset by an increase of $786,654 related to the increase in oil and natural gas prices.

Gathering Revenue and Expense

Gathering revenue and expense during 2010 represents the income earned from third-party working interest owners in the wells we operated and the expenses incurred from our gathering system in the Riverbend area. We sold our gathering assets in February 2010, which eliminated these revenues and expenses after February 2010.

Lease Operating Expenses

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

	For the Year Ended December 31,				Year over Year Change
	2011		2010		Value			Percentage
Direct operating expenses and overhead	$	5,670,033	$	4,778,914	891,119			19	%
Workover expense	2,490,613		361,170		2,129,443			590	%
Total operating expenses	$	8,160,646	$	5,140,084	$	3,020,562		59	%
Operating expenses per Mcfe	$	2.10	$	1.18	$	0.92		78	%
Production and property taxes	$	718,856	$	882,761	$	(163,905	)	(19	)%
Production and property taxes per Mcfe	$	0.19	$	0.20	$	(0.01	)	(5	)%
Total lease operating expense	$	8,879,502	$	6,022,845	$	2,856,657		47	%
Total lease operating expense per Mcfe	$	2.29	$	1.39	$	0.90		65	%

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Lease operating expense increased $2,885,657 during 2011 compared with 2010. The increase is primarily due to higher workover and operating expenses partially offset by lower production and property taxes due to lower oil and gas revenue during 2011. The increase in workover activity related to the removal of critical velocity reduction strings, modification of cap strings and scale treatment and removal from existing wells in 2011. The increase in operating expenses was primarily due to the increase in water disposal fees which we had to pay for the full year in 2011 and only for the last three quarters of 2010 after the sale of our evaporative pits during 2010.

Transportation and Processing

Transportation and processing costs were $2,759,780 ($0.71 per Mcfe) and $3,002,719 ($0.69 per Mcfe) during the years ended December 31, 2011 and 2010, respectively. The decrease of $242,939 reflects a full year of these costs in 2011 versus ten months of these costs in 2010 due to the sale of our gathering system during February 2010. The increase in these costs during 2011 was partially offset by the production decline as previously discussed.

Depletion, Depreciation, Amortization and Accretion

The decrease in depletion, depreciation and amortization expense of $39,866 during 2011 compared to 2010 was primarily due to the decline in production as described above.

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 Year Ended  December 31,						Year over Year Change
	2011			2010			Value			Percentage
Total general and administrative costs	$	6,166,845		$	6,936,835		$	(769,990	)	(11	)%
General and administrative costs allocated to drilling, completion and operating activities	(1,556,887		)	(1,558,560		)	1,673			0	%
General and administrative expense	$	4,609,958		$	5,378,275		$	(768,317	)	(14	)%
General and administrative expenses per Mcfe	$	1.19		$	1.24		$	(0.05	)	(4	)%
Total stock-based compensation costs	$	323,059		$	1,363,894		(1,040,835		)	(76	)%
Stock-based compensation (costs) reduction in costs capitalized	674			1,370			(696		)	(51	)%
Stock-based compensation	$	323,733		$	1,365,264		$	(1,041,531	)	(76	)%
Stock-based compensation per Mcfe	$	0.08		$	0.31		$	(0.23	)	(74	)%
Total general and administrative expense including stock-based compensation	$	4,933,691		$	6,743,539		$	(1,809,848	)	(27	)%
Total general and administrative expense per Mcfe	$	1.27		$	1.55		$	(0.28	)	(18	)%

Total general and administrative expense decreased by $1,809,848 during 2011 as compared to 2010 primarily as a result of $950,000 in severance payments we agreed to make to our former President and CEO in connection with his resignation during January 2010 partially offset by increased legal and

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consulting fees during 2011 associated with our increased transactional activity. The decrease in stock-based compensation expense was due primarily to the fact that a substantial portion of our unvested stock options were being accounted for as liability awards until stockholder approval of the stock plan under which such options were issued was received in July 2011.

Interest Expense

Interest expense decreased $10,918,820 during 2011 as compared with the 2010, primarily due to the pro-rata portion of the unamortized discount and debt interest costs that were recorded as interest expense upon the conversion of 30% of the original principal amount of the 2015 Notes in September 2010.

Derivative Gains

Derivative gains during 2011 and 2010 are comprised of realized and unrealized gains and losses on our commodity derivative instruments and unrealized gains on our warrant derivative liability during 2011. The unrealized derivative gains (losses) represent the changes in the fair value of our derivative assets and liabilities and the realized derivative gains (losses) represent the net settlements due from or to our counterparty based on each month’s settlement during the quarter.

Gain on Extinguishment of Debt

Gain on extinguishment of debt during 2010 represents the difference between the fair value of the 2015 Notes and the debt conversion derivative as compared to the carrying value of the 2011 Notes less unamortized debt issuance costs that were exchanged for such 2015 Notes in a transaction that closed on June 25, 2010.

Amortization of Deferred Income from Sale of Assets

The amortization of the deferred income from the sale of assets represents the amortization of the excess of proceeds received over the carrying value of our gathering system and evaporative facilities.

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 December 31, 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. See “Liquidity and Capital Resources” above and “Item 2.—Properties—Delivery Commitments” for additional discussion regarding certain gas transportation and processing agreements and our obligations thereunder.

Recently Issued Accounting Pronouncements

Effective January 1, 2012, we 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 our consolidated financial position or results of operations.

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ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to a variety of market risks, including commodity price risk. We address these risks through a program of risk management which may include the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we were a party at December 31, 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 referred to as 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 3 — Significant Accounting Policies of the accompanying 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 December 31, 2012:

(i)the warrant derivative liability would remain unchanged if the trading price of our common stock was reduced to zero and would increase by approximately $1.9 million for a $0.10 per share increase in the trading price of our common stock; and

(ii)the warrant derivative liability would remain unchanged for a 10% increase in the volatility rate and would decrease by approximately $302,500 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 December 31, 2012.

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ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	81
Consolidated Balance Sheets at December 31, 2012 and 2011	82-83
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010	84
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010	85
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010	86
Notes to Consolidated Financial Statements	87

80

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Gasco Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Gasco Energy, Inc. and subsidiaries (the Company) as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in note 2 to the consolidated financial statements, the Company has suffered recurring losses and negative cash flows from operations that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 6, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Denver, Colorado
March 6, 2013

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GASCO ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2012			2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,938,086		$	1,965,967
Accounts receivable
Joint interest billings	1,753,204			810,482
Revenue	777,567			1,483,382
Inventory	1,730,733			1,911,362
Note receivable	—			500,000
Derivative instruments	—			865,358
Prepaid and other expenses	153,848			152,045
Total	7,353,438			7,688,596
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved properties	264,814,427			268,793,463
Unproved properties	31,486,314			36,938,162
Wells in progress	—			1,938,691
Facilities and equipment	1,493,314			1,502,921
Furniture, fixtures and other	506,511			167,737
Total	298,300,566			309,340,974
Less accumulated depletion, depreciation, amortization and impairment	(253,176,523		)	(234,132,806		)
Total	45,124,043			75,208,168
NON-CURRENT ASSETS
Deposit	531,443			639,500
Deferred financing costs	845,367			1,117,972
	1,376,810			1,757,472
TOTAL ASSETS	$	53,854,291		$	84,654,236

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

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GASCO ENERGY, INC.

CONSOLIDATED BALANCE SHEETS (continued)

	December 31,
	2012			2011
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	1,548,121		$	2,649,772
Revenue payable	2,454,282			2,043,240
Advances from joint interest owners	47,667			98,512
Current portion of long-term debt	—			8,544,969
Accrued interest	586,556			586,556
Accrued expenses	396,000			355,224
Total	5,032,626			14,278,273
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes due 2015, net of unamortized discount of $18,530,539 and $22,574,687 as of December 31, 2012 and 2011, respectively	26,637,461			22,593,313
Deferred income from sale of assets	2,463,177			2,665,629
Derivative instruments	907,500			4,235,000
Deferred rent	294,236			—
Asset retirement obligation	815,660			1,226,796
Total	31,118,034			30,720,738
COMMITMENTS AND CONTINGENCIES (NOTE 16)
STOCKHOLDERS’ EQUITY
Series B Convertible Preferred stock - $.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 and 191,000 shares outstanding as of December 31, 2012 and 2011, respectively	182			191
Common stock - $.0001 par value; 600,000,000 shares authorized; 169,823,681 shares issued and 169,749,981 shares outstanding as of December 31, 2012; 168,084,515 shares issued and 168,010,815 shares outstanding as of December 31, 2011	16,982			16,808
Additional paid-in-capital	262,624,918			262,344,286
Accumulated deficit	(244,808,156		)	(222,575,765		)
Less cost of treasury stock of 73,700 common shares	(130,295		)	(130,295		)
Total	17,703,631			39,655,225
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	53,854,291		$	84,654,236

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

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GASCO ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Years Ended December 31,
	2012			2011			2010
REVENUES
Gas	$	6,779,540		$	15,359,973		$	17,053,924
Oil	2,100,133			2,975,635			2,612,233
Gathering	—			—			595,942
Total	8,879,673			18,335,608			20,262,099
OPERATING EXPENSES
Lease operating	4,960,037			8,879,502			6,057,571
Gathering operations	—			—			375,848
Transportation and processing	1,704,677			2,759,780			3,002,719
Depletion, depreciation and amortization	2,732,694			3,525,806			3,565,672
Impairment	16,486,000			—			—
General and administrative	4,818,644			4,933,691			6,743,539
Total	30,702,052			20,098,779			19,745,349
OPERATING (LOSS) INCOME	(21,822,379		)	(1,763,171		)	516,750
OTHER (EXPENSE) INCOME
Interest expense	(6,922,814		)	(6,764,933		)	(17,683,753		)
Gain on sale of assets	2,567,574			—			—
Derivative gains	3,718,090			996,484			11,316,191
Gain on extinguishment of debt	—			—			15,772,441
Amortization of deferred income from sale of assets	202,452			202,452			168,710
Interest income	24,686			27,523			36,681
Total	(410,012		)	(5,538,474		)	9,610,270
NET (LOSS) INCOME	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
NET (LOSS) INCOME PER COMMON SHARE
BASIC	$	(0.13	)	$	(0.05	)	$	0.08
DILUTED	$	(0.13	)	$	(0.05	)	$	0.08

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

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GASCO ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

									Additional
	Preferred Stock					Common Stock			Paid-in			Accumulated			Treasury
	Shares		Value			Shares	Value		Capital			Deficit			Stock			Total
Balance December 31, 2009	—		$	—		107,789,597	$	10,779	$	221,327,257		$	(225,401,140	)	$	(130,295	)	$	(4,193,399	)
Issuance of preferred stock	305,754		306			—	—		19,363,694			—			—			19,364,000
Reclassification of debt derivative	—		—			—	—		15,358,616			—			—			15,358,616
Conversion of preferred stock into common stock	(80,154	)	(80		)	13,359,001	1,336		(54,080		)	—			—			(52,824		)
Stock compensation	—		—			107,150	11		1,331,828			—			—			1,331,839
Net income	—		—			—	—		—			10,127,020			—			10,127,020
Balance December 31, 2010	225,600		226			121,255,748	12,126		257,327,315			(215,274,120		)	(130,295		)	41,935,252
Conversion of preferred stock into common stock	(34,600	)	(35		)	5,766,667	576		(541		)	—			—			—
Issuance of common stock	—		—			41,000,000	4,100		4,673,328			—			—			4,677,428
Stock compensation	—		—			62,100	6		344,184			—			—			344,190
Net loss	—		—			—	—		—			(7,301,645		)	—			(7,301,645		)
Balance December 31, 2011	191,000		191			168,084,515	16,808		262,344,286			(222,575,765		)	(130,295		)	39,655,225
Conversion of preferred stock into common stock	(8,935	)	(9		)	1,489,166	149		(140		)	—			—			—
Stock compensation	—		—			250,000	25		280,772			—			—			280,797
Net loss	—		—			—	—		—			(22,232,391		)	—			(22,232,391		)
Balance December 31, 2012	182,065		$	182		169,823,681	$	16,982	$	262,624,918		$	(244,808,156	)	$	(130,295	)	$	17,703,631

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

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GASCO ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Adjustment to reconcile net (loss) income to net cash (used in) provided by operating activities
Depletion, depreciation, amortization, accretion and impairment expense	19,218,694			3,525,806			3,565,672
Stock-based compensation	269,979			323,733			1,365,264
Gain on extinguishment of debt	—			—			(15,772,441		)
Change in fair value of derivative instruments	(2,462,142		)	(472,024		)	(9,727,956		)
Gain on sale of assets	(2,567,574		)	—			—
Amortization of debt discount, deferred expenses and other	4,126,759			3,301,796			13,734,361
Payment of deposit	(12,943		)	—			—
Changes in operating assets and liabilities:
Accounts receivable	(230,971		)	1,425,969			117,298
Inventory	180,629			(241,957		)	(799,092		)
Note receivable	500,000			—			—
Prepaid and other expenses	(1,803		)	(22,732		)	170,784
Accounts payable	(1,040,651		)	406,847			816,919
Revenue payable	411,042			(555,453		)	353,148
Accrued interest	—			(5,195		)	(250,965		)
Accrued expenses	172,700			(814,645		)	(56,161		)
Net cash (used in) provided by operating activities	(3,668,672		)	(429,500		)	3,643,851
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for acquisitions, development and exploration	(5,756,886		)	(8,790,336		)	(6,981,247		)
Cash paid for furniture, fixtures and other	(205,774		)	(890		)	(17,522		)
(Decrease) increase in advances from joint interest owners	(50,845		)	(1,065,902		)	1,164,414
Proceeds from property sales	19,199,265			10,000			24,309,000
Net cash provided by (used in) investing activities	13,185,760			(9,847,128		)	18,474,645
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit	2,000,000			2,000,000			1,000,000
Proceeds from issuance of common stock and warrants	—			10,000,000			—
Repayment of borrowings	(10,544,969		)	—			(29,000,000		)
Cash paid for debt and stock issuance costs	—			(1,351,947		)	(2,146,894		)
Repurchase of convertible notes	—			—			(54,400		)
Payment of deposit	—			—			(500,000		)
Repayment of convertible notes	—			(400,000		)	—
Net cash (used in) provided by financing activities	(8,544,969		)	10,248,053			(30,701,294		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	972,119			(28,575		)	(8,582,798		)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD	1,965,967			1,994,542			10,577,340
END OF PERIOD	$	2,938,086		$	1,965,967		$	1,994,542

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

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GASCO ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010

NOTE 1 — ORGANIZATION

Gasco Energy, Inc. (“Gasco,” the “Company,” “we,” “our” or “us”) was incorporated under the laws of the State of Nevada on April 21, 1997. Gasco 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.

NOTE 2 — GOING CONCERN

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of these consolidated financial statements.  However, due to the extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, the Company has not been able to recover its exploration and development costs as anticipated.  There is substantial doubt regarding the Company’s ability to generate sufficient cash flows from operations to fund its ongoing operations, and the Company currently anticipates that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013.  This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of the Company’s cash management strategy discussed below, some or all of which may not prove to be correct and may result in the Company’s inability to meet cash requirements prior to the second quarter of 2013.   As a result of these factors, there is substantial doubt about the Company’s ability to continue as a going concern.

The Company received notices from the NYSE MKT LLC (the “Exchange”) notifying it that it does not satisfy the continued listing standards set forth in the Exchange’s Company Guide. On December 6, 2012, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange set forth in Section 1003(f)(v) of the Company Guide because our common stock has traded at a low price per share for a substantial period of time.  In the notice, the Exchange predicated our continued listing on the Exchange on us effecting a reverse stock split of our common stock by June 6, 2013. On January 11, 2013, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange set forth in Section 1003(a)(iv) of the Company Guide, which applies if a listed company has sustained losses which are so substantial in relation to its overall operations or its existing financial resources, or its financial condition has become so impaired that it appears questionable, in the opinion of the Exchange, as to whether such company will be able to continue operations and/or meet its obligations as they mature. The Company submitted a plan of compliance (a “Plan”) to the Exchange on February 11, 2013, however, there can be no assurance that the Plan will be accepted by the Exchange or that the Company will be able to achieve compliance with the Exchange’s continued listing standards within the required time frame. Pursuant to the Plan, the Company intends to lower costs, rationalize assets, refocus our development program toward oil and liquids,

87

especially in the Green River Formation, and continue the California program with the potential goal of expanding the California model.  The Plan also considers strategic alternatives, including the debt restructuring and sales of assets, if necessary.  If the Plan is not accepted, the Company will be subject to delisting proceedings.

Furthermore, if the Plan is accepted but the Company is not in compliance with the continued listing standards of the Company Guide by June 30, 2013, or if the Company does not make progress consistent with the Plan, the Exchange staff will initiate delisting proceedings as it deems appropriate.

The Company’s prior revolving credit facility matured on June 29, 2012, and as of the date of this Annual Report, the Company has been unable to obtain a replacement facility on acceptable terms and is no longer actively in discussions to obtain a replacement facility.  Furthermore, the Company may not achieve profitability from operations in the near future or at all.  The Company had net losses and negative cash flow from operations for the year ended December 31, 2012 and at December 31, 2012 had an accumulated deficit of $244,808,156.

As of December 31, 2012, the Company had $45,168,000 aggregate principal amount of its 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”) outstanding.  The 2015 Notes bear interest at a rate of 5.50% per annum, payable in cash semi-annually in arrears on April 5th and October 5th of each year.  The Company’s failure to make an interest payment on the 2015 Notes, if not cured within 30 days, would result in a default under the indenture governing the 2015 Notes, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes. In addition, if the Company’s stock was delisted, it could result in a default under the Indenture.

The Company also has commitments under its gas transportation and processing agreements as discussed further in Note 16 — Commitments, herein.

Failure to generate operating cash flow or to obtain additional financing for the development of the Company’s properties could result in substantial dilution of our property interests or delay or cause indefinite postponement of further exploration and development of our prospects resulting in the possible loss of its properties. This could cause the Company to alter its business plans, including further reducing its exploration and development plans. In particular, the Company faces uncertainties relating to its ability to fund the level of capital expenditures required for oil and gas exploration and production activities. The Company intends to fund its anticipated cash requirements through the second quarter of 2013 primarily through cash on hand and cash flows from operations, although the Company cannot provide assurances that cash on hand and cash flows from operations will be sufficient to fund such requirements. If they are not, the Company’s ability to execute its growth plans as well as to fund its operating budget will be significantly limited, and its liquidity and results of operations may be materially adversely affected.

To continue as a going concern, the Company must generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide it with additional liquidity. The Company has engaged a financial advisor to assist it in evaluating such potential strategic alternatives. It is possible these strategic alternatives will require the Company to make a pre-package, pre-arranged or other type of filing for protection under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against the Company).  The Company’s ability to do so will depend on numerous factors, some of which are beyond its control.  If the Company is unable to generate sufficient operating cash flows, secure additional capital or otherwise restructure or refinance the business before the end of the second quarter of 2013, it will not have adequate liquidity to fund its operations and meet its obligations (including its debt payment obligations), the Company will not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed

88

against it).  The accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets, carrying amounts, or the amount and classification of liabilities that may result, should the Company be unable to continue as a going concern.

In order to address the Company’s liquidity constraints and in addition to its ongoing efforts to secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide it with additional liquidity, the Company has embarked on a cash management strategy to enhance and preserve as much liquidity as possible. This plan contemplates the Company, among other things:

·reducing expenditures by eliminating, delaying or curtailing discretionary and non-essential spending, and not designating any capital budget for 2013;

·managing working capital;

·delaying certain drilling projects;

·pursuing farm-out and other similar types of transactions to fund working capital needs;

·evaluating its options for the divestiture of certain assets;

·considering asset purchases through the issuance of equity;

·investigating merger opportunities; and

·restructuring and reengineering the Company’s organization and processes to reduce operating costs and increase efficiency.

The Company cannot provide any assurances that it will be successful in accomplishing any of these plans or that any of these actions can be effected on a timely basis, on satisfactory terms or maintained once initiated. Furthermore, the Company’s cash management strategy, if successful, may limit certain of its operational and strategic initiatives designed to grow its business over the long term.

NOTE 3 — SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Cash and Cash Equivalents

All highly liquid investments purchased with an original maturity of three months or less at the time of acquisition are considered to be cash equivalents.

Concentration of Credit Risk

The Company’s cash equivalents and derivative instruments are exposed to concentrations of credit risk. The Company manages and controls this risk by placing these funds and contracts with major financial institutions with high credit ratings.

The Company’s receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.

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Significant Customers

During the years ended December 31, 2012, 2011 and 2010  70%, 78% and 83%, respectively, of the Company’s production was sold to Anadarko Petroleum Corporation; during 2012, 2011 and 2010, 24%, 16% and 13% of the Company’s production was sold to EnWest Marketing LLC. Approximately 80% of the accounts receivable — revenue as of December 31, 2012 are due from Anadarko Petroleum Corporation. However, Gasco does not believe that the loss of a single purchaser, including Anadarko Petroleum Corporation, would materially affect the Company’s business because there are numerous other purchasers in the areas in which Gasco sells its production. However, the Company may not be able to find other purchasers who would purchase its production on terms comparable to its current arrangements.

Inventory

Inventory consists of pipe and tubular goods intended to be used in the Company’s oil and gas operations, and is stated at the lower of cost or market using the average cost valuation method.

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 $41,644, $76,973 and $123,753 of internal costs during the years ended December 31, 2012, 2011 and 2010, respectively. Additionally, the Company capitalized stock compensation expense related to our drilling consultants as further described in Note 8 — Stock-Based Compensation, herein. Costs associated with production and general corporate activities are expensed in the period incurred. During April 2010, the Company began charging a marketing fee related to the sale of its natural gas production to the wells in which it is the operator and, therefore, net income attributable to the outside working interest owners from such marketing activities of $112,301, $123,844 and $127,639 was recorded as a credit to proved properties during the years ended December 31, 2012, 2011 and 2010, respectively. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to 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.

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. The costs of unproved properties of $31,486,314 as of December 31, 2012, are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. If a determination is made that acreage will be expiring or that the Company does not plan to develop some of the acreage that is no longer considered to be prospective, an impairment of the acreage is recorded by reclassifying the costs to the full cost pool. The value of these acres for the purpose of recording the impairment is estimated by calculating a per acre value from the total unproved costs incurred for the applicable acreage divided by the total net acres owned by the Company. This per acre estimate is then applied to the acres that the Company does not plan to develop in order to calculate the impairment.

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During the year ended December 31, 2012, the Company reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification was comprised of a $7,000,000 decrease in the carrying value of its Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012.  During 2011, the Company reclassified $660,000 of acreage costs in Nevada into proved property as it relinquished control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects.  These costs were included in the ceiling test and depletion calculations during the quarter in which the reclassifications were made.

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 of 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-the-month oil and gas price during the 12-month period ended December 31, 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, June 30, 2012, September 30, 2012 and December 31, 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, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012, $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012, and $80.25 per barrel and $2.15 per Mcf of gas during the 12-month period ended December 31, 2012. Therefore, impairment expense of $16,486,000 was recorded during the year ended December 31, 2012. No impairment expense related to the Company’s oil and gas properties was recorded during 2011 or 2010.

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.

Capitalized Interest

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only

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for the period that activities are in progress to bring these projects to their intended use. No interest was capitalized during the three years ended December 31, 2012.

Facilities and Equipment

The Company’s oil and gas equipment is depreciated using the straight-line method over an estimated useful life of three 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 activity attributable to the outside working interest owners from the equipment rental of $(28,080), $(93,208) and $(16,109) was recorded as an adjustment to proved properties during the years ended December 31, 2012, 2011 and 2010, respectively.

Deferred Financing Costs

Deferred financing costs represent the costs associated with the issuance of financial instruments. The Company recorded amortization expense of $272,605, $258,456 and $13,888,901 related to these costs during the years ended December 31, 2012, 2011 and 2010, respectively. Expenses in 2012 and 2011 related to the amortization of the costs for the issuance of the 2015 Notes (see Note 5 — Convertible Senior Notes, herein). Expenses incurred in 2010 included the pro-rata portion of the debt issuance costs expensed for a conversion of 30% of the outstanding 2015 Notes.

Forward Sales Contracts

During March 2010, per the Base Contract for Sale and Purchase of Natural Gas that the Company has with Anadarko Energy Services Company, dated December 1, 2007, the Company entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of its gross production through 2013 from the Uinta Basin.  The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price. The Company accounts for its agreement to physically settle its production as an executory contract. The Company does not believe that the loss of this contract would materially affect its business because there are other potential purchasers in the areas in which the Company sells its production; however, the Company may not be able to find other purchasers who would purchase its production on terms comparable to its current arrangements.

Commodity Derivatives

From time to time, the Company has used 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 consolidated balance sheets. The Company’s management 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 6 — 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”) 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

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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 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 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.

	Year Ended December 31,
	2012			2011
Balance beginning of period	$	1,226,796		$	1,119,561
Liabilities incurred				1,405
Property dispositions	(493,178		)	—
Accretion expense	82,042			105,830
Balance end of period	$	815,660		$	1,226,796

See Note 4 — Asset Sales and Acquisitions, herein, for discussion of property dispositions.

Deferred Income from Sale of Assets

The deferred income from sale of assets represents the excess of proceeds received over the carrying value that was recorded in connection with the sale of the Company’s gathering assets and evaporative facilities in February 2010. This income is being amortized over the fifteen-year terms of the gathering and salt water disposal contracts which were entered into at the time of the sale.

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 December 31, 2012, the off-balance sheet arrangements and transactions that the Company had entered into included undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. See Note 16 — Commitments, herein, for additional discussion regarding certain gas transportation and processing agreements.

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Revenue Recognition

The Company records revenues from the sale 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. Gas imbalances at December 31, 2012 and 2011 were not significant.

Computation of Net Income (Loss) per Share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted-average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income (loss) per share of common stock includes both the vested and unvested shares of restricted stock. Diluted net income or loss per common share of stock is computed by dividing adjusted net income by the diluted weighted-average common shares outstanding.  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 the Company’s common stock, (iii) outstanding Series C Convertible Preferred Stock, par value $0.001 per share (“Preferred Stock”), which are convertible into shares of the Company’s common stock, and (iv) the Company’s outstanding 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 (which repurchases were assumed to have been made at the average market price of the common shares during the reporting period), is used to measure the dilutive impact of stock options, shares of restricted common stock and shares into which the 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 years ended December 31, 2012, 2011 and 2010.

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	For the Years Ended December 31,
	2012			2011			2010
Basic Net (Loss) Income Per Common Share
Numerator:
Basic net (loss) income	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Net earnings allocated to participating securities	—			—			942,721
Net (loss) income attributed to common stockholders	(22,232,391		)	(7,301,645		)	9,184,299
Denominator:
Weighted-average common shares outstanding	169,032,229			146,587,438			110,058,936
Basic net (loss) income per share	$	(0.13	)	$	(0.05	)	$	0.08

	For the Years Ended December 31,
	2012			2011			2010
Diluted Net (Loss) Income Per Common Share
Numerator:
Basic and diluted net (loss) income	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Denominator:
Diluted weighted-average common shares outstanding	169,032,229			146,587,438			110,058,936
Diluted net (loss) income per share	$	(0.13	)	$	(0.05	)	$	0.08

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

	For the Years Ended December 31,
	2012	2011	2010
2015 Notes and 2011 Notes	75,280,000	75,280,000	75,380,000
Preferred Stock	30,344,173	31,833,339	—
Common stock options	9,506,943	8,182,647	12,689,733
Warrants	30,250,000	30,250,000	—
Unvested restricted stock	336,000	184,500	191,300

Use of Estimates

The preparation of the financial statements for the Company in conformity with U.S. generally accepted accounting principals (“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 loss for the period presented.

Other Comprehensive Income (Loss)

The Company does not have any items of other comprehensive income (loss) for the years ended December 31, 2012, 2011 and 2010. Therefore, total comprehensive income (loss) is the same as net income (loss) for these periods.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of temporary differences between the accounting bases and the tax bases of the Company’s assets and liabilities.  The deferred tax assets and liabilities are computed using enacted tax rates in effect for the year in which the temporary differences are expected to reverse.

The Company’s policy is to recognize penalties and interest, if any, related to uncertain tax positions as general and administrative expense. The Company files income tax returns in the U.S. federal jurisdiction and various states.  There are currently no federal or state income tax examinations underway for these jurisdictions.  Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2009 and for state and local tax authorities for years before 2008.

Stock Compensation

The Company recognizes compensation cost for its common stock options and restricted stock grants as equity based awards based on estimated fair value of the award and records compensation expense over the requisite service period. The Company accounts for its stock appreciation rights (“SARs”) as liability based awards and accordingly recognizes the fair value of the vested SARs each reporting period. See Note 8 —Stock-Based Compensation, herein for further discussion.

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 4 — ASSET SALES AND ACQUISITIONS

Uinta Basin Joint Venture

On March 22, 2012, the Company closed a 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

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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. If the Company is not able to pay its share of the above costs, it may lose certain rights granted under the Development Agreement and related operating agreements, including the right to continue as operator or contract operator of the properties, the right to make proposals or elect to participate in operations under the Development Agreement or any operating agreement, the right to call, attend and vote at meetings of the operating committee, the right to transfer its interest in the properties and the joint venture, the right to acquire Wapiti’s interest in the properties under the right of first offer provisions of the Development Agreement and the right to acquire its pro rata share of additional properties acquired by Wapiti within the area of mutual interest identified in the Development Agreement. We have not incurred any costs to date and there is substantial doubt regarding our ability to fund our share of the drilling and completion 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, 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.  However, to the extent that Gasco Production Company, as operator under these agreements, becomes insolvent, bankrupt or is placed into receivership, it will be deemed to have resigned as operator or the other party may have a termination right.  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

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certain matters specified in the Development Agreement. The Operating Committee consists of two members from each of the Company 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 the Company or Wapiti upon six months’ advance notice.

Due to low natural gas prices and permitting delays, the Company did not drill any natural gas wells in Utah from the closing of the Uinta Basin Transaction through the remainder of 2012.

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.

The Company used approximately $10.5 million of the proceeds from the transaction to repay the borrowings under its prior revolving credit facility. The Company planned to use the remaining proceeds for its capital expenditures consisting of approximately $5.0 million 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 low natural gas prices and permitting delays, the Company did not drill any natural gas wells in Utah during the remainder of 2012.

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, 2010, 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, 2010.

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	For the Years Ended December 31,
	2012			2011			2010
Revenue as reported	$	8,879,673		$	18,335,608		$	20,262,099
Less: revenue from the Uinta Basin Transaction	1,206,145			6,382,289			7,052,865
Pro forma revenue	$	10,085,818		$	11,953,319		$	13,209,234
Net (loss) income as reported	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Less: operating loss resulting from the Uinta Basin Transaction	(2,390,235		)	(816,119		)	(2,441,482		)
Pro forma net (loss) income	$	(19,842,156	)	$	(6,485,526	)	$	12,568,502	)
Net (loss) income per share — basic and diluted as reported	$	(0.13	)	$	(0.05	)	$	0.08
Less net (loss) income per share - from the Uinta Basin Transaction	(0.01		)	(0.01		)	(0.02		)
Pro forma net (loss) income per share — basic and diluted	$	(0.12	)	$	(0.04	)	$	(0.10	)

Working Interest Acquisition

During December 2012, the Company acquired additional working interests in 32 producing wells in the Riverbend area of Utah in which the Company has a working interest and operates for $177,620. The acquired interests range from 4% to 10% per well with an average of 8% per well.

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 one well to be drilled on the acreage. The proceeds were recorded as a credit to unproved properties during the year ended December 31, 2012.

NOTE 5 - CONVERTIBLE SENIOR NOTES

As of December 31, 2012, 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 (the “2015 Indenture”), by and between the Company and Wells Fargo Bank, National Association, as trustee (the “Trustee”) 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, payable in cash semi-annually in arrears on April 5th and October 5th of each year.  The Company’s failure to make an interest payment on the 2015 Notes, if not cured within 30 days, or the delisting of the Company’s common stock from the Exchange, would result in a default under the 2015 Indenture, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes.

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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 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 LLC 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

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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, 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 December 31, 2012 and 2011 was $18,530,539 and $22,574,687, respectively.

NOTE 6 — 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, 2012, 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 consolidated balance sheets:

	Location on Consolidated	Fair Value at December 31,
	Balance Sheets	2012		2011
Natural gas derivative contracts	Current assets	$	—	$	865,358
Warrant derivative	Noncurrent liabilities	907,500		4,235,000

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2012, 2011 and 2010.

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	For the Years Ended December 31,
	2012			2011			2010
Realized gains on commodity instruments	$	1,255,948		$	524,460		$	1,588,235
Change in fair value of commodity instruments	(865,358		)	671,399			2,887,564
Change in fair value of warrant derivative	3,327,500			(199,375		)	—
Change in fair value of embedded derivative feature	—			—			6,840,392
Total realized and unrealized gains (losses) recorded	$	3,718,090		$	996,484		$	11,316,191

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

NOTE 7 — 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 constructed.

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.  The cryogenic processing facility was completed and placed in service on February 7, 2013.

Pursuant to the Chipeta Processing Agreement, the Company reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing.  Under this agreement, the Company committed to deliver, on average, at least 90% of its contracted cryogenic capacity of 25,000 Mcf/d during each monthly accounting period. 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, the Company 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 the Company’s 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 the Company’s reserves in excess of the Excluded Production.  The Excluded Production may be reduced if the Company fails to meet certain drilling investment targets.  The Company is committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and it is obligated to pay for any shortfall following the end of each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the agreement.

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In connection with the Amended and Restated Monarch Agreement, we also entered into the Questar Wet Line Agreement (the “QPC Transportation Agreement”), dated September 20, 2011, by and between Questar Pipeline Company (“QPC”), pursuant to which we agreed to enter into separate transportation services agreements for firm transportation services. We are currently committed to deliver to QPC for transportation services a minimum of 25,000 MMBtu/day.

See Note 16 — Commitments for further discussion.

NOTE 8 — STOCK-BASED COMPENSATION

The Company has outstanding common stock options, 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 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 the unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair value on that date. During the years ended December 31, 2012, 2011 and 2010, the Company recognized stock-based compensation as follows:

	Year Ended December 31,
	2012			2011			2010
Employee compensation	$	270,086		$	324,408		$	1,368,863
Consultant compensation (reduction in compensation)	(213		)	(1,349		)	(4,969		)
Total stock-based compensation	269,873			323,059			1,363,894
Less: consultant compensation expense (reduction in expense) capitalized as proved property	(106		)	(674		)	(1,370		)
Stock-based compensation expense	$	269,979		$	323,733		$	1,365,264

The Company did not recognize a tax benefit from stock-based compensation expense because the Company considers it more likely than not that the related deferred tax assets, which have been reduced by a full valuation allowance, will not be recognized.

The Company uses the Black-Scholes option-pricing model to estimate the fair value of the options at the grant date. The fair value of options granted to the Company’s employees and directors during 2012, 2011 and 2010 was calculated using the following assumptions:

	Employee and Director Options
	2012	2011	2010
Expected dividend yield	—	—	—
Expected price volatility	182-188%	80-137%	76-78%

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	Employee and Director Options
	2012	2011	2010
Risk-free interest rate	0.02 – 0.9%	0.1 – 1.3%	1.4 – 2.3%
Expected life of options	0.3 – 5 years	0.3 – 5 years	5 years

The weighted average grant-date fair value of options granted to employees and directors during 2012, 2011 and 2010 was $0.12, $0.08 and $0.23, respectively.

The expected stock price volatility assumption was determined using the historical volatility of the Company’s common stock over the expected life of the option.

Stock Options

During the year ended December 31, 2012, the Company granted 2,096,485 options to purchase common stock with exercise prices ranging from $0.16 to $0.30 per share. These options have a two-year vesting period and expire five years from the grant date.

During the year ended December 31, 2011, the Company granted 751,000 options to purchase common stock with exercise prices of $0.17 to $0.25. These options vest in equal portions over the following two-year period and expire five years from the grant date.

During the year ended December 31, 2010, the Company granted 1,371,000 options to purchase 50,000, 175,000, 646,000 and 500,000 shares of common stock with exercise prices of $0.34, $0.35, $0.36 and $0.37 per share, respectively. These options have a one- or two-year vesting period and expire five years from the grant date.

The following table summarizes the stock option activity in the equity incentive plans during the years ended December 31, 2012, 2011 and 2010:

	2012				2011				2010
	Stock Options		Weighted Average Exercise Price		Stock Options		Weighted Average Exercise Price		Stock Options		Weighted Average Exercise Price
Outstanding at beginning of year	8,182,647		$	1.37	12,689,733		$	1.63	12,096,672		$	1.82
Granted	2,096,485		$	0.24	751,000		$	0.22	1,371,000		$	0.36
Exercised	—		—		—		—		—		—
Forfeited	(17,179	)	$	0.22	(201,450	)	$	0.97	(86,547	)	$	1.64
Cancelled	(755,010	)	$	1.36	(5,056,636	)	$	1.75	(691,392	)	$	2.46
Outstanding at the end of year	9,506,943		$	1.04	8,182,647		$	1.37	12,689,733		$	1.63
Exercisable at December 31,	7,565,518		$	1.35	6,950,973		$	1.63	10,548,230		$	1.83

The following table summarizes information related to the outstanding and vested options as of December 31, 2012:

	Outstanding Options	Vested Options
Number of shares	9,506,943	7,565,518
Weighted-Average Remaining Contractual Life	2.4 years	2.2 years
Weighted-Average Exercise Price	$1.04	$1.35
Aggregate intrinsic value	$—	$—

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The aggregate intrinsic value in the table above is based on the Company’s closing common stock price of $0.07 as of December 31, 2012, which would have been received by the option holders had all option holders exercised their options as of that date.

There were no options exercised during the years ending December 31, 2012, 2011 and 2010.

The Company settles employee stock option exercises with newly issued common shares. SARs are settled with cash equal to the difference between the fair market value of the stock and the exercise price on the date of grant.

As of December 31, 2012, there was $241,557 of total unrecognized compensation cost related to non-vested options and SARs granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 2.4 years.

The following table summarizes the stock options outstanding at December 31, 2012:

Range of exercise Prices per Share	Number of Shares Outstanding	Number of Shares Exercisable	Weighted-Average Remaining Contractual Life of Shares Outstanding (years)
$0.00 – $0.99	5,169,060	3,227,635	2.8
$1.00 – $1.99	2,955,800	2,955,800	1.3
$2.00 – $2.99	300,000	300,000	2.5
$3.00 – $3.99	990,000	990,000	2.7
$4.00 – $4.99	40,000	40,000	5.5
$5.00 – $5.99	52,083	52,083	3.3
Total	9,506,943	7,565,518	2.4

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 provided 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 its common stock to these directors.  As of December 31, 2012, the liability for February SARs was approximately zero. The February SARs provided 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 was  less, over (ii) $0.30, which was 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 vested on

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January 31, 2013 and were automatically exercised on February 1, 2013. 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.

Restricted Stock

The following table summarizes the restricted stock activity for the years ending December 31, 2012, 2011 and 2010:

	2012				2011				2010
	Restricted Stock		Weighted Average Fair Value		Restricted Stock		Weighted Average Fair Value		Restricted Stock		Weighted Average Fair Value
Outstanding at the beginning of the year	184,500		$	0.36	191,300		$	0.70	140,500		$	2.39
Granted	250,000		$	0.18	75,000		$	0.25	150,000		$	0.37
Vested	(98,500	)	$	0.36	(68,900	)	$	0.93	(78,500	)	$	2.51
Forfeited	—		—		(12,900	)	$	1.79	(20,700	)	$	2.83
Outstanding at the end of the year	336,000		$	0.22	184,500		$	0.36	191,300		$	0.70

The total grant date fair value of the restricted shares vested during the years ending December 31, 2012, 2011 and 2010 was $35,460, $64,204 and $197,075, respectively.

As of December 31, 2012, there was $64,347 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a weighted-average period of 2.4 years.

NOTE 9 — OIL AND GAS PROPERTY

The Company’s oil and gas properties are summarized in the following table:

	As of December 31,
	2012			2011
Proved properties	$	264,814,427		$	268,793,463
Unproved properties	31,486,314			36,938,162
Wells in progress	—			1,938,691
Facilities and equipment	1,493,314			1,502,921
Total	297,794,055			309,173,237
Less accumulated depletion, depreciation, amortization and impairment	(253,092,709		)	(233,987,193		)
	$	44,701,346		$	75,186,044

The following table presents information regarding the Company’s net costs incurred in the purchase of proved and unproved properties and in exploration and development activities:

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	For the Years Ended December 31,
	2012		2011		2010
Property acquisition costs:
Unproved	$	2,490,305	$	2,094,969	$	313,238
Proved	177,620		—		481,947
Exploration costs	2,599,168		3,864,866		968,683
Development costs	13,818		2,506,176		5,151,909
Total	$	5,280,911	$	8,466,011	$	6,915,777

At December 31, 2012 and 2011, the Company’s unproved properties consist of leasehold acquisition and exploration costs in the following areas:

	2012		2011
Utah	$	29,097,179	$	35,335,449
California	2,389,135		1,602,713
	$	31,486,314	$	36,938,162

During the year ended December 31, 2012, the Company reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification was comprised of a $7,000,000 decrease in the carrying value of its Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012.  During 2011, the Company reclassified $660,000 of acreage costs in Nevada into proved property as it relinquished our control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects.  These costs were included in the ceiling test and depletion calculations during the quarter in which the reclassifications were made.

Depreciation, depletion and amortization expense per Mcfe was $1.07, $0.91 and $0.82 for the years ended December 31, 2012, 2011 and 2010, respectively. Impairment expense was $6.44 per Mcfe during the year ended December 31, 2012. No impairment expense was recorded during the years ended December 31, 2011 and 2010.

The following table sets forth a summary of unproved oil and gas property costs as of December 31, 2012, by the year in which such costs were incurred.

	Balance		Costs Incurred During Years Ended December 31,
	12/31/12		2012		2011		2010		Prior
Acquisition costs	$	23,445,306	$	1,762,979	$	673,351	$	166,772	$	20,842,204
Exploration costs	8,041,008		727,326		1,503,763		146,467		5,663,452
Total	$	31,486,314	$	2,490,305	$	2,177,114	$	313,239	$	26,505,656

The Company believes that the majority of its unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further, or by making decisions that further exploration and development activity will not occur.

NOTE 10 — CREDIT FACILITY

The Company’s prior $250 million revolving credit facility matured on June 29, 2012 and was repaid in full.

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While the Company has attempted to secure a replacement facility, as of the date of this Annual Report, it has been unable to do so on acceptable terms and is no longer actively in discussions to obtain a replacement facility.  There can be no assurance that the Company will be able to adequately finance its operations or execute its existing short-term and long-term business plans, and its liquidity and results of operations are likely to be materially adversely affected if the Company is unable to generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide it with additional liquidity.

NOTE 11 — 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 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 December 31, 2012 and 2011 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
December 31, 2012
Liabilities:
Warrant derivatives	$	—	$	—	$	907,500	$	907,500
December 31, 2011
Assets:
Commodity derivatives	$	—	$	856,358	$	—	$	856,358
Liabilities:
Warrant derivatives	$	—	$	—	$	4,235,000	$	4,235,000

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As of December 31, 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 December 31, 2012:

(i)the warrant derivative liability would remain unchanged if the trading price of Gasco’s common stock was reduced to zero, and would increase by approximately $1.9 million for a $0.10 increase in the trading price of our common stock.

(ii)the warrant derivative liability would remain unchanged with a 10% increase in the volatility rate and would decrease by approximately $302,000 with a 10% decrease in the volatility rate.

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 12/31/2011	30,250,000	$	0.35	54.1 months
Warrants issued	—			—
Warrants outstanding as of 12/31/2012	30,250,000	$	0.35	42.0 months

The significant assumptions used in the valuation of the warrant derivative liability are as follows:

Exercise price	$0.35 per share
Volatility	105%
Remaining Term of Warrants	41-43 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:

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	For the Year Ended December 31,
	2012			2011
Balance as of January 1,	$	(4,235,000	)	$	—
Total losses (realized or unrealized):
Included in earnings	3,327,500			(199,375		)
Included in other comprehensive income	—			—
Issuances	—			(4,035,625		)
Settlements	—			—
Transfers in and out of Level 3	—			—
Balance as of December 31	$	(907,500	)	$	(4,235,000	)
Change in unrealized gains included in earnings relating to instruments still held as of December 31	$	3,327,500		$	(199,375	)

The carrying amounts of cash and cash equivalents, accounts 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 $28,833,000 and $31,443,000 as of December 31, 2012 and 2011, respectively, was determined using the income valuation technique and option pricing model. This valuation is classified as a Level 3 in the fair value hierarchy as it relies primarily on unobservable pricing inputs.

NOTE 12 - STOCKHOLDERS’ EQUITY

The Company’s capital stock as of December 31, 2012 and 2011 consists of 600,000,000 authorized shares of common stock, par value $0.0001 per share, 20,000 authorized shares of Series B Convertible Preferred stock, par value $0.001 per share, and 2,000,000 authorized shares of Series C Convertible Preferred stock  (“Preferred Stock”).

Series B Convertible Preferred Stock

As of December 31, 2012 and 2011, the Company had no shares of Series B Preferred Stock issued and outstanding.

Series C Convertible Preferred Stock

As of December 31, 2012 and 2011, the Company had 182,065 and 191,000 shares, respectively, of Preferred Stock issued and outstanding. The Preferred Stock is entitled to receive cash dividends and other distributions declared on the common stock, as well as distributions upon liquidation, dissolution or any other winding up event, in each case as set forth in the Certificate of Designations. The Preferred Stock does not have any right or power to vote on any question or in any proceeding or to be represented at or to receive notice of any meeting of holders of capital stock of the Company, except as required by law. The Preferred Stock may not be redeemed by the Company at any time.

Each share of Preferred Stock is convertible at the option of the holder thereof, at any time, into the number of fully paid and nonassessable shares of common stock equal to the quotient of (1) one hundred dollars ($100.00) divided by (ii) the conversion price applicable to shares of common stock as determined pursuant to the Indenture and in effect at the time of conversion (and any fractional shares will be paid in

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cash). As for the 2015 Notes, a holder may not convert all or any portion of such holder’s Preferred Stock into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion beneficially own more than the Maximum Ownership Percentage (as defined in the Indenture governing the 2015 Notes).

During the first quarter of 2011, 36,400 shares of Preferred Stock were converted into 5,766,667 shares of common stock. During March 2012, 8,935 shares of Preferred Stock were converted into 1,489,166 shares of common stock.

Common Stock

The Company had 169,823,681 shares of common stock issued and 73,700 shares held in treasury as of December 31, 2012. The common shareholders are entitled to one vote per share on all matters to be voted on by the shareholders; however, there are no cumulative voting rights. The common shareholders are entitled to dividends and other distributions as may be declared by the board of directors. Upon liquidation or dissolution, the common shareholders will be entitled to share ratably in the distribution of all assets remaining available for distribution after satisfaction of all liabilities and payment of the liquidation preference of any outstanding preferred stock.

As of December 31, 2012, the Company had 9,506,943 shares of common stock issuable upon exercise of outstanding options, 336,000 shares of unvested restricted stock and additional 11,466,640 shares of common stock available for issuance under its long term incentive plan.

As of December 31, 2012, assuming all of the 2015 Notes are converted at the applicable conversion prices and all of the Preferred Stock is converted, the number of shares of our common stock outstanding would increase by approximately 105,624,173 shares of common stock resulting in an increase in the outstanding shares as December 31, 2012 to approximately 275,374,154 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).

The Company’s common stock equity transactions during 2012 and 2011 are described as follows:

On June 15, 2011, the Company closed its underwritten registered offering of 25,000,000 units (the “June Offering”) at a price of $0.24 per unit, for gross proceeds of $6.0 million. Each unit consisted of (i) one share of common stock and (ii) one warrant to purchase 0.75 of a share of common stock. The shares of common stock and June Warrants were issued separately. The net proceeds from the June Offering were $5,108,143, after deducting underwriting discounts and commissions and other offering expenses of $891,857.

On August 3, 2011, the Company closed an underwritten registered offering of 16,000,000 units (the “August Offering” and collectively with the June Offering, the “Offerings”) at a price of $0.25 per unit, for gross proceeds of $4.0 million.  Each unit consisted of (i) one share of common stock and (ii) one warrant to purchase 0.71875 of a share of common stock .  The shares of common stock and August Warrants were issued separately. The net proceeds from the August Offering were $3,604,910, after deducting underwriting discounts, commissions and other offering expenses of $395,090.

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

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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 sheet with changes in their fair value reported in earnings. The June Warrants and the August Warrants were recorded at their fair values of $1,850,625 and $2,185,000, respectively, at the issuance dates. 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 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.

During the first quarter of 2012 and 2011, 8,935 and 34,600 shares of Preferred Stock were converted into 1,489,166 and 5,766,667 shares of common stock, respectively.

During the years ended December 31, 2012 and 2011, the Company’s Board of Directors approved the issuance of 250,000 and 75,000 restricted shares of common stock, respectively, to certain of the Company’s employees. The restricted shares vest at varying schedules within three to five years. The shares fully vest upon certain events, such as a change in control of the Company, expiration of the individual’s employment agreement and termination by the Company of the individual’s employment without cause.  Any unvested shares are forfeited upon termination of employment for any other reason. The shares of restricted stock are considered issued and outstanding at the date of grant and are included in shares outstanding upon vesting for the purposes of computing diluted earnings per share.

NOTE 13 - STATEMENTS OF CASH FLOWS

During the year ended December 31, 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.

·Additions to oil and gas properties included in accounts payable of $454,000.

·Write-off of fully depreciated furniture, fixtures and equipment of $252,424.

During the year ended December 31, 2011, the Company’s non-cash investing and financing activities consisted of the following transactions:

·Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $1,405.

·Reduction in stock-based compensation expense of $674 capitalized as proved property.

·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 $830,000.

Cash paid for interest during the years ended December 31, 2012, 2011 and 2010 was $2,598,381, $3,786,641 and $4,095,566, respectively. There was no cash paid for income taxes during the years ended December 31, 2012, 2011 and 2010.

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NOTE 14 — INCOME TAXES

The provision (benefit) for income taxes for the years ended December 31, 2012, 2011 and 2010 consists of the following:

	2012			2011			2010
Current taxes:
Federal	$	—		$	—		$	—
State	—			—			—
Deferred taxes:
Deferred provision (benefit)	(5,615,970		)	55,013,560			12,151,778
Less: valuation allowance	5,615,970			(55,013,560		)	(12,151,778		)
Net income tax provision (benefit)	$	—		$	—		$	—

A reconciliation of the provision (benefit) for income taxes computed at the statutory rate to the provision for income taxes as shown in the consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010 is summarized below:

	2012			2011			2010
Tax provision (benefit) at federal statutory rate	$	(7,781,337	)	$	(2,555,576	)	$	3,544,457
State taxes, net of federal tax effects	(524,611		)	(167,581		)	2,573,856
Change in tax rate from prior year	(642		)	7,030			25,267
Permanent items and other	2,690,620			(243,639		)	6,008,198
Loss of NOL from Sec. 382 Limitation	—			57,973,328			—
Valuation allowance	5,615,970			(55,013,560		)	(12,151,778		)
Net income tax provision (benefit)	$	—		$	—		$	—

The components of the deferred tax assets and liabilities as of December 31, 2012 and 2011 are as follows:

	2012			2011
Deferred tax assets:
Federal and state net operating loss carryovers	$	20,790,664		$	20,172,061
Oil and gas property and other property, plant & equipment	1,995,698			—
Deferred compensation	2,357,410			2,344,155
Deferred gain on sale of assets	920,235			994,149
Accrued salaries and bonus	88,169			82,049
Asset Retirement Obligation	304,728			457,535
Other	130,920			316,516
Total deferred tax assets	26,587,824			24,366,465
Less: valuation allowance	(25,419,167		)	(19,803,198		)
	1,168,657			4,563,268
Deferred tax liabilities:
Oil and gas property and other property, plant & equipment	—			4,314,889
Derivatives	1,168,657			248,379
Total deferred tax liabilities	1,168,657			4,563,268
Net deferred tax asset	$	—		$	—

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The Company has $54,541,750 of net operating loss carryovers for federal income tax purposes as of December 31, 2012, of which $3,030,233 is not benefited for financial statement purposes as it relates to tax deductions that deviate from compensation expense for financial statement purposes. The benefit of these excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce taxes payable.  The Company has $41,063,071 of net operating loss carryovers for state income tax purposes as of December 31, 2012, of which the above excess tax deductions have similarly not been benefited for financial statement purposes. The net operating losses may offset against taxable income through the year ended December 31, 2032. A portion of the net operating loss carryovers begins expiring in 2019.  The Company has analyzed the implications of an ownership change pursuant to IRC Section 382 on its net operating losses and has made appropriate adjustments to the federal and state net operating loss carryovers and related deferred tax assets in its financial statements.  Such adjustments have no impact on the financial statements as the Company’s deferred tax assets net of liabilities are subject to a full valuation allowance.  The Company provided a valuation allowance against its net deferred tax asset of $25,301,485 and $19,803,198 as of December 31, 2012 and 2011, respectively, since it believes that it is more likely than not that the net deferred tax assets will not be fully realized on future income tax returns. The decrease and increase in the valuation allowance for 2012 and 2011 is $5,498,287 and $(55,013,560), respectively.

NOTE 15 — RELATED PARTY TRANSACTIONS

Certain of the Company’s directors and officers have working and/or overriding royalty interests in oil and gas properties in which the Company has an interest.  It is expected that the directors and officers may participate with the Company in future projects. All participation by directors and officers will continue to be approved by the disinterested members of the Company’s Board of Directors.

NOTE 16 - COMMITMENTS

The Company leases approximately 11,170 square feet of office space in Denver, Colorado under a lease which terminates on May 31, 2017. The Company’s future rental payments due under this lease are as follows:

Year Ending December 31,	Annual Rentals
2013	$	193,613
2014	227,123
2015	236,432
2016	247,602
2017	83,775
	$	988,545

Rent expense for the years ended December 31, 2012, 2011 and 2010 was $153,509, $142,090 and $166,334, respectively.

As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells.  If the Company does not pay such commitments, the acreage positions or wells may be lost.

On February 8, 2011, the Company entered into new employment agreements with its two key officers, W. King Grant and Michael K. Decker, which replace in their entirety the employment agreements previously in effect. The agreements were effective January 1, 2011 and the total minimum compensation under the agreements is an aggregate of $590,000 per annum and the initial terms of the agreements will

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expire on the second anniversary of the effective date and will automatically renew for additional one-year terms unless either party elects not to renew or the agreements are otherwise terminated in accordance with their terms. These agreements were renewed through January 1, 2014. The agreements contain clauses regarding termination of the officers that could require payment of an amount ranging from 1.5 to two times annual compensation.

During March 2010, per the Base Contract for Sale and Purchase of Natural Gas that the Company has with Anadarko Energy Services Company, dated December 1, 2007, the Company entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of its gross production through 2013 from the Uinta Basin.  The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price.

The Company has gathering, processing, and transportation through-put commitments with Monarch, Chipeta and Questar Pipeline Company that require delivery of a fixed determinable quantity of gas production. The aggregate minimum commitment to deliver is 25,000 Mcf of natural gas per day to Monarch for gathering and 25,000 Mcf of natural gas per day to Chipeta for processing. The aggregate minimum commitment is 25,000 MMBtu of natural gas per day to QPC for transportation services. These contracts expire at various dates through 2023 and the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. The annual minimum payments for the next five years and thereafter are presented below:

Year Ending December 31,	Annual Commitments
2013	$	6,006,803
2014	6,482,782
2015	6,799,638
2016	7,157,293
2017	5,046,652
Thereafter	27,551,825
	$	59,044,993

These amounts are owed regardless of whether the Company delivers any natural gas quantities to the applicable parties. As described in Note 2 — Going Concern, herein, there is substantial doubt regarding the Company’s ability to generate sufficient cash flows from operations to fund its ongoing operations. If the Company is unable to fund additional drilling projects, and based on its December 31, 2012 reserve estimates, assuming no future drilling and constant gas prices, it estimates that it could have a possible minimum production shortfall of approximately 54,000 MMcf valued at approximately $37 million on an undiscounted gross basis.

The Company is considering several alternatives to mitigate the estimated production shortfall such as the sale of its firm commitment positions, seeking relief from the firm commitments because of the permitting delays in the area and the purchase of production quantities to meet its minimum production requirements. Also, future increases in gas prices would increase the related reserve estimates and reduce the possible shortfalls. However, there is no assurance that the Company will be successful in accomplishing these actions should there be a shortfall. Accordingly, the Company has not accrued the possible obligation as of December 31, 2012 as it is not probable or reasonably estimable.

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NOTE 17 - EMPLOYEE BENEFIT PLANS

The Company adopted a 401(k) profit sharing plan (the “401(k) Plan”) in October 2001 available to employees who meet the 401(k) Plan’s eligibility requirements.  The 401(k) Plan is a defined contribution plan.  The Company may make discretionary contributions to the 401(k)Plan and is required to contribute 3% of each participating employee’s compensation to the 401(k) Plan.  The contributions made by the Company totaled $129,354, $118,573 and $127,169 during the years ended December 31, 2012, 2011 and 2010, respectively.

NOTE 18 — SELECTED QUARTERLY INFORMATION (Unaudited)

The following represents selected quarterly financial information for the years ended December 31, 2012 and 2011. In March 2012, the Company closed the Uinta Basin Transaction whereby the Company sold to Wapiti an undivided 50% of its interest in certain of its Uinta Basin producing oil and gas assets, and transferred to Wapiti an undivided 50% of its interest in its Uinta Basin non-producing oil and gas assets, as further described in Note 4 — Asset Sales and Acquisitions.

	For the Quarter Ended
2012	March 31,			June 30,			September 30,			December 31,
Gross revenue	$	3,180,267		$	1,603,873		$	1,808,625		$	2,286,908
Gross profit (loss) from oil and gas operations	826,124			(66,983		)	506,244			949,574
Net loss (a)	(5,058,144		)	(5,151,559		)	(3,170,910		)	(8,851,778		)
Net loss per share
Basic and diluted	(0.03		)	(0.03		)	(0.02		)	(0.05		)

(a)The increase in the net loss during the fourth quarter of 2012 is primarily due to a $7,415,000 property impairment recorded during the period.

	For the Quarter Ended
2011	March 31,			June 30,		September 30,			December 31,
Gross revenue	$	4,269,105		$	5,755,471	$	4,577,127		$	3,733,905
Gross profit (loss) from oil and gas operations	2,125,958			3,146,353		2,050,485			(532,796		)
Net (loss) income(b)	(1,592,477		)	30,169		(1,266,533		)	(4,472,804		)
Net (loss) income per share
Basic and diluted	(0.01		)	0.00		(0.01		)	(0.03		)

(b)The increase in net loss and the decrease in gross profit from oil and gas operations during the fourth quarter of 2011 is primarily due to the increase in lease operating expense due to the increased workover activity in 2011.

NOTE 19— LEGAL PROCEEDINGS

The Company is party to various legal proceedings arising out of the normal course of business.  The most significant legal proceedings to which the Company is subject are summarized below.  The ultimate outcome of the Clean Water Act Compliance Order matter cannot presently be determined, nor can the

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liability that could potentially result from an adverse outcome be reasonably estimated at this time.  The Company does not expect the outcome of these proceedings to have a material adverse effect 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 (the “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: (i) once when it constructed an access road to a future well location in either 2004 or 2005 and (ii) 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 the 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 the 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.  On September 5, 2012, the EPA, represented by the Department of Justice, answered, and the United States separately counterclaimed for an injunction seeking substantially the same relief that the EPA seeks in the compliance order but also requested civil penalties for each day of alleged discharges of fill material and each day of alleged violation of the compliance order.  The Company has answered the EPA’s counterclaim.  In late January 2013, pursuant to a Scheduling Order before the court, the Company submitted a brief in support of its claims under the original suit filed in June 2012.

NEPA Suit

In June 2012, the BLM signed and issued a Rule of Decision on the EIS that authorizes the development of the Company’s Uinta Basin field upon federal lands in Duchesne and Uintah Counties, Utah.  This field includes the Company’s core Riverbend Project.  However on January 18, 2013, certain non-governmental environmental organizations, including the Southern Utah Wilderness Alliance, or SUWA, filed a suit against the BLM, challenging the ROD issued by that agency.  In its complaint, SUWA alleges that the BLM failed to comply with the requirements of NEPA and its implementing regulations.  SUWA was seeking, among other things, that the ROD and EIS be set aside, the effect of which would void the BLM’s authorization for the Company to proceed with its planned project. Only recently, on February 13, 2013, SUWA voluntarily submitted notice of dismissal of the suit to the District Court. Because SUWA voluntarily withdrew its suit, it has the opportunity to refile the suit at a later date. Whether SUWA will refile this suit at a later date is currently unknown to the Company. While any future suit by SUWA or any other third party that seeks to set aside the ROD issued by the BLM for the Company’s planned project in the Uinta Basin field in Utah could, if successfully, have a material adverse effect on the Company’s ability to perform the planned project, the Company would not expect the outcome of such proceeding to have a material adverse effect on the Company’s financial position, results of operations or cash flows.

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Hat Creek Settlement

In February 2013, the Company settled a claim with one of its working interest owners, Hat Creek Energy LLC (“Hat Creek”), in connection with a well that was operated by the Company and owned by both parties. Hat Creek filed the claim on April 2, 2012 in the Denver District Court, alleging that Hat Creek did not consent to certain reworking operations performed by the Company in violation of the joint operating agreement, and that Hat Creek’s working interest in the well was impaired as a result.  Hat Creek sought damages of not less than $200,000, and the Company sought counterclaim damages for receivables owed by Hat Creek and for the reworking costs.  The Company settled this claim for $315,000 consisting of a $160,000 cash payment to Hat Creek and the forgiveness of $155,000 in accounts receivable owed to the Company by Hat Creek. In addition, the settlement provides that the Company will receive Hat Creek’s ownership interest in the well.  The final settlement has been accrued in the accompanying consolidated financial statements and is dependent upon the completion of the final settlement documents.

NOTE 20 — 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 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.

NOTE 21 — SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)

The following reserve quantity and future net cash flow information for the Company represents estimated proved reserves located in the United States. The reserves as of December 31, 2012, 2011 and 2010 have been estimated by Netherland, Sewell and Associates, Inc., independent petroleum engineers. The determination of oil and gas reserves is based on estimates, which are highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available.

The standardized measure of discounted future net cash flows is prepared under the guidelines set forth by the Securities and Exchange Commission (the “SEC”) which requires the use of the average, first-of-the-month price. The oil and gas prices weighted by production over the lives of the proved reserves used as of December 31, 2012, 2011 and 2010 were $80.25 per Bbl and $2.15 per Mcf of gas, $81.35 per Bbl and $3.59 per Mcf of gas, and $64.97 per Bbl of oil and $3.62 per Mcf of gas, respectively. Future production costs are based on year-end costs and include severance taxes. Each property that is operated by the Company is also charged with field-level overhead in the reserve calculation. The present value of future cash inflows is based on a 10% discount rate.

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Reserve Quantities

	Gas		Oil
	Mcf		Bbls
Proved Reserves:
Balance, December 31, 2009	44,229,950		450,858
Extensions and discoveries	—		—
Revisions of previous estimates (a)	632,807		68,912
Sales of reserves in place	(2,213,000	)	(19,000	)
Purchases of reserves in place	1,181,442		4,421
Production	(4,105,139	)	(40,532	)
Balance, December 31, 2010	39,726,060		464,659
Extensions and discoveries	—		33,382
Revisions of previous estimates (a)	732,040		40,866
Sales of reserves in place	—		—
Purchases of reserves in place	—		—
Production	(3,659,790	)	(36,852	)
Balance, December 31, 2011	36,798,310		502,055
Extensions and discoveries	—		10,400
Revisions of previous estimates (b)	(10,110,081	)	(28,351	)
Sales of reserves in place	(12,251,600	)	(210,500	)
Purchases of reserves in place	573,600		3,800
Production	(2,406,512	)	(25,805	)
Balance, December 31, 2012	12,603,717		251,599

	Gas	Oil
	Mcf	Bbls
Proved Developed Reserves
Balance, December 31, 2012	12,603,717	251,599
Balance, December 31, 2011	36,798,310	502,055
Balance, December 31, 2010	39,726,060	464,659

(a)Better than anticipated existing well performances related to behind pipe reserves that began producing during both years yielded positive reserve revisions during the years ended December 31, 2011 and 2010.

(b)Downward revisions during the year ended December 31, 2012 are comprised of the following:

	Gas		Oil
	Mcf		Bbls
Commodity price decreases	(5,489,900	)	(30,400	)
Lease operating expense estimate revisions	(3,558,800	)	(25,300	)
Revision due to well performance	(1,061,381	)	27,349
Revisions of previous estimates	(10,110,081	)	(28,351	)

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Standardized Measure of Discounted Future Net Cash Flows

	December 31,
	2012			2011			2010
Future cash flows	$	47,303,900		$	172,844,800		$	173,982,700
Future production and development costs	(31,144,200		)	(92,505,100		)	(91,157,000		)
Future income taxes (a)	—			—			—
Future net cash flows before discount	16,159,700			80,339,700			82,825,700
10% discount to present value	(5,842,100		)	(35,689,700		)	(35,898,700		)
Standardized measure of discounted future net cash flows	$	10,317,600		$	44,650,000		$	46,927,000

(a)The calculations of standardized measure do not include deductions for future income tax expenses because the tax basis of the properties involved and the future tax deductions were greater than the net cash flows from the proved oil and gas reserves for the years ended December 31, 2012, 2011 and 2010.

Changes in the Standardized Measure of Discounted Future Net Cash Flows

	For the Years Ended December 31,
	2012			2011			2010
Standardized measure of discounted future net cash flows at the beginning of year	$	44,650,000		$	46,927,000		$	35,561,400
Sales of oil and gas produced, net of production costs	(3,919,636		)	(9,549,780		)	(13,643,312		)
Net changes in prices and production costs	(12,419,867		)	1,499,400			12,137,633
Extensions and discoveries, net of future production and development costs	45,618			224,640			—
Previously estimated development costs incurred	13,818			1,781,487			4,411,807
Changes in estimated future development costs	(872,576		)	148,872			2,556,404
Revisions of previous quantity estimates	(7,515,377		)	1,096,031			1,154,884
Purchases of reserves in place	647,899			—			2,228,917
Sales of reserves in place	(14,681,586		)	—			(1,663,100		)
Accretion of discount	3,861,014			4,073,524			3,398,429
Other	508,293			(1,551,174		)	783,938
Standardized measure of discounted future net cash flows at the end of year	$	10,317,600		$	44,650,000		$	46,927,000

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ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to 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 December 31, 2012, at the reasonable assurance level.

Changes in Internal Controls over Financial Reporting during the Fourth Quarter of 2012

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.

In accordance with Item 308 of SEC Regulation S-K, management is required to provide an annual report regarding our internal control over financial reporting. This report, which includes management’s assessment of the effectiveness of our internal control over financial reporting, is found below.

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed, under the supervision of the Company’s principal executive and financial officers, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

121

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on the assessment and those criteria, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2012.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 was audited by KPMG LLP, the independent registered public accounting firm who audited the Company’s financial statements for the year ended December 31, 2012, as stated in its report that follows.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Gasco Energy, Inc.:

We have audited Gasco Energy, Inc.’s (the Company) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

122

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated March 6, 2013 expressed an unqualified opinion on those consolidated financial statements.

The consolidated financial statements referred to above have been prepared assuming that the Company will continue as a going concern. As discussed in note 2 to the consolidated financial statements, the Company has suffered recurring losses and negative cash flows from operations that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ KPMG LLP

Denver, Colorado
March 6, 2013

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ITEM 9B — OTHER INFORMATION

None.

PART III

ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item will be included in the definitive proxy statement relating to the Company’s 2013 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

The Board of Directors of the Company has adopted several governance documents to guide the operation and direction of the Board and its committees, including our Corporate Code of Business Conduct and Ethics, Financial Code of Ethics, and charters for the Audit Committee, Compensation Committee and Nominating Committee. Each of these documents is available on our website at www.gascoenergy.com and stockholders may obtain a printed copy, free of charge, by sending a written request to Gasco Energy, Inc., 8 Inverness Drive East, Suite 100, Englewood, Colorado 80112, Attn: Corporate Secretary. To the extent required by SEC rules, we intend to disclose any amendments to Corporate Code of Business Conduct and Ethics and any waiver of a provision thereof, on our website within four business days following any such amendment or waiver, or within any other period that may be required under SEC rules from time to time.

ITEM 11 — EXECUTIVE COMPENSATION

The information required by this item will be included in the definitive proxy statement relating to the Company’s 2013 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item will be included in the definitive proxy statement relating to the Company’s 2013 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item will be included in the definitive proxy statement relating to the Company’s 2013 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

124

ITEM 14 — PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item will be included in the definitive proxy statement relating to the Company’s 2013 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.

PART IV

ITEM 15 — EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

(a)	1. See “Index to Financial Statements” under Item 8 on page 80.
	2. Financial Statement Schedules — none.
	3. Exhibits — See Index to Exhibits, below.

INDEX TO EXHIBITS

3.1	Restated and Amended Articles of Incorporation (incorporated herein 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 herein 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 herein 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	Certificate of Amendment to Articles of Incorporation dated September 20, 2010 (incorporated herein 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).
3.5	Second Amended and Restated Bylaws of Gasco Energy, Inc. dated April 8, 2009 (incorporated herein 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).
3.6	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).
4.1	Indenture (including form of 2015 Note) dated as of June 25, 2010 between Gasco Energy, Inc. and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).

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4.2	First Supplemental Indenture dated as of September 22, 2010 between Gasco Energy, Inc. and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.7 to the Company’s Form 10-Q dated September 30, 2010, filed on November 2, 2010, File No. 001-32369).
4.3	Guaranty Agreement dated as of June 25, 2010 among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.4	Investor Rights Agreement dated as of June 25, 2010 among Gasco Energy, Inc., CNH CA Master Account, L.P. and AQR Absolute Return Master Account, L.P. (incorporated herein by reference to Exhibit 4.3 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.5	Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 8-K dated June 10, 2011, filed on June 10, 2011, File No. 001-32369).
4.6	Form of Warrant (incorporated herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated July 28, 2011, filed on July 29, 2011, File No. 001-32369).
# 10.1	1999 Stock Option Plan (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 10KSB for the fiscal year ended December 31, 1999, filed on April 14, 2000, File No. 000-26321).
# 10.2	Form of Stock Option Agreement under the 1999 Stock Option Plan (incorporated herein by reference to Exhibit 10.8 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.3	Stock Option Agreement dated January 2, 2001 between Gasco and Mark A. Erickson (incorporated herein by reference to Exhibit 10.9 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.4	Form of Stock Option Agreement between Gasco and each of the individuals named therein (incorporated herein by reference to Exhibit 4.4 to the Company’s Form S-8 Registration Statement (Reg. No. 333-122716), filed on February 10, 2005).
# 10.5	2003 Restricted Stock Plan (incorporated herein by reference to Appendix B to the Company’s Proxy Statement dated August 25, 2003 for its 2003 Annual Meeting of Stockholders, filed on August 25, 2003, File No. 000-26321).
#10.6	Form of Amendment to Gasco Energy, Inc. Employment Agreement dated as of December 31, 2008, and effective as of January 1, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated December 31, 2008, filed January 7, 2009, File No. 001-32369).
#10.7	Form of Second Amendment to Gasco Energy, Inc. Employment Agreement dated and effective as of January 22, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.12 to the Company’s Form 10-K for the fiscal year ended December 31, 2008, filed on March 4, 2009, File No. 001-32369).
10.8	Form of Exchange Agreement dated as of June 22, 2010 between Gasco Energy, Inc. and each of the Investors (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
#10.9	Employment Agreement entered into by and between Gasco Energy, Inc. and W. King Grant, effective as of February 8, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated February 8, 2011, filed on February 11, 2011, File No. 001-32369).

126

#10.10	Employment Agreement entered into by and between Gasco Energy, Inc. and Michael K. Decker, effective as of February 8, 2011 (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K dated February 8, 2011, filed on February 11, 2011, File No. 001-32369).
#10.11	Gasco Energy, Inc. 2011 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 10-Q dated June 30, 2011, filed on August 9, 2011, File No. 001-32369).
10.12	Gas Processing Agreement dated September 21, 2011 by and between Gasco Energy, Inc. and Chipeta Processing LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated September 20, 2011, filed on September 26, 2011, File No. 001-32369).
10.13	Amended and Restated Gas Gathering and Processing Agreement dated March 22, 2012, by and between Gasco Production Company and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
#10.14	Form of Stock Appreciation Right Agreement (incorporated herein by reference to Exhibit 10.4 to the Company’s Form 10-Q dated September 30, 2011, filed on November 1, 2011, File No. 001-32369).
10.15	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).
10.16	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).
10.17	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).
#10.18	Form of Stock Appreciation Right Agreement (incorporated herein by reference to Exhibit 10.35 to the Company’s Form 10-K, dated December 31, 2011, filed on March 28, 2012, File No. 001-32369).
* 10.19	Amendment to Gas Processing Agreement dated December 1, 2013, by and between Chipeta Processing LLC and Gasco Energy, Inc.
*21.1	Subsidiaries of Gasco Energy, Inc.
*23.1	Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists
*23.2	Consent of KPMG LLP
*31.1	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
*31.2	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
**32.1	Section 1350 Certification of Principal Executive Officer
**32.2	Section 1350 Certification of Principal Financial Officer
*99.1	Report of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists

127

***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.

#Identifies management contracts and compensatory plans or arrangements.

128

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.		Dated: March 6, 2013
By:	/s/ W. King Grant
	W. King Grant, President, Chief Executive Officer and Director
	(Duly Authorized Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Charles B. Crowell	Director	March 6, 2013
Charles B. Crowell
/s/ Richard S. Langdon	Director	March 6, 2013
Richard S. Langdon
/s/ R. J. Burgess	Director	March 6, 2013
R.J. Burgess
/s/ John A. Schmit	Director	March 6, 2013
John A. Schmit
/s/ Steven D. (Dean) Furbush	Director	March 6, 2013
Steven D. (Dean) Furbush
/s/ W. King Grant	President, Chief Executive Officer and Director	March 6, 2012
W. King Grant	(Principal Executive Officer)
/s/ Peggy A. Herald	Vice President and Chief Accounting Officer	March 6, 2013
Peggy A. Herald	(Principal Financial Officer)

129

INDEX TO EXHIBITS

3.1	Restated and Amended Articles of Incorporation (incorporated herein 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 herein 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 herein 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	Certificate of Amendment to Articles of Incorporation dated September 20, 2010 (incorporated herein 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).
3.5	Second Amended and Restated Bylaws of Gasco Energy, Inc. dated April 8, 2009 (incorporated herein 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).
3.6	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).
4.1	Indenture (including form of 2015 Note) dated as of June 25, 2010 between Gasco Energy, Inc. and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.2	First Supplemental Indenture dated as of September 22, 2010 between Gasco Energy, Inc. and Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 10.7 to the Company’s Form 10-Q dated September 30, 2010, filed on November 2, 2010, File No. 001-32369).
4.3	Guaranty Agreement dated as of June 25, 2010 among Gasco Production Company, Riverbend Gas Gathering, LLC, and Myton Oilfield Rentals, LLC, in favor of Wells Fargo Bank, National Association (incorporated herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.4	Investor Rights Agreement dated as of June 25, 2010 among Gasco Energy, Inc., CNH CA Master Account, L.P. and AQR Absolute Return Master Account, L.P. (incorporated herein by reference to Exhibit 4.3 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
4.5	Form of Warrant (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 8-K dated June 10, 2011, filed on June 10, 2011, File No. 001-32369).
4.6	Form of Warrant (incorporated herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated July 28, 2011, filed on July 29, 2011, File No. 001-32369).
# 10.1	1999 Stock Option Plan (incorporated herein by reference to Exhibit 4.1 to the Company’s Form 10KSB for the fiscal year ended December 31, 1999, filed on April 14, 2000, File No. 000-26321).
# 10.2	Form of Stock Option Agreement under the 1999 Stock Option Plan (incorporated herein by reference to Exhibit 10.8 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

130

# 10.3	Stock Option Agreement dated January 2, 2001 between Gasco and Mark A. Erickson (incorporated herein by reference to Exhibit 10.9 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.4	Form of Stock Option Agreement between Gasco and each of the individuals named therein (incorporated herein by reference to Exhibit 4.4 to the Company’s Form S-8 Registration Statement (Reg. No. 333-122716), filed on February 10, 2005).
# 10.5	2003 Restricted Stock Plan (incorporated herein by reference to Appendix B to the Company’s Proxy Statement dated August 25, 2003 for its 2003 Annual Meeting of Stockholders, filed on August 25, 2003, File No. 000-26321).
#10.6	Form of Amendment to Gasco Energy, Inc. Employment Agreement, dated as of December 31, 2008, and effective as of January 1, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated December 31, 2008, filed January 7, 2009, File No. 001-32369).
#10.7	Form of Second Amendment to Gasco Energy, Inc. Employment Agreement, dated and effective as of January 22, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.12 to the Company’s Form 10-K for the fiscal year ended December 31, 2008, filed on March 4, 2009, File No. 001-32369).
10.8	Form of Exchange Agreement dated as of June 22, 2010 between Gasco Energy, Inc. and each of the Investors (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated June 22, 2010, filed on June 28, 2010, File No. 001-32369).
#10.9	Employment Agreement entered into by and between Gasco Energy, Inc. and W. King Grant, effective as of February 8, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated February 8, 2011, filed on February 11, 2011, File No. 001-32369).
#10.10	Employment Agreement entered into by and between Gasco Energy, Inc. and Michael K. Decker, effective as of February 8, 2011 (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K dated February 8, 2011, filed on February 11, 2011, File No. 001-32369).
#10.11	Gasco Energy, Inc. 2011 Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 10-Q dated June 30, 2011, filed on August 9, 2011, File No. 001-32369).
10.12	Gas Processing Agreement dated September 21, 2011 by and between Gasco Energy, Inc. and Chipeta Processing LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated September 20, 2011, filed on September 26, 2011, File No. 001-32369).
10.13	Amended and Restated Gas Gathering and Processing Agreement dated March 22, 2012, by and between Gasco Production Company and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated March 22, 2012, filed on March 28, 2012, File No. 000-26321).
#10.14	Form of Stock Appreciation Right Agreement (incorporated herein by reference to Exhibit 10.4 to the Company’s Form 10-Q dated September 30, 2011, filed on November 1, 2011, File No. 001-32369).
10.15	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).

131

10.16	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).
10.17	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).
#10.18	Form of Stock Appreciation Right Agreement (incorporated herein by reference to Exhibit 10.35 to the Company’s Form 10-K, dated December 31, 2011, filed on March 28, 2012, File No. 001-32369).
* 10.19	Amendment to Gas Processing Agreement dated December 1, 2013, by and between Chipeta Processing LLC and Gasco Energy, Inc.
*21.1	Subsidiaries of Gasco Energy, Inc.
*23.1	Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists.
*23.2	Consent of KPMG LLC
*31.1	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer
*31.2	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
**32.1	Section 1350 Certification of Principal Executive Officer
**32.2	Section 1350 Certification of Principal Financial Officer
*99.1	Report of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists.
***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.

#Identifies management contracts and compensatory plans or arrangements.

132

EX-10.19

EXHIBIT 10.19

Contract #9330

AMENDMENT TO GAS PROCESSING AGREEMENT

This Amendment to Gas Processing Agreement (“Amendment”) is made and entered into this 1st day of December, 2012, by and between CHIPETA PROCESSING LLC (“Processor”), and GASCO ENERGY, INC. (“Processing Customer”).

RECITALS

Whereas, Processor and Processing Customer are Parties to that certain Gas Processing Agreement (“Agreement”) dated September 21, 2011, as amended, providing for processing of Processing Customer’s Gas at the Chipeta Plant; and

Whereas, Processor and Processing Customer desire to amend the Agreement as set forth in this Amendment.

NOW, THEREFORE, in consideration of the mutual covenants and promises contained herein, and intending to be legally bound, Processor and Processing Customer agree as follows:

1.             Definitions.  For purposes of this Amendment, unless given a different meaning under this Amendment, capitalized terms shall be given the same meaning they are given under the Agreement.

2.             Effective Date.  This Amendment shall be effective as of date first set forth above.

3.             Amendment Gas Processing Agreement.

(a)           Section 3(a) of the Agreement is hereby amended by deleting the date “December 31, 2012”, wherever it appears and substituting in lieu thereof “June 30, 2013”.

(b)           Section 3(b) of the Agreement is hereby amended by deleting the date “December 31, 2012”, wherever it appears and substituting in lieu thereof “June 30, 2013”.

(c)           Except as expressly amended hereby, the Agreement shall remain effective in accordance with its terms.

4.             Entire Agreement; Amendment.  This Amendment constitutes the entire agreement and understanding between the Parties with respect to the matters covered by this Amendment, and supersedes all prior agreements and understandings with respect thereto, and may be amended, restated or supplemented only by written agreement of the Parties.

5.             Multiple Counterparts.  This Amendment may be executed in multiple counterparts, each of which shall be deemed an original, and all of which taken together shall constitute one and the same agreement.

IN WITNESS WHEREOF, and with the intent to be legally bound, the Parties hereto have caused this Amendment to be executed by their duly authorized officers or representatives to be effective as of the date specified herein.

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GASCO ENERGY, INC.		CHIPETA PROCESSING LLC
		By WGR Operating, LP
		Its Managing Member
By:	/s/ Michael Decker	By:	/s/ David Gibbons
Name:	Michael Decker	Name:	David Gibbons
Title:	EVP/COO	Title:	Regional Manager Anadarko Mid-Stream

2

EX-21.1

EXHIBIT 21.1

Subsidiaries of the Company

At December 31, 2012

State or Jurisdiction
of Organization	Subsidiaries	Ownership %
Nevada	Myton Oilfield Rentals, LLC	100	%
Nevada	Riverbend Gas Gathering, LLC	100	%
Delaware	Gasco Production Company	100	%

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to the incorporation by reference in Registration Statements Nos. 333-153154, 333-114496, 333-121039, 333-128547 and 333-176593 on Form S-3, and Nos. 333-105974, 333-116014, 333-122716 and 333-176916 on Form S-8 of Gasco Energy, Inc. (the “Company”) of all references to Netherland, Sewell & Associates, Inc., independent petroleum engineers, and the reports prepared by such independent petroleum engineers appearing in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012, to be filed with the U.S. Securities and Exchange Commission.

	NETHERLAND, SEWELL & ASSOCIATES, INC.
	By:	/s/ C.H. (Scott) Rees III
		C.H. (Scott) Rees III, P.E.
		Chairman and Chief Executive Officer
Dallas, Texas
March 6, 2013

EX-23.2

EXHIBIT 23.2

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Gasco Energy, Inc.:

We consent to the incorporation by reference in the registration statements (Nos. 333-176593, 333-153154, 333-128547, 333-121039, and 333-114496) on Form S-3 and (Nos. 333-176916, 333-122716, 333-116014 and 333-105974) on Form S-8, of Gasco Energy, Inc. of our reports dated March 6, 2013, with respect to the consolidated balance sheets of Gasco Energy, Inc. as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and the effectiveness of internal control over financial reporting as of December 31, 2012, which reports appear in the December 31, 2012 annual report on Form 10-K of Gasco Energy, Inc.

Our report dated March 6, 2013 contains an explanatory paragraph that states that the Company has suffered recurring losses and negative cash flows from operations, which raise substantial doubt about its ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of that uncertainty.

/s/ KPMG LLP

Denver, Colorado

March 6, 2013

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO RULE 13-A-14(A) AND RULE 15D-14(A) OF THE

SECURITIES EXCHANGE ACT OF 1934

I, W. King Grant, certify that:

1.I have reviewed this annual report on Form 10-K for the period ended December 31, 2012, of Gasco Energy, Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 6, 2013	/s/ W. King Grant
		W. King Grant
		President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A) OF THE

SECURITIES EXCHANGE ACT OF 1934

I, Peggy A. Herald, certify that:

1.I have reviewed this annual report on Form 10-K for the period ended December 31, 2012, of Gasco Energy, Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	March 6, 2013	/s/ Peggy A. Herald
		Peggy A. Herald
		Vice President and Chief Accounting Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

OF GASCO ENERGY, INC. UNDER SECTION 906 OF

THE SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

I, W. King Grant, Chief Executive Officer of Gasco Energy, Inc. (the “Company”), hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, that, to my knowledge, the accompanying report on Form 10-K for the period ending December 31, 2012 and filed with the Securities and Exchange Commission on the date hereof pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended.

I further certify that, to my knowledge, the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ W. King Grant
Name:	W. King Grant
Title:	President and Chief Executive Officer
Date:	March 6, 2013

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

OF GASCO ENERGY, INC. UNDER SECTION 906

 OF THE SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

I, Peggy A. Herald, Vice President and Chief Accounting Officer of Gasco Energy, Inc. (the “Company”), hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, that, to my knowledge, the accompanying report on Form 10-K for the period ending December 31, 2012 and filed with the Securities and Exchange Commission on the date hereof pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended.

I further certify that, to my knowledge, the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Peggy A. Herald
Name:	Peggy A. Herald
Title:	Vice President and Chief Accounting Officer
Date:	March 6, 2013

EX-99.1

Exhibit 99.1

January 25, 2013

Mr. Michael K. Decker

Gasco Energy, Inc.

Suite 1150

7979 East Tufts Avenue

Denver, Colorado 80237

Dear Mr. Decker:

In accordance with your request, we have estimated the proved developed reserves and future revenue, as of December 31, 2012, to the Gasco Energy, Inc. (Gasco) interest in certain oil and gas properties located in Carbon, Duchesne, and Uintah Counties, Utah.  We completed our evaluation on or about the date of this letter.  It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Gasco.  The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas.  Definitions are presented immediately following this letter.  This report has been prepared for Gasco’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Gasco interest in these properties, as of December 31, 2012, to be:

	Net Reserves		Future Net Revenue (M$)
	Oil	Gas		Present Worth
Category	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	222.7	11,909.4	14,651.4	9,499.5
Proved Developed Non-Producing	28.9	694.4	1,508.3	818.2
Total Proved Developed	251.6	12,603.7	16,159.7	10,317.6

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate.  Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons.  Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed reserves.  Our study indicates that there are no proved undeveloped reserves for these properties at this time.  No study was made to determine whether probable or possible reserves might be established for these properties.  Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status.  The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Gasco’s share of the gross (100 percent) revenue from the properties prior to any deductions.  Future net revenue is after deductions for Gasco’s share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes.  The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the

value of money.  Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2012.  For oil and condensate volumes, the average Wall Street Journal West Texas Intermediate spot price of $94.71 per barrel is adjusted by product for quality, transportation fees, and regional price differentials.  For gas volumes, the average Northwest (Wyoming pool) spot price of $2.617 per MMBTU is adjusted by area for energy content, transportation fees, and regional price differentials.  All prices are held constant throughout the lives of the properties.  The average adjusted product prices weighted by production over the remaining lives of the properties are $80.25 per barrel of oil and $2.151 per MCF of gas.

Operating costs used in this report are based on operating expense records of Gasco, the operator of the properties.  These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels.  Headquarters general and administrative overhead expenses of Gasco are included to the extent that they are covered under joint operating agreements.  Operating costs are held constant throughout the lives of the properties.

Capital costs used in this report were provided by Gasco and are based on actual costs from recent activity.  Capital costs are included as required for workovers.  Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable.  Capital costs are held constant to the date of expenditure.  As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities.  We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Gasco interest.  Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Gasco receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities.  Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves.  Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.  In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance.  If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts.  Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests.  The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards).  We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric

analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Gasco, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate.  Supporting work data are on file in our office.  The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed.  The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.  We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

		Sincerely,
		NETHERLAND, SEWELL & ASSOCIATES, INC.
		Texas Registered Engineering Firm F-2699
		By:	/s/ C.H. (Scott) Rees III
			C.H. (Scott) Rees III, P.E.
			Chairman and Chief Executive Officer
By:	/s/ Craig H. Adams	By:	/s/ William J. Knights
	Craig H. Adams, P.E. 68137		William J. Knights, P.G. 1532
	Vice President		Vice President
Date Signed: January 25, 2013		Date Signed: January 25, 2013
CHA:JDH

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients.  The digital document is intended to be substantively the same as the original signed document maintained by NSAI.  The digital document is subject to the parameters, limitations, and conditions stated in the original document.  In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a).  Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties.  Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir.  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery.  When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)Same environment of deposition;

(iii)Similar geological structure; and

(iv)Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen.  Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.  In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate.  Condensate is 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.

(5) Deterministic estimate.  The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves — Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.  Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves — Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.  Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons.  Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production.  In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

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(7) Development costs.  Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.  More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)Provide improved recovery systems.

(8) Development project.  A development project is the means by which petroleum resources are brought to the status of economically producible.  As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) 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.

(10) Economically producible.  The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.  The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR).  Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs.  Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.  Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property.  Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies.  Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

(ii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii)Dry hole contributions and bottom hole contributions.

(iv)Costs of drilling and equipping exploratory wells.

(v)Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well.  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well.  An extension well is a well drilled to extend the limits of a known reservoir.

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(15) Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.  There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.  Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field.  The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)Oil and gas producing activities include:

(A)The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1)Lifting the oil and gas to the surface; and

(2)Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank.  If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)Oil and gas producing activities do not include:

(A)Transporting, refining, or marketing oil and gas;

(B)Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C)Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D)Production of geothermal steam.

(17) Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.  When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

3

(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain.  Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir.  Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology.  Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves.  When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.  Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate.  The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.  They become part of the cost of oil and gas produced.  Examples of production costs (sometimes called lifting costs) are:

(A)Costs of labor to operate the wells and related equipment and facilities.

(B)Repairs and maintenance.

(C)Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

4

(D)Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E)Severance taxes.

(ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities.  To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate.  Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

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

(22) Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)The area of the reservoir considered as proved includes:

(A)The area identified by drilling and limited by fluid contacts, if any, and

(B)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B)The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.  The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties.  Properties with proved reserves.

(24) Reasonable certainty.  If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90%

5

probability that the quantities actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology.  Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30  A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31  All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a.Future cash inflows.  These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves.  Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b.Future development and production costs.  These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.  If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c.Future income tax expenses.  These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved.  The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

d.Future net cash flows.  These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e.Discount.  This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f.Standardized measure of discounted future net cash flows.  This amount is the future net cash flows less the computed discount.

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

6

(28) Resources.  Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations.  A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable.  Resources include both discovered and undiscovered accumulations.

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

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

(31) Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

·The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

·The company’s historical record at completing development of comparable long-term projects;

·The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

·The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

·The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties.  Properties with no proved reserves.

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GOING CONCERN (Details) (USD $)			0 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Jun. 25, 2010 2015 Notes	Dec. 31, 2012 2015 Notes
GOING CONCERN
Accumulated deficit	$ (244,808,156)	$ (222,575,765)
Convertible senior notes
Aggregate principal amount outstanding				$ 45,168,000
Interest rate (as a percent)			5.50%	5.50%
Maximum cure period for payment of interest			30 days

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STOCK-BASED COMPENSATION (Details 4) (SARs, USD $)	0 Months Ended
	Feb. 28, 2012	Oct. 05, 2011	Dec. 31, 2011
SARs
Stock-based compensation
Stock appreciation rights granted to non-employee directors (in shares)	1,000,000	500,000
Amount recorded as a liability			$ 10,924
Number of shares of common stock used to calculate fair market value for a lump sum payment	1	1
An amount greater than the closing price of a share of common stock on the date of grant used to calculate lump sum cash payment (in dollars per share)	$ 0.30	$ 0.25
Amount used to calculate lump sum cash payment	$ 2.00

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DERIVATIVES (Details 2) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Aug. 03, 2011	Jun. 15, 2011
Fair value of derivatives recorded in consolidated balance sheets
Fair value of derivative assets, current		$ 865,358
Fair value of derivative liabilities, noncurrent	907,500	4,235,000	2,185,000	1,850,625
Not designated as an accounting hedge | Natural gas derivative contracts | Current assets
Fair value of derivatives recorded in consolidated balance sheets
Fair value of derivative assets, current		865,358
Not designated as an accounting hedge | Warrant derivatives | Noncurrent liabilities
Fair value of derivatives recorded in consolidated balance sheets
Fair value of derivative liabilities, noncurrent	$ 907,500	$ 4,235,000

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SELECTED QUARTERLY INFORMATION (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Mar. 30, 2012
SELECTED QUARTERLY INFORMATION (Unaudited)
Sale of undivided interest percentage in Uinta Basin producing oil and gas assets												50.00%
Sale of undivided interest percentage in Uinta Basin non-producing oil and gas assets												50.00%
Gross revenue	$ 2,286,908	$ 1,808,625	$ 1,603,873	$ 3,180,267	$ 3,733,905	$ 4,577,127	$ 5,755,471	$ 4,269,105	$ 8,879,673	$ 18,335,608	$ 20,262,099
Gross profit (loss) from oil and gas operations	949,574	506,244	(66,983)	826,124	(532,796)	2,050,485	3,146,353	2,125,958
Net (loss) income	(8,851,778)	(3,170,910)	(5,151,559)	(5,058,144)	(4,472,804)	(1,266,533)	30,169	(1,592,477)	(22,232,391)	(7,301,645)	10,127,020
Net (loss) income per share Basic and diluted	$ (0.05)	$ (0.02)	$ (0.03)	$ (0.03)	$ (0.03)	$ (0.01)	$ 0.00	$ (0.01)	$ (0.13)	$ (0.05)	$ 0.08
Property impairment	$ 7,415,000

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STOCK-BASED COMPENSATION (Details 5) (Restricted Stock, USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Restricted Stock
Restricted stock activity
Outstanding at the beginning of the period (in shares)	184,500	191,300	140,500
Granted (in shares)	250,000	75,000	150,000
Vested (in shares)	(98,500)	(68,900)	(78,500)
Forfeited (in shares)		(12,900)	(20,700)
Outstanding at the end of the period (in shares)	336,000	184,500	191,300
Weighted-Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per share)	$ 0.36	$ 0.70	$ 2.39
Granted (in dollars per share)	$ 0.18	$ 0.25	$ 0.37
Vested (in dollars per share)	$ 0.36	$ 0.93	$ 2.51
Forfeited (in dollars per share)		$ 1.79	$ 2.83
Outstanding at the end of the period (in dollars per share)	$ 0.22	$ 0.36	$ 0.70
Total grant date fair value of shares vested	$ 35,460	$ 64,204	$ 197,075
Total unrecognized compensation cost related to non-vested stock (in dollars)	$ 64,347
Period over which unrecognized compensation cost is expected to be recognized	2 years 4 months 24 days

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CONVERTIBLE SENIOR NOTES (Details) (USD $)	0 Months Ended	12 Months Ended
	Jun. 25, 2010 D	Dec. 31, 2012	Dec. 31, 2011
Convertible senior notes
Debt Instrument, Unamortized Discount		$ 18,530,539	$ 22,574,687
2015 Notes
Convertible senior notes
Aggregate principal amount outstanding		45,168,000
Interest rate (as a percent)	5.50%	5.50%
Maximum cure period for payment of interest	30 days
Redemption price as percentage of principal amount of notes	100.00%
Number of days within 30 consecutive trading days in which the closing price of the entity's common stock must exceed the conversion price for the notes to be redeemable	20
Number of consecutive trading days during which the closing price of the entity's common stock must exceed the conversion price for at least 20 days in order for the notes to be redeemable	30 days
Percentage of principal amount at which notes may be required to be repurchased in event of change of control	100.00%
Effective interest rate for accretion of debt discount to interest expense (as a percent)		26.30%
Debt Instrument, Unamortized Discount		18,530,539	22,574,687
2015 Notes | Common Stock
Convertible senior notes
Initial conversion price (in dollars per share)	0.60
Conversion rate per $1000 principal amount	1,666.6667
Aggregate principal amount used for the calculation of conversion rate	1,000
2015 Notes | Common Stock | Minimum
Convertible senior notes
Period of prior written notice for increase in maximum ownership percentage	61 days
Percentage of the closing sales price of the entity's common stock that the conversion price must exceed in order for the notes to be convertible	150.00%
2015 Notes | Common Stock | Maximum
Convertible senior notes
Ownership percentage of note holders after conversion of notes into common stock	4.99%
Increased ownership percentage of note holders upon prior written notice	9.90%
2015 Notes | Preferred Stock
Convertible senior notes
Initial conversion price (in dollars per share)	100
Conversion rate per $1000 principal amount	10
Aggregate principal amount used for the calculation of conversion rate	1,000

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OIL AND GAS PROPERTY (Tables)

12 Months Ended

Dec. 31, 2012

OIL AND GAS PROPERTY

Summary of oil and gas properties

	As of December 31,
	2012			2011
Proved properties	$	264,814,427		$	268,793,463
Unproved properties	31,486,314			36,938,162
Wells in progress	—			1,938,691
Facilities and equipment	1,493,314			1,502,921
Total	297,794,055			309,173,237
Less accumulated depletion, depreciation, amortization and impairment	(253,092,709		)	(233,987,193		)
	$	44,701,346		$	75,186,044

Schedule of information regarding net costs incurred in the purchase of proved and unproved properties and in exploration and development activities

	For the Years Ended December 31,
	2012		2011		2010
Property acquisition costs:
Unproved	$	2,490,305	$	2,094,969	$	313,238
Proved	177,620		—		481,947
Exploration costs	2,599,168		3,864,866		968,683
Development costs	13,818		2,506,176		5,151,909
Total	$	5,280,911	$	8,466,011	$	6,915,777

Schedule of unproved properties consisting of leasehold acquisition and exploration costs

	2012		2011
Utah	$	29,097,179	$	35,335,449
California	2,389,135		1,602,713
	$	31,486,314	$	36,938,162

Summary of unproved oil and gas property costs

	Balance		Costs Incurred During Years Ended December 31,
	12/31/12		2012		2011		2010		Prior
Acquisition costs	$	23,445,306	$	1,762,979	$	673,351	$	166,772	$	20,842,204
Exploration costs	8,041,008		727,326		1,503,763		146,467		5,663,452
Total	$	31,486,314	$	2,490,305	$	2,177,114	$	313,239	$	26,505,656

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited) (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Standardized measure of discounted future net cash flows
Future cash flows	$ 47,303,900	$ 172,844,800	$ 173,982,700
Future production and development costs	(31,144,200)	(92,505,100)	(91,157,000)
Future net cash flows before discount	16,159,700	80,339,700	82,825,700
10% discount to present value	(5,842,100)	(35,689,700)	(35,898,700)
Standardized measure of discounted future net cash flows	10,317,600	44,650,000	46,927,000
Changes in the standardized measure of discounted future net cash flows
Balance at the beginning of the year	44,650,000	46,927,000	35,561,400
Sales of oil and gas produced, net of production costs	(3,919,636)	(9,549,780)	(13,643,312)
Net changes in prices and production costs	(12,419,867)	1,499,400	12,137,633
Extensions and discoveries, net of future production and development costs	45,618	224,640
Previously estimated development costs incurred	13,818	1,781,487	4,411,807
Changes in estimated future development costs	(872,576)	148,872	2,556,404
Revisions of previous quantity estimates	(7,515,377)	1,096,031	1,154,884
Purchases of reserves in place	647,899		2,228,917
Sales of reserves in place	(14,681,586)		(1,663,100)
Accretion of discount	3,861,014	4,073,524	3,398,429
Other	508,293	(1,551,174)	783,938
Balance at the end of the year	$ 10,317,600	$ 44,650,000	$ 46,927,000

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OIL AND GAS PROPERTY (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property acquisition costs:
Unproved	$ 2,490,305	$ 2,094,969	$ 313,238
Proved	177,620		481,947
Exploration costs	2,599,168	3,864,866	968,683
Development costs	13,818	2,506,176	5,151,909
Total	$ 5,280,911	$ 8,466,011	$ 6,915,777

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LEGAL PROCEEDINGS (Details) (USD $)	1 Months Ended	0 Months Ended
	Feb. 28, 2013 Claim of working interest owners Hat Creek item	Apr. 02, 2012 Claim of working interest owners Hat Creek Minimum	Oct. 03, 2011 Clean Water Act Compliance Order Matter item
Legal proceedings
Number of occasions when Clean Water Act was violated			2
Number of working interest owners with whom claims were settled	1
Damages sought		$ 200,000
Settlement of claim	315,000
Cash payment for settlement of claim	160,000
Forgiveness amount for settlement of claim	$ 155,000

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LEGAL PROCEEDINGS

12 Months Ended

Dec. 31, 2012

LEGAL PROCEEDINGS

LEGAL PROCEEDINGS

NOTE 19— LEGAL PROCEEDINGS

The Company is party to various legal proceedings arising out of the normal course of business.  The most significant legal proceedings to which the Company is subject are 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 these proceedings to have a material adverse effect 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 (the “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: (i) once when it constructed an access road to a future well location in either 2004 or 2005 and (ii) 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 the 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 the 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.  On September 5, 2012, the EPA, represented by the Department of Justice, answered, and the United States separately counterclaimed for an injunction seeking substantially the same relief that the EPA seeks in the compliance order but also requested civil penalties for each day of alleged discharges of fill material and each day of alleged violation of the compliance order.  The Company has answered the EPA’s counterclaim.  In late January 2013, pursuant to a Scheduling Order before the court, the Company submitted a brief in support of its claims under the original suit filed in June 2012.

NEPA Suit

In June 2012, the BLM signed and issued a Rule of Decision on the EIS that authorizes the development of the Company’s Uinta Basin field upon federal lands in Duchesne and Uintah Counties, Utah.  This field includes the Company’s core Riverbend Project.  However on January 18, 2013, certain non-governmental environmental organizations, including the Southern Utah Wilderness Alliance, or SUWA, filed a suit against the BLM, challenging the ROD issued by that agency.  In its complaint, SUWA alleges that the BLM failed to comply with the requirements of NEPA and its implementing regulations.  SUWA was seeking, among other things, that the ROD and EIS be set aside, the effect of which would void the BLM’s authorization for the Company to proceed with its planned project. Only recently, on February 13, 2013, SUWA voluntarily submitted notice of dismissal of the suit to the District Court. Because SUWA voluntarily withdrew its suit, it has the opportunity to refile the suit at a later date. Whether SUWA will refile this suit at a later date is currently unknown to the Company. While any future suit by SUWA or any other third party that seeks to set aside the ROD issued by the BLM for the Company’s planned project in the Uinta Basin field in Utah could, if successfully, have a material adverse effect on the Company’s ability to perform the planned project, the Company would not expect the outcome of such proceeding to have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Hat Creek Settlement

In February 2013, the Company settled a claim with one of its working interest owners, Hat Creek Energy LLC (“Hat Creek”), in connection with a well that was operated by the Company and owned by both parties. Hat Creek filed the claim on April 2, 2012 in the Denver District Court, alleging that Hat Creek did not consent to certain reworking operations performed by the Company in violation of the joint operating agreement, and that Hat Creek’s working interest in the well was impaired as a result.  Hat Creek sought damages of not less than $200,000, and the Company sought counterclaim damages for receivables owed by Hat Creek and for the reworking costs.  The Company settled this claim for $315,000 consisting of a $160,000 cash payment to Hat Creek and the forgiveness of $155,000 in accounts receivable owed to the Company by Hat Creek. In addition, the settlement provides that the Company will receive Hat Creek’s ownership interest in the well.  The final settlement has been accrued in the accompanying consolidated financial statements and is dependent upon the completion of the final settlement documents.

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GAS PROCESSING AGREEMENT (Details)	12 Months Ended	0 Months Ended	12 Months Ended	0 Months Ended		12 Months Ended	0 Months Ended	12 Months Ended
	Dec. 31, 2012	Sep. 21, 2011 Chipeta Processing Agreement	Dec. 31, 2012 Chipeta Processing Agreement	Sep. 21, 2011 Chipeta Processing Agreement Minimum	Mar. 22, 2012 Amended and Restated Monarch Agreement	Dec. 31, 2012 Amended and Restated Monarch Agreement	Sep. 21, 2011 QPC Transportation Agreement	Dec. 31, 2012 QPC Transportation Agreement
Gas processing agreements
Primary term of agreement		10 years
Capacity of cryogenic processing facility to be built by Chipeta (in MMcf/d)		300,000
Extended primary term of agreement unless terminated by either party		1 year
Notice period for termination of agreement		180 days
Committed monthly percentage of capacity in Chipeta processing plant reserved for cryogenic processing				90.00%
Minimum commitment	25,000	25,000	25,000		25,000	25,000	25,000	25,000
Initial volumes of natural gas production related to which the right to process is released and waived by the counterparty (in MMBtu/d)					50,000

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SIGNIFICANT ACCOUNTING POLICIES (Details 3) (USD $)	12 Months Ended			1 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Mar. 31, 2010 Base Contract for Sale and Purchase of Natural Gas Maximum	Dec. 31, 2010 2015 Notes
Deferred financing costs
Amortization expenses	$ 272,605	$ 258,456	$ 13,888,901
Percentage of outstanding amount of debt converted for which pro-rata portion of debt issuance cost was expensed					30.00%
Forward sales contract
Volume of gross production per day to be sold (in MMBtu)				50,000
Volume of gross production per day to be sold that will be priced at the NW Rockies first of month price (in MMBtu)				25,000
Volume of gross production per day to be sold that will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price (in MMBtu)				25,000

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SELECTED QUARTERLY INFORMATION (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

SELECTED QUARTERLY INFORMATION (Unaudited)

Schedule of selected quarterly financial information

	For the Quarter Ended
2012	March 31,			June 30,			September 30,			December 31,
Gross revenue	$	3,180,267		$	1,603,873		$	1,808,625		$	2,286,908
Gross profit (loss) from oil and gas operations	826,124			(66,983		)	506,244			949,574
Net loss (a)	(5,058,144		)	(5,151,559		)	(3,170,910		)	(8,851,778		)
Net loss per share
Basic and diluted	(0.03		)	(0.03		)	(0.02		)	(0.05		)

(a) The increase in the net loss during the fourth quarter of 2012 is primarily due to a $7,415,000 property impairment recorded during the period.

	For the Quarter Ended
2011	March 31,			June 30,		September 30,			December 31,
Gross revenue	$	4,269,105		$	5,755,471	$	4,577,127		$	3,733,905
Gross profit (loss) from oil and gas operations	2,125,958			3,146,353		2,050,485			(532,796		)
Net (loss) income(b)	(1,592,477		)	30,169		(1,266,533		)	(4,472,804		)
Net (loss) income per share
Basic and diluted	(0.01		)	0.00		(0.01		)	(0.03		)

(b) The increase in net loss and the decrease in gross profit from oil and gas operations during the fourth quarter of 2011 is primarily due to the increase in lease operating expense due to the increased workover activity in 2011.

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STOCK-BASED COMPENSATION (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Additional disclosure
Fair value of common stock (in dollars per share)	$ 0.07
Stock Options
Assumptions used to calculate fair values of options granted
Expected dividend yield (as a percent)	0.00%	0.00%	0.00%
Expected price volatility, minimum (as a percent)	182.00%	80.00%	76.00%
Expected price volatility, maximum (as a percent)	188.00%	137.00%	78.00%
Risk-free interest rate, minimum (as a percent)	0.02%	0.10%	1.40%
Risk-free interest rate, maximum (as a percent)	0.90%	1.30%	2.30%
Weighted average grant-date fair value of options granted (in dollars per share)	$ 0.12	$ 0.08	$ 0.23
Vesting period	2 years	2 years
Expiration period	5 years	5 years	5 years
Stock Options
Outstanding at the beginning of the period (in shares)	8,182,647	12,689,733	12,096,672
Granted (in shares)	2,096,485	751,000	1,371,000
Forfeited (in shares)	(17,179)	(201,450)	(86,547)
Cancelled (in shares)	(755,010)	(5,056,636)	(691,392)
Outstanding at the end of the period (in shares)	9,506,943	8,182,647	12,689,733
Exercisable (in shares)	7,565,518	6,950,973	10,548,230
Weighted-Average Exercise Price
Outstanding at the beginning of the period (in dollars per share)	$ 1.37	$ 1.63	$ 1.82
Granted (in dollars per share)	$ 0.24	$ 0.22	$ 0.36
Exercise price for options granted at low end of the range (in dollars per share)	$ 0.16	$ 0.17
Exercise price for options granted at high end of the range (in dollars per share)	$ 0.30	$ 0.25
Forfeited (in dollars per share)	$ 0.22	$ 0.97	$ 1.64
Cancelled (in dollars per share)	$ 1.36	$ 1.75	$ 2.46
Outstanding at the end of the period (in dollars per share)	$ 1.04	$ 1.37	$ 1.63
Exercisable (in dollars per share)	$ 1.35	$ 1.63	$ 1.83
Additional disclosure
Outstanding options weighted average remaining contractual life	2 years 4 months 24 days
Vested options weighted average remaining contractual life	2 years 2 months 12 days
Stock Options | Exercise price of $0.34 per share
Stock Options
Granted (in shares)			50,000
Weighted-Average Exercise Price
Granted (in dollars per share)			$ 0.34
Stock Options | Exercise price of $0.35 per share
Stock Options
Granted (in shares)			175,000
Weighted-Average Exercise Price
Granted (in dollars per share)			$ 0.35
Stock Options | Exercise price of $0.36 per share
Stock Options
Granted (in shares)			646,000
Weighted-Average Exercise Price
Granted (in dollars per share)			$ 0.36
Stock Options | Exercise price of $0.37 per share
Stock Options
Granted (in shares)			500,000
Weighted-Average Exercise Price
Granted (in dollars per share)			$ 0.37
Stock Options | Minimum
Assumptions used to calculate fair values of options granted
Expected life of options	3 months 18 days	3 months 18 days
Vesting period			1 year
Stock Options | Maximum
Assumptions used to calculate fair values of options granted
Expected life of options	5 years	5 years	5 years
Vesting period			2 years
Options and SARs
Additional disclosure
Total unrecognized compensation cost	$ 241,557
Period over which unrecognized compensation cost is expected to be recognized	2 years 4 months 24 days

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COMMITMENTS (Details) (USD $)	12 Months Ended
	Dec. 31, 2012 sqft	Dec. 31, 2011	Dec. 31, 2010
COMMITMENTS
Office space leased (in square feet)	11,170
Annual Rentals
2013	$ 193,613
2014	227,123
2015	236,432
2016	247,602
2017	83,775
Total	988,545
Rent expense	$ 153,509	$ 142,090	$ 166,334

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FAIR VALUE MEASUREMENTS (Details 2) (Warrant derivatives, USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Derivatives
Increase in derivative liability due to increase in trading price of common stock	$ 1,900,000
Increase in trading price of common stock (in dollars per share)	$ 0.10
Decrease in derivative liability by decrease in volatility rate	$ 302,000
Decrease in volatility rate (as a percent)	10.00%
Summary of Warrants
Warrants outstanding at the beginning of the period (in shares)	30,250,000
Warrants outstanding at the end of the period (in shares)	30,250,000	30,250,000
Warrants outstanding at the beginning of the period	42 months	54 months 3 days
Warrants outstanding at the end of the period	42 months	54 months 3 days
Significant assumptions used in the valuation of the warrant derivative liability
Exercise price (in dollars per share)	$ 0.35
Volatility (as a percent)	105.00%
Minimum
Significant assumptions used in the valuation of the warrant derivative liability
Remaining Term of Warrants	41 months
Risk-free interest rate (as a percent)	1.00%
Maximum
Significant assumptions used in the valuation of the warrant derivative liability
Remaining Term of Warrants	43 months
Risk-free interest rate (as a percent)	2.00%

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DERIVATIVES (Details) (USD $)	0 Months Ended		1 Months Ended		0 Months Ended
	Aug. 03, 2011	Jun. 15, 2011	Jun. 30, 2012 Not designated as an accounting hedge Costless collar	Dec. 31, 2012 Not designated as an accounting hedge Costless collar item	Aug. 03, 2011 Not designated as an accounting hedge Warrant derivatives	Jun. 15, 2011 Not designated as an accounting hedge Warrant derivatives
Derivatives
Warrants issued (in shares)	11,500,000	18,750,000			11,500,000	18,750,000
Proceeds from monetization of derivative contract			$ 677,868
Number of derivative instruments held				1
Initial exercise price of warrants (in dollars per share)	$ 0.35	$ 0.35			$ 0.35	$ 0.35
Term of warrants	60 months	60 months			60 months	60 months

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SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2012

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES

NOTE 3 — SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Cash and Cash Equivalents

All highly liquid investments purchased with an original maturity of three months or less at the time of acquisition are considered to be cash equivalents.

Concentration of Credit Risk

The Company’s cash equivalents and derivative instruments are exposed to concentrations of credit risk. The Company manages and controls this risk by placing these funds and contracts with major financial institutions with high credit ratings.

The Company’s receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.

Significant Customers

During the years ended December 31, 2012, 2011 and 2010  70%, 78% and 83%, respectively, of the Company’s production was sold to Anadarko Petroleum Corporation; during 2012, 2011 and 2010, 24%, 16% and 13% of the Company’s production was sold to EnWest Marketing LLC. Approximately 80% of the accounts receivable — revenue as of December 31, 2012 are due from Anadarko Petroleum Corporation. However, Gasco does not believe that the loss of a single purchaser, including Anadarko Petroleum Corporation, would materially affect the Company’s business because there are numerous other purchasers in the areas in which Gasco sells its production. However, the Company may not be able to find other purchasers who would purchase its production on terms comparable to its current arrangements.

Inventory

Inventory consists of pipe and tubular goods intended to be used in the Company’s oil and gas operations, and is stated at the lower of cost or market using the average cost valuation method.

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 $41,644, $76,973 and $123,753 of internal costs during the years ended December 31, 2012, 2011 and 2010, respectively. Additionally, the Company capitalized stock compensation expense related to our drilling consultants as further described in Note 8 — Stock-Based Compensation, herein. Costs associated with production and general corporate activities are expensed in the period incurred. During April 2010, the Company began charging a marketing fee related to the sale of its natural gas production to the wells in which it is the operator and, therefore, net income attributable to the outside working interest owners from such marketing activities of $112,301, $123,844 and $127,639 was recorded as a credit to proved properties during the years ended December 31, 2012, 2011 and 2010, respectively. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to 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.

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. The costs of unproved properties of $31,486,314 as of December 31, 2012, are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. If a determination is made that acreage will be expiring or that the Company does not plan to develop some of the acreage that is no longer considered to be prospective, an impairment of the acreage is recorded by reclassifying the costs to the full cost pool. The value of these acres for the purpose of recording the impairment is estimated by calculating a per acre value from the total unproved costs incurred for the applicable acreage divided by the total net acres owned by the Company. This per acre estimate is then applied to the acres that the Company does not plan to develop in order to calculate the impairment.

During the year ended December 31, 2012, the Company reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification was comprised of a $7,000,000 decrease in the carrying value of its Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012.  During 2011, the Company reclassified $660,000 of acreage costs in Nevada into proved property as it relinquished control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects.  These costs were included in the ceiling test and depletion calculations during the quarter in which the reclassifications were made.

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 of 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-the-month oil and gas price during the 12-month period ended December 31, 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, June 30, 2012, September 30, 2012 and December 31, 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, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012, $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012, and $80.25 per barrel and $2.15 per Mcf of gas during the 12-month period ended December 31, 2012. Therefore, impairment expense of $16,486,000 was recorded during the year ended December 31, 2012. No impairment expense related to the Company’s oil and gas properties was recorded during 2011 or 2010.

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.

Capitalized Interest

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. No interest was capitalized during the three years ended December 31, 2012.

Facilities and Equipment

The Company’s oil and gas equipment is depreciated using the straight-line method over an estimated useful life of three 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 activity attributable to the outside working interest owners from the equipment rental of $(28,080), $(93,208) and $(16,109) was recorded as an adjustment to proved properties during the years ended December 31, 2012, 2011 and 2010, respectively.

Deferred Financing Costs

Deferred financing costs represent the costs associated with the issuance of financial instruments. The Company recorded amortization expense of $272,605, $258,456 and $13,888,901 related to these costs during the years ended December 31, 2012, 2011 and 2010, respectively. Expenses in 2012 and 2011 related to the amortization of the costs for the issuance of the 2015 Notes (see Note 5 — Convertible Senior Notes, herein). Expenses incurred in 2010 included the pro-rata portion of the debt issuance costs expensed for a conversion of 30% of the outstanding 2015 Notes.

Forward Sales Contracts

During March 2010, per the Base Contract for Sale and Purchase of Natural Gas that the Company has with Anadarko Energy Services Company, dated December 1, 2007, the Company entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of its gross production through 2013 from the Uinta Basin.  The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price. The Company accounts for its agreement to physically settle its production as an executory contract. The Company does not believe that the loss of this contract would materially affect its business because there are other potential purchasers in the areas in which the Company sells its production; however, the Company may not be able to find other purchasers who would purchase its production on terms comparable to its current arrangements.

Commodity Derivatives

From time to time, the Company has used 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 consolidated balance sheets. The Company’s management 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 6 — 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”) 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 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 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.

	Year Ended December 31,
	2012			2011
Balance beginning of period	$	1,226,796		$	1,119,561
Liabilities incurred				1,405
Property dispositions	(493,178		)	—
Accretion expense	82,042			105,830
Balance end of period	$	815,660		$	1,226,796

See Note 4 — Asset Sales and Acquisitions, herein, for discussion of property dispositions.

Deferred Income from Sale of Assets

The deferred income from sale of assets represents the excess of proceeds received over the carrying value that was recorded in connection with the sale of the Company’s gathering assets and evaporative facilities in February 2010. This income is being amortized over the fifteen-year terms of the gathering and salt water disposal contracts which were entered into at the time of the sale.

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 December 31, 2012, the off-balance sheet arrangements and transactions that the Company had entered into included undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. See Note 16 — Commitments, herein, for additional discussion regarding certain gas transportation and processing agreements.

Revenue Recognition

The Company records revenues from the sale 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. Gas imbalances at December 31, 2012 and 2011 were not significant.

Computation of Net Income (Loss) per Share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted-average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income (loss) per share of common stock includes both the vested and unvested shares of restricted stock. Diluted net income or loss per common share of stock is computed by dividing adjusted net income by the diluted weighted-average common shares outstanding.  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 the Company’s common stock, (iii) outstanding Series C Convertible Preferred Stock, par value $0.001 per share (“Preferred Stock”), which are convertible into shares of the Company’s common stock, and (iv) the Company’s outstanding 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 (which repurchases were assumed to have been made at the average market price of the common shares during the reporting period), is used to measure the dilutive impact of stock options, shares of restricted common stock and shares into which the 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 years ended December 31, 2012, 2011 and 2010.

	For the Years Ended December 31,
	2012			2011			2010
Basic Net (Loss) Income Per Common Share
Numerator:
Basic net (loss) income	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Net earnings allocated to participating securities	—			—			942,721
Net (loss) income attributed to common stockholders	(22,232,391		)	(7,301,645		)	9,184,299
Denominator:
Weighted-average common shares outstanding	169,032,229			146,587,438			110,058,936
Basic net (loss) income per share	$	(0.13	)	$	(0.05	)	$	0.08

	For the Years Ended December 31,
	2012			2011			2010
Diluted Net (Loss) Income Per Common Share
Numerator:
Basic and diluted net (loss) income	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Denominator:
Diluted weighted-average common shares outstanding	169,032,229			146,587,438			110,058,936
Diluted net (loss) income per share	$	(0.13	)	$	(0.05	)	$	0.08

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

	For the Years Ended December 31,
	2012	2011	2010
2015 Notes and 2011 Notes	75,280,000	75,280,000	75,380,000
Preferred Stock	30,344,173	31,833,339	—
Common stock options	9,506,943	8,182,647	12,689,733
Warrants	30,250,000	30,250,000	—
Unvested restricted stock	336,000	184,500	191,300

Use of Estimates

The preparation of the financial statements for the Company in conformity with U.S. generally accepted accounting principals (“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.

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 loss for the period presented.

Other Comprehensive Income (Loss)

The Company does not have any items of other comprehensive income (loss) for the years ended December 31, 2012, 2011 and 2010. Therefore, total comprehensive income (loss) is the same as net income (loss) for these periods.

Income Taxes

The Company uses the asset and liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of temporary differences between the accounting bases and the tax bases of the Company’s assets and liabilities.  The deferred tax assets and liabilities are computed using enacted tax rates in effect for the year in which the temporary differences are expected to reverse.

The Company’s policy is to recognize penalties and interest, if any, related to uncertain tax positions as general and administrative expense. The Company files income tax returns in the U.S. federal jurisdiction and various states.  There are currently no federal or state income tax examinations underway for these jurisdictions.  Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2009 and for state and local tax authorities for years before 2008.

Stock Compensation

The Company recognizes compensation cost for its common stock options and restricted stock grants as equity based awards based on estimated fair value of the award and records compensation expense over the requisite service period. The Company accounts for its stock appreciation rights (“SARs”) as liability based awards and accordingly recognizes the fair value of the vested SARs each reporting period. See Note 8 —Stock-Based Compensation, herein for further discussion.

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.

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FAIR VALUE MEASUREMENTS (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of changes in fair value of financial liabilities
Balance at the beginning of the period	$ (4,235,000)
Total gains (realized or unrealized):
Included in earnings	3,327,500	(199,375)
Issuances		(4,035,625)
Balance at the end of the period	(907,500)	(4,235,000)
Change in unrealized gains included in earnings relating to instruments still held at the end of the period	3,327,500	(199,375)
2015 Notes
Total gains (realized or unrealized):
Estimated fair value of the 2015 Notes	$ 28,833,000	$ 31,443,000

XML

SIGNIFICANT ACCOUNTING POLICIES (Details 4) (USD $)	0 Months Ended		1 Months Ended	3 Months Ended								12 Months Ended
	Aug. 03, 2011	Jun. 15, 2011	Feb. 28, 2010	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
SIGNIFICANT ACCOUNTING POLICIES
Number of shares that can be purchased out of warrants issued	11,500,000	18,750,000
Initial exercise price of warrants (in dollars per share)	$ 0.35	$ 0.35
Term of warrants	60 months	60 months
Minimum percentage of initial exercise price of warrant to be exceeded by average daily volume weighted-average price of share to require holder to exercise the warrant												200.00%
Information reconciling the value of the asset retirement obligation
Balance beginning of period							$ 1,226,796				$ 1,119,561	$ 1,226,796	$ 1,119,561
Liabilities incurred													1,405
Property dispositions												(493,178)
Accretion expense												82,042	105,830
Balance end of period				815,660				1,226,796				815,660	1,226,796	1,119,561
Deferred income from sale of assets
Amortization period of deferred income on sale of salt water			15 years
Numerator:
Basic net (loss) income				(8,851,778)	(3,170,910)	(5,151,559)	(5,058,144)	(4,472,804)	(1,266,533)	30,169	(1,592,477)	(22,232,391)	(7,301,645)	10,127,020
Net earnings allocated to participating securities														942,721
Net (loss) income attributed to common stockholders												(22,232,391)	(7,301,645)	9,184,299
Denominator:
Weighted-average common shares outstanding, basic												169,032,229	146,587,438	110,058,936
Basic net (loss) income per share (in dollars per share)												$ (0.13)	$ (0.05)	$ 0.08
Numerator:
Basic net (loss) income				$ (8,851,778)	$ (3,170,910)	$ (5,151,559)	$ (5,058,144)	$ (4,472,804)	$ (1,266,533)	$ 30,169	$ (1,592,477)	$ (22,232,391)	$ (7,301,645)	$ 10,127,020
Denominator:
Diluted weighted-average common shares outstanding (in shares)												169,032,229	146,587,438	110,058,936
Diluted net income (loss) per share (in dollars per share)												$ (0.13)	$ (0.05)	$ 0.08
Series C Convertible Preferred stock
Computation of Net Income (Loss) Per Share
Par value of preferred stock (in dollars per share)				$ 0.001				$ 0.001				$ 0.001	$ 0.001

XML

SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2012

SIGNIFICANT ACCOUNTING POLICIES

Schedule reconciling the value of the asset retirement obligation

	Year Ended December 31,
	2012			2011
Balance beginning of period	$	1,226,796		$	1,119,561
Liabilities incurred				1,405
Property dispositions	(493,178		)	—
Accretion expense	82,042			105,830
Balance end of period	$	815,660		$	1,226,796

Schedule of computations of basic and diluted net income (loss) per share

	For the Years Ended December 31,
	2012			2011			2010
Basic Net (Loss) Income Per Common Share
Numerator:
Basic net (loss) income	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Net earnings allocated to participating securities	—			—			942,721
Net (loss) income attributed to common stockholders	(22,232,391		)	(7,301,645		)	9,184,299
Denominator:
Weighted-average common shares outstanding	169,032,229			146,587,438			110,058,936
Basic net (loss) income per share	$	(0.13	)	$	(0.05	)	$	0.08

	For the Years Ended December 31,
	2012			2011			2010
Diluted Net (Loss) Income Per Common Share
Numerator:
Basic and diluted net (loss) income	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Denominator:
Diluted weighted-average common shares outstanding	169,032,229			146,587,438			110,058,936
Diluted net (loss) income per share	$	(0.13	)	$	(0.05	)	$	0.08

Schedule of shares excluded from the computation of diluted earnings (loss) per common share

	For the Years Ended December 31,
	2012	2011	2010
2015 Notes and 2011 Notes	75,280,000	75,280,000	75,380,000
Preferred Stock	30,344,173	31,833,339	—
Common stock options	9,506,943	8,182,647	12,689,733
Warrants	30,250,000	30,250,000	—
Unvested restricted stock	336,000	184,500	191,300

XML

SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2012

SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Basis of Presentation

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

Cash and Cash Equivalents

Cash and Cash Equivalents

All highly liquid investments purchased with an original maturity of three months or less at the time of acquisition are considered to be cash equivalents.

Concentration of Credit Risk

Concentration of Credit Risk

The Company’s cash equivalents and derivative instruments are exposed to concentrations of credit risk. The Company manages and controls this risk by placing these funds and contracts with major financial institutions with high credit ratings.

The Company’s receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.

Significant Customers

Significant Customers

During the years ended December 31, 2012, 2011 and 2010  70%, 78% and 83%, respectively, of the Company’s production was sold to Anadarko Petroleum Corporation; during 2012, 2011 and 2010, 24%, 16% and 13% of the Company’s production was sold to EnWest Marketing LLC. Approximately 80% of the accounts receivable — revenue as of December 31, 2012 are due from Anadarko Petroleum Corporation. However, Gasco does not believe that the loss of a single purchaser, including Anadarko Petroleum Corporation, would materially affect the Company’s business because there are numerous other purchasers in the areas in which Gasco sells its production. However, the Company may not be able to find other purchasers who would purchase its production on terms comparable to its current arrangements.

Inventory

Inventory

Inventory consists of pipe and tubular goods intended to be used in the Company’s oil and gas operations, and is stated at the lower of cost or market using the average cost valuation method.

Oil and Gas Properties

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 $41,644, $76,973 and $123,753 of internal costs during the years ended December 31, 2012, 2011 and 2010, respectively. Additionally, the Company capitalized stock compensation expense related to our drilling consultants as further described in Note 8 — Stock-Based Compensation, herein. Costs associated with production and general corporate activities are expensed in the period incurred. During April 2010, the Company began charging a marketing fee related to the sale of its natural gas production to the wells in which it is the operator and, therefore, net income attributable to the outside working interest owners from such marketing activities of $112,301, $123,844 and $127,639 was recorded as a credit to proved properties during the years ended December 31, 2012, 2011 and 2010, respectively. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to 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.

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. The costs of unproved properties of $31,486,314 as of December 31, 2012, are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. If a determination is made that acreage will be expiring or that the Company does not plan to develop some of the acreage that is no longer considered to be prospective, an impairment of the acreage is recorded by reclassifying the costs to the full cost pool. The value of these acres for the purpose of recording the impairment is estimated by calculating a per acre value from the total unproved costs incurred for the applicable acreage divided by the total net acres owned by the Company. This per acre estimate is then applied to the acres that the Company does not plan to develop in order to calculate the impairment.

During the year ended December 31, 2012, the Company reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification was comprised of a $7,000,000 decrease in the carrying value of its Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012.  During 2011, the Company reclassified $660,000 of acreage costs in Nevada into proved property as it relinquished control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects.  These costs were included in the ceiling test and depletion calculations during the quarter in which the reclassifications were made.

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 of 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-the-month oil and gas price during the 12-month period ended December 31, 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, June 30, 2012, September 30, 2012 and December 31, 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, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012, $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012, and $80.25 per barrel and $2.15 per Mcf of gas during the 12-month period ended December 31, 2012. Therefore, impairment expense of $16,486,000 was recorded during the year ended December 31, 2012. No impairment expense related to the Company’s oil and gas properties was recorded during 2011 or 2010.

Wells in Progress

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.

Capitalized Interest

Capitalized Interest

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. No interest was capitalized during the three years ended December 31, 2012.

Facilities and Equipment

Facilities and Equipment

The Company’s oil and gas equipment is depreciated using the straight-line method over an estimated useful life of three 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 activity attributable to the outside working interest owners from the equipment rental of $(28,080), $(93,208) and $(16,109) was recorded as an adjustment to proved properties during the years ended December 31, 2012, 2011 and 2010, respectively.

Deferred Financing Costs

Deferred Financing Costs

Deferred financing costs represent the costs associated with the issuance of financial instruments. The Company recorded amortization expense of $272,605, $258,456 and $13,888,901 related to these costs during the years ended December 31, 2012, 2011 and 2010, respectively. Expenses in 2012 and 2011 related to the amortization of the costs for the issuance of the 2015 Notes (see Note 5 — Convertible Senior Notes, herein). Expenses incurred in 2010 included the pro-rata portion of the debt issuance costs expensed for a conversion of 30% of the outstanding 2015 Notes.

Forward Sales Contracts

Forward Sales Contracts

During March 2010, per the Base Contract for Sale and Purchase of Natural Gas that the Company has with Anadarko Energy Services Company, dated December 1, 2007, the Company entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of its gross production through 2013 from the Uinta Basin.  The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price. The Company accounts for its agreement to physically settle its production as an executory contract. The Company does not believe that the loss of this contract would materially affect its business because there are other potential purchasers in the areas in which the Company sells its production; however, the Company may not be able to find other purchasers who would purchase its production on terms comparable to its current arrangements.

Commodity Derivatives

Commodity Derivatives

From time to time, the Company has used 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 consolidated balance sheets. The Company’s management 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 6 — Derivatives, herein.

Warrants

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”) 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 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

Asset Retirement Obligation

The Company accounts for its future asset retirement obligations by recording the fair value of the liability during the period in which it was incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs using the units-of-production method. The Company’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties. The asset retirement liability is allocated to operating expense using a systematic and rational method.

	Year Ended December 31,
	2012			2011
Balance beginning of period	$	1,226,796		$	1,119,561
Liabilities incurred				1,405
Property dispositions	(493,178		)	—
Accretion expense	82,042			105,830
Balance end of period	$	815,660		$	1,226,796

See Note 4 — Asset Sales and Acquisitions, herein, for discussion of property dispositions.

Deferred Income from Sale of Assets

Deferred Income from Sale of Assets

The deferred income from sale of assets represents the excess of proceeds received over the carrying value that was recorded in connection with the sale of the Company’s gathering assets and evaporative facilities in February 2010. This income is being amortized over the fifteen-year terms of the gathering and salt water disposal contracts which were entered into at the time of the sale.

Off Balance Sheet Arrangements

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 December 31, 2012, the off-balance sheet arrangements and transactions that the Company had entered into included undrawn letters of credit, operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. See Note 16 — Commitments, herein, for additional discussion regarding certain gas transportation and processing agreements.

Revenue Recognition

Revenue Recognition

The Company records revenues from the sale 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. Gas imbalances at December 31, 2012 and 2011 were not significant.

Computation of Net Income (Loss) Per Share

Computation of Net Income (Loss) per Share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted-average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income (loss) per share of common stock includes both the vested and unvested shares of restricted stock. Diluted net income or loss per common share of stock is computed by dividing adjusted net income by the diluted weighted-average common shares outstanding.  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 the Company’s common stock, (iii) outstanding Series C Convertible Preferred Stock, par value $0.001 per share (“Preferred Stock”), which are convertible into shares of the Company’s common stock, and (iv) the Company’s outstanding 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 (which repurchases were assumed to have been made at the average market price of the common shares during the reporting period), is used to measure the dilutive impact of stock options, shares of restricted common stock and shares into which the 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 years ended December 31, 2012, 2011 and 2010.

	For the Years Ended December 31,
	2012			2011			2010
Basic Net (Loss) Income Per Common Share
Numerator:
Basic net (loss) income	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Net earnings allocated to participating securities	—			—			942,721
Net (loss) income attributed to common stockholders	(22,232,391		)	(7,301,645		)	9,184,299
Denominator:
Weighted-average common shares outstanding	169,032,229			146,587,438			110,058,936
Basic net (loss) income per share	$	(0.13	)	$	(0.05	)	$	0.08

	For the Years Ended December 31,
	2012			2011			2010
Diluted Net (Loss) Income Per Common Share
Numerator:
Basic and diluted net (loss) income	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Denominator:
Diluted weighted-average common shares outstanding	169,032,229			146,587,438			110,058,936
Diluted net (loss) income per share	$	(0.13	)	$	(0.05	)	$	0.08

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

	For the Years Ended December 31,
	2012	2011	2010
2015 Notes and 2011 Notes	75,280,000	75,280,000	75,380,000
Preferred Stock	30,344,173	31,833,339	—
Common stock options	9,506,943	8,182,647	12,689,733
Warrants	30,250,000	30,250,000	—
Unvested restricted stock	336,000	184,500	191,300

Use of Estimates

Use of Estimates

The preparation of the financial statements for the Company in conformity with U.S. generally accepted accounting principals (“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.

Reclassifications

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 loss for the period presented.

Other Comprehensive Income (Loss)

Other Comprehensive Income (Loss)

The Company does not have any items of other comprehensive income (loss) for the years ended December 31, 2012, 2011 and 2010. Therefore, total comprehensive income (loss) is the same as net income (loss) for these periods.

Income Taxes

Income Taxes

The Company uses the asset and liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of temporary differences between the accounting bases and the tax bases of the Company’s assets and liabilities.  The deferred tax assets and liabilities are computed using enacted tax rates in effect for the year in which the temporary differences are expected to reverse.

The Company’s policy is to recognize penalties and interest, if any, related to uncertain tax positions as general and administrative expense. The Company files income tax returns in the U.S. federal jurisdiction and various states.  There are currently no federal or state income tax examinations underway for these jurisdictions.  Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2009 and for state and local tax authorities for years before 2008.

Stock Compensation

Stock Compensation

The Company recognizes compensation cost for its common stock options and restricted stock grants as equity based awards based on estimated fair value of the award and records compensation expense over the requisite service period. The Company accounts for its stock appreciation rights (“SARs”) as liability based awards and accordingly recognizes the fair value of the vested SARs each reporting period. See Note 8 —Stock-Based Compensation, herein for further discussion.

Recently Issued Accounting Pronouncements

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.

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OIL AND GAS PROPERTY (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2009
Unproved properties
Proved properties	$ 264,814,427	$ 268,793,463
Unproved properties	31,486,314	36,938,162	26,505,656
Wells in progress		1,938,691
Facilities and equipment	1,493,314	1,502,921
Total	297,794,055	309,173,237
Less accumulated depletion, depreciation, amortization and impairment	(253,092,709)	(233,987,193)
Oil and gas properties	44,701,346	75,186,044
Utah
Unproved properties
Unproved properties	29,097,179	35,335,449
California
Unproved properties
Unproved properties	$ 2,389,135	$ 1,602,713

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SIGNIFICANT ACCOUNTING POLICIES (Details 5)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
2015 Notes and 2011 Notes
Shares excluded from the computation of diluted earnings (loss) per common share
Anti-dilutive shares	75,280,000	75,280,000	75,380,000
Preferred Stock
Shares excluded from the computation of diluted earnings (loss) per common share
Anti-dilutive shares	30,344,173	31,833,339
Common stock options
Shares excluded from the computation of diluted earnings (loss) per common share
Anti-dilutive shares	9,506,943	8,182,647	12,689,733
Warrants
Shares excluded from the computation of diluted earnings (loss) per common share
Anti-dilutive shares	30,250,000	30,250,000
Unvested restricted stock
Shares excluded from the computation of diluted earnings (loss) per common share
Anti-dilutive shares	336,000	184,500	191,300

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ASSET SALES AND ACQUISITIONS (Tables) (Uinta Basin)

12 Months Ended

Dec. 31, 2012

Uinta Basin

Asset sales

Schedule of unaudited pro forma information

	For the Years Ended December 31,
	2012			2011			2010
Revenue as reported	$	8,879,673		$	18,335,608		$	20,262,099
Less: revenue from the Uinta Basin Transaction	1,206,145			6,382,289			7,052,865
Pro forma revenue	$	10,085,818		$	11,953,319		$	13,209,234
Net (loss) income as reported	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Less: operating loss resulting from the Uinta Basin Transaction	(2,390,235		)	(816,119		)	(2,441,482		)
Pro forma net (loss) income	$	(19,842,156	)	$	(6,485,526	)	$	12,568,502	)
Net (loss) income per share — basic and diluted as reported	$	(0.13	)	$	(0.05	)	$	0.08
Less net (loss) income per share - from the Uinta Basin Transaction	(0.01		)	(0.01		)	(0.02		)
Pro forma net (loss) income per share — basic and diluted	$	(0.12	)	$	(0.04	)	$	(0.10	)

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DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2012

DERIVATIVES

Schedule of fair value of derivatives recorded in unaudited condensed consolidated balance sheets

	Location on Consolidated	Fair Value at December 31,
	Balance Sheets	2012		2011
Natural gas derivative contracts	Current assets	$	—	$	865,358
Warrant derivative	Noncurrent liabilities	907,500		4,235,000

Summary of realized and unrealized gains and losses related to derivative instruments

	For the Years Ended December 31,
	2012			2011			2010
Realized gains on commodity instruments	$	1,255,948		$	524,460		$	1,588,235
Change in fair value of commodity instruments	(865,358		)	671,399			2,887,564
Change in fair value of warrant derivative	3,327,500			(199,375		)	—
Change in fair value of embedded derivative feature	—			—			6,840,392
Total realized and unrealized gains (losses) recorded	$	3,718,090		$	996,484		$	11,316,191

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GOING CONCERN

12 Months Ended

Dec. 31, 2012

GOING CONCERN

GOING CONCERN

NOTE 2 — GOING CONCERN

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of these consolidated financial statements.  However, due to the extended decline in the natural gas market and sustained low natural gas prices caused by excess production and stagnant growth in the demand for natural gas, the Company has not been able to recover its exploration and development costs as anticipated.  There is substantial doubt regarding the Company’s ability to generate sufficient cash flows from operations to fund its ongoing operations, and the Company currently anticipates that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, through the second quarter of 2013.  This expectation is based on various assumptions, including those related to future natural gas and oil prices, production results and the effectiveness of the Company’s cash management strategy discussed below, some or all of which may not prove to be correct and may result in the Company’s inability to meet cash requirements prior to the second quarter of 2013.   As a result of these factors, there is substantial doubt about the Company’s ability to continue as a going concern.

The Company received notices from the NYSE MKT LLC (the “Exchange”) notifying it that it does not satisfy the continued listing standards set forth in the Exchange’s Company Guide. On December 6, 2012, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange set forth in Section 1003(f)(v) of the Company Guide because our common stock has traded at a low price per share for a substantial period of time.  In the notice, the Exchange predicated our continued listing on the Exchange on us effecting a reverse stock split of our common stock by June 6, 2013. On January 11, 2013, we received a notice from the Exchange indicating that we do not satisfy the continued listing standards of the Exchange set forth in Section 1003(a)(iv) of the Company Guide, which applies if a listed company has sustained losses which are so substantial in relation to its overall operations or its existing financial resources, or its financial condition has become so impaired that it appears questionable, in the opinion of the Exchange, as to whether such company will be able to continue operations and/or meet its obligations as they mature. The Company submitted a plan of compliance (a “Plan”) to the Exchange on February 11, 2013, however, there can be no assurance that the Plan will be accepted by the Exchange or that the Company will be able to achieve compliance with the Exchange’s continued listing standards within the required time frame. Pursuant to the Plan, the Company intends to lower costs, rationalize assets, refocus our development program toward oil and liquids, especially in the Green River Formation, and continue the California program with the potential goal of expanding the California model.  The Plan also considers strategic alternatives, including the debt restructuring and sales of assets, if necessary.  If the Plan is not accepted, the Company will be subject to delisting proceedings.

Furthermore, if the Plan is accepted but the Company is not in compliance with the continued listing standards of the Company Guide by June 30, 2013, or if the Company does not make progress consistent with the Plan, the Exchange staff will initiate delisting proceedings as it deems appropriate.

The Company’s prior revolving credit facility matured on June 29, 2012, and as of the date of this Annual Report, the Company has been unable to obtain a replacement facility on acceptable terms and is no longer actively in discussions to obtain a replacement facility.  Furthermore, the Company may not achieve profitability from operations in the near future or at all.  The Company had net losses and negative cash flow from operations for the year ended December 31, 2012 and at December 31, 2012 had an accumulated deficit of $244,808,156.

As of December 31, 2012, the Company had $45,168,000 aggregate principal amount of its 5.5% Convertible Senior Notes due 2015 (the “2015 Notes”) outstanding.  The 2015 Notes bear interest at a rate of 5.50% per annum, payable in cash semi-annually in arrears on April 5th and October 5th of each year.  The Company’s failure to make an interest payment on the 2015 Notes, if not cured within 30 days, would result in a default under the indenture governing the 2015 Notes, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes. In addition, if the Company’s stock was delisted, it could result in a default under the Indenture.

The Company also has commitments under its gas transportation and processing agreements as discussed further in Note 16 — Commitments, herein.

Failure to generate operating cash flow or to obtain additional financing for the development of the Company’s properties could result in substantial dilution of our property interests or delay or cause indefinite postponement of further exploration and development of our prospects resulting in the possible loss of its properties. This could cause the Company to alter its business plans, including further reducing its exploration and development plans. In particular, the Company faces uncertainties relating to its ability to fund the level of capital expenditures required for oil and gas exploration and production activities. The Company intends to fund its anticipated cash requirements through the second quarter of 2013 primarily through cash on hand and cash flows from operations, although the Company cannot provide assurances that cash on hand and cash flows from operations will be sufficient to fund such requirements. If they are not, the Company’s ability to execute its growth plans as well as to fund its operating budget will be significantly limited, and its liquidity and results of operations may be materially adversely affected.

To continue as a going concern, the Company must generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide it with additional liquidity. The Company has engaged a financial advisor to assist it in evaluating such potential strategic alternatives. It is possible these strategic alternatives will require the Company to make a pre-package, pre-arranged or other type of filing for protection under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against the Company).  The Company’s ability to do so will depend on numerous factors, some of which are beyond its control.  If the Company is unable to generate sufficient operating cash flows, secure additional capital or otherwise restructure or refinance the business before the end of the second quarter of 2013, it will not have adequate liquidity to fund its operations and meet its obligations (including its debt payment obligations), the Company will not be able to continue as a going concern, and could potentially be forced to seek relief through a filing under Chapter 11 of the U.S. Bankruptcy Code (or an involuntary petition for bankruptcy may be filed against it).  The accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets, carrying amounts, or the amount and classification of liabilities that may result, should the Company be unable to continue as a going concern.

In order to address the Company’s liquidity constraints and in addition to its ongoing efforts to secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide it with additional liquidity, the Company has embarked on a cash management strategy to enhance and preserve as much liquidity as possible. This plan contemplates the Company, among other things:

· reducing expenditures by eliminating, delaying or curtailing discretionary and non-essential spending, and not designating any capital budget for 2013;

· managing working capital;

· delaying certain drilling projects;

· pursuing farm-out and other similar types of transactions to fund working capital needs;

· evaluating its options for the divestiture of certain assets;

· considering asset purchases through the issuance of equity;

· investigating merger opportunities; and

· restructuring and reengineering the Company’s organization and processes to reduce operating costs and increase efficiency.

The Company cannot provide any assurances that it will be successful in accomplishing any of these plans or that any of these actions can be effected on a timely basis, on satisfactory terms or maintained once initiated. Furthermore, the Company’s cash management strategy, if successful, may limit certain of its operational and strategic initiatives designed to grow its business over the long term.

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STOCK-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2012

STOCK-BASED COMPENSATION

Summary of stock-based compensation expense

	Year Ended December 31,
	2012			2011			2010
Employee compensation	$	270,086		$	324,408		$	1,368,863
Consultant compensation (reduction in compensation)	(213		)	(1,349		)	(4,969		)
Total stock-based compensation	269,873			323,059			1,363,894
Less: consultant compensation expense (reduction in expense) capitalized as proved property	(106		)	(674		)	(1,370		)
Stock-based compensation expense	$	269,979		$	323,733		$	1,365,264

Schedule of assumptions used to calculate fair value of options granted to the employees and directors

	Employee and Director Options
	2012	2011	2010
Expected dividend yield	—	—	—
Expected price volatility	182-188%	80-137%	76-78%

	Employee and Director Options
	2012	2011	2010
Risk-free interest rate	0.02 – 0.9%	0.1 – 1.3%	1.4 – 2.3%
Expected life of options	0.3 – 5 years	0.3 – 5 years	5 years

Summary of stock option activity in the equity incentive plans

	2012				2011				2010
	Stock Options		Weighted Average Exercise Price		Stock Options		Weighted Average Exercise Price		Stock Options		Weighted Average Exercise Price
Outstanding at beginning of year	8,182,647		$	1.37	12,689,733		$	1.63	12,096,672		$	1.82
Granted	2,096,485		$	0.24	751,000		$	0.22	1,371,000		$	0.36
Exercised	—		—		—		—		—		—
Forfeited	(17,179	)	$	0.22	(201,450	)	$	0.97	(86,547	)	$	1.64
Cancelled	(755,010	)	$	1.36	(5,056,636	)	$	1.75	(691,392	)	$	2.46
Outstanding at the end of year	9,506,943		$	1.04	8,182,647		$	1.37	12,689,733		$	1.63
Exercisable at December 31,	7,565,518		$	1.35	6,950,973		$	1.63	10,548,230		$	1.83

Summary of information related to the outstanding and vested options

	Outstanding Options	Vested Options
Number of shares	9,506,943	7,565,518
Weighted-Average Remaining Contractual Life	2.4 years	2.2 years
Weighted-Average Exercise Price	$1.04	$1.35
Aggregate intrinsic value	$—	$—

Summary of stock options outstanding

Range of exercise Prices per Share	Number of Shares Outstanding	Number of Shares Exercisable	Weighted-Average Remaining Contractual Life of Shares Outstanding (years)
$0.00 – $0.99	5,169,060	3,227,635	2.8
$1.00 – $1.99	2,955,800	2,955,800	1.3
$2.00 – $2.99	300,000	300,000	2.5
$3.00 – $3.99	990,000	990,000	2.7
$4.00 – $4.99	40,000	40,000	5.5
$5.00 – $5.99	52,083	52,083	3.3
Total	9,506,943	7,565,518	2.4

Summary of restricted stock activity

	2012				2011				2010
	Restricted Stock		Weighted Average Fair Value		Restricted Stock		Weighted Average Fair Value		Restricted Stock		Weighted Average Fair Value
Outstanding at the beginning of the year	184,500		$	0.36	191,300		$	0.70	140,500		$	2.39
Granted	250,000		$	0.18	75,000		$	0.25	150,000		$	0.37
Vested	(98,500	)	$	0.36	(68,900	)	$	0.93	(78,500	)	$	2.51
Forfeited	—		—		(12,900	)	$	1.79	(20,700	)	$	2.83
Outstanding at the end of the year	336,000		$	0.22	184,500		$	0.36	191,300		$	0.70

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SIGNIFICANT ACCOUNTING POLICIES (Details) (Customer concentration)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Sales | Anadarko Petroleum Corporation
Significant Customers
Percentage of concentration risk	70.00%	78.00%	83.00%
Sales | EnWest Marketing LLC
Significant Customers
Percentage of concentration risk	24.00%	16.00%	13.00%
Accounts receivable | Anadarko Petroleum Corporation
Significant Customers
Percentage of concentration risk	80.00%

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STOCK-BASED COMPENSATION (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2012
Stock-based compensation
Number of Shares Outstanding	9,506,943
Number of Shares Exercisable	7,565,518
Weighted-Average Remaining Contractual Life of Shares Outstanding	2 years 4 months 24 days
$0.00 - $0.99
Stock-based compensation
Exercise price, minimum (in dollars per share)	0.00
Exercise price, maximum (in dollars per share)	0.99
Number of Shares Outstanding	5,169,060
Number of Shares Exercisable	3,227,635
Weighted-Average Remaining Contractual Life of Shares Outstanding	2 years 9 months 18 days
$1.00 - $1.99
Stock-based compensation
Exercise price, minimum (in dollars per share)	1.00
Exercise price, maximum (in dollars per share)	1.99
Number of Shares Outstanding	2,955,800
Number of Shares Exercisable	2,955,800
Weighted-Average Remaining Contractual Life of Shares Outstanding	1 year 3 months 18 days
$2.00 - $2.99
Stock-based compensation
Exercise price, minimum (in dollars per share)	2.00
Exercise price, maximum (in dollars per share)	2.99
Number of Shares Outstanding	300,000
Number of Shares Exercisable	300,000
Weighted-Average Remaining Contractual Life of Shares Outstanding	2 years 6 months
$3.00 - $3.99
Stock-based compensation
Exercise price, minimum (in dollars per share)	3.00
Exercise price, maximum (in dollars per share)	3.99
Number of Shares Outstanding	990,000
Number of Shares Exercisable	990,000
Weighted-Average Remaining Contractual Life of Shares Outstanding	2 years 8 months 12 days
$4.00 - $4.99
Stock-based compensation
Exercise price, minimum (in dollars per share)	4.00
Exercise price, maximum (in dollars per share)	4.99
Number of Shares Outstanding	40,000
Number of Shares Exercisable	40,000
Weighted-Average Remaining Contractual Life of Shares Outstanding	5 years 6 months
$5.00 - $5.99
Stock-based compensation
Exercise price, minimum (in dollars per share)	5.00
Exercise price, maximum (in dollars per share)	5.99
Number of Shares Outstanding	52,083
Number of Shares Exercisable	52,083
Weighted-Average Remaining Contractual Life of Shares Outstanding	3 years 3 months 18 days

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)
Oil and gas prices weighted by production over lives of proved reserves	80.25	80.35	81.16	82.58	81.35	64.97
Gas
Proved Reserves
Balance at the beginning of the period	36,798,310				39,726,060	44,229,950
Revisions of previous estimates	(10,110,081)				732,040	632,807
Sales of reserves in place	(12,251,600)					(2,213,000)
Purchases of reserves in place	573,600					1,181,442
Production	(2,406,512)				(3,659,790)	(4,105,139)
Balance at the end of the period	12,603,717				36,798,310	39,726,060
Downward revisions
Commodity price decreases	(5,489,900)
Lease operating expense estimate revisions	(3,558,800)
Revision due to well performance	(1,061,381)
Oil
Proved Reserves
Balance at the beginning of the period	502,055				464,659	450,858
Extensions and discoveries	10,400				33,382
Revisions of previous estimates	(28,351)				40,866	68,912
Sales of reserves in place	(210,500)					(19,000)
Purchases of reserves in place	3,800					4,421
Production	(25,805)				(36,852)	(40,532)
Balance at the end of the period	251,599				502,055	464,659
Downward revisions
Commodity price decreases	(30,400)
Lease operating expense estimate revisions	(25,300)
Revision due to well performance	27,349

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CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2012	Dec. 31, 2011
CURRENT ASSETS
Cash and cash equivalents	$ 2,938,086	$ 1,965,967
Accounts receivable
Joint interest billings	1,753,204	810,482
Revenue	777,567	1,483,382
Inventory	1,730,733	1,911,362
Note receivable		500,000
Derivative instruments		865,358
Prepaid and other expenses	153,848	152,045
Total	7,353,438	7,688,596
Oil and gas properties (full cost method)
Proved properties	264,814,427	268,793,463
Unproved properties	31,486,314	36,938,162
Wells in progress		1,938,691
Facilities and equipment	1,493,314	1,502,921
Furniture, fixtures and other	506,511	167,737
Total	298,300,566	309,340,974
Less accumulated depletion, depreciation, amortization and impairment	(253,176,523)	(234,132,806)
Total	45,124,043	75,208,168
NON-CURRENT ASSETS
Deposit	531,443	639,500
Deferred financing costs	845,367	1,117,972
Total	1,376,810	1,757,472
TOTAL ASSETS	53,854,291	84,654,236
CURRENT LIABILITIES
Accounts payable	1,548,121	2,649,772
Revenue payable	2,454,282	2,043,240
Advances from joint interest owners	47,667	98,512
Current portion of long-term debt		8,544,969
Accrued interest	586,556	586,556
Accrued expenses	396,000	355,224
Total	5,032,626	14,278,273
NONCURRENT LIABILITIES
5.5% Convertible Senior Notes due 2015, net of unamortized discount of $18,530,539 and $22,574,687 as of December 31, 2012 and 2011, respectively	26,637,461	22,593,313
Deferred income from sale of assets	2,463,177	2,665,629
Derivative instruments	907,500	4,235,000
Deferred rent	294,236
Asset retirement obligation	815,660	1,226,796
Total	31,118,034	30,720,738
COMMITMENTS AND CONTINGENCIES (NOTE 16)
STOCKHOLDERS' EQUITY
Common stock - $.0001 par value; 600,000,000 shares authorized; 169,823,681 shares issued and 169,749,981 shares outstanding as of December 31, 2012; 168,084,515 shares issued and 168,010,815 shares outstanding as of December 31, 2011	16,982	16,808
Additional paid-in-capital	262,624,918	262,344,286
Accumulated deficit	(244,808,156)	(222,575,765)
Less cost of treasury stock of 73,700 common shares	(130,295)	(130,295)
Total	17,703,631	39,655,225
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	53,854,291	84,654,236
Series B Convertible Preferred stock
STOCKHOLDERS' EQUITY
Convertible Preferred stock
Series C Convertible Preferred stock
STOCKHOLDERS' EQUITY
Convertible Preferred stock	$ 182	$ 191

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ASSET SALES AND ACQUISITIONS (Details) (USD $)	3 Months Ended								12 Months Ended									0 Months Ended			12 Months Ended				1 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Uinta Basin	Dec. 31, 2011 Uinta Basin	Dec. 31, 2010 Uinta Basin	Dec. 31, 2012 Uinta Basin Pro forma	Dec. 31, 2011 Uinta Basin Pro forma	Dec. 31, 2010 Uinta Basin Pro forma	Mar. 22, 2012 Uinta Basin Wapiti item	Mar. 22, 2012 Uinta Basin producing oil and gas assets Wapiti	Mar. 22, 2012 Uinta Basin non-producing oil and gas assets Wapiti	Dec. 31, 2012 Riverbend working interest item	Dec. 31, 2012 Riverbend working interest Minimum	Dec. 31, 2012 Riverbend working interest Maximum	Dec. 31, 2012 Riverbend working interest Average	Jan. 31, 2012 California acreage item
Asset sales
Percentage of undivided interest in assets sold or transferred																			50.00%	50.00%
Consideration in cash																			$ 18,000,000
Consideration in the form of promissory note																			1,190,000
Amount committed to fund drilling and completion costs associated with the development and exploration of the subject assets																				30,000,000
Amount of funding commitment that will be paid on behalf of the entity																		15,000,000
Amount of additional drilling and completion costs																		7,500,000
Total program amount																		37,500,000
Amount expended by counterparty on drilling and completion costs related to the program wells after which the Operating Committee can vote to cease the drilling program																		10,000,000
Potential suspension period if governmental studies are not completed.																		6 months
Net revenue interest allocated to company until Wapiti cumulative proceeds equals costs paid (as a percent)																		32.50%
Net revenue interest allocated to Wapiti until Wapiti cumulative proceeds equals costs paid (as a percent)																		67.50%
Drilling and completion costs for each well borne by the company during the drilling term (as a percent)																		20.00%
Drilling and completion costs for each well borne by Wapiti during the drilling term (as a percent)																		80.00%
Drilling and completion costs borne by company after the drilling term but before Payout (as a percent)																		32.50%
Drilling and completion costs borne by Wapiti after the drilling term but before Payout (as a percent)																		67.50%
All other working interest costs borne by company before Payout (as a percent)																		32.50%
All other working interest costs borne by Wapiti before Payout (as a percent)																		67.50%
Number of members in Operating Committee																		2
Voting percentage of members of each party in Operating Committee																		50.00%
Period from end of drilling term after which Development Agreement may be terminated																		6 months
Period of advance notice upon which the Development Agreement may be terminated by either party																		6 months
Proceeds from transaction used to repay borrowings under prior revolving credit facility																		10,500,000
Amount expected to be paid from proceeds of transaction																		5,000,000
Wells expected to be drilled																									1
Gain on sale of the proved property																		2,567,574
Revenue	2,286,908	1,808,625	1,603,873	3,180,267	3,733,905	4,577,127	5,755,471	4,269,105	8,879,673	18,335,608	20,262,099	1,206,145	6,382,289	7,052,865	10,085,818	11,953,319	13,209,234
Net (loss) income	(8,851,778)	(3,170,910)	(5,151,559)	(5,058,144)	(4,472,804)	(1,266,533)	30,169	(1,592,477)	(22,232,391)	(7,301,645)	10,127,020	(2,390,235)	(8,161,199)	(2,441,482)	(19,842,156)	(6,485,526)	(12,568,502)
Net (loss) income per share - basic and diluted (in dollars per share)	$ (0.05)	$ (0.02)	$ (0.03)	$ (0.03)	$ (0.03)	$ (0.01)	$ 0.00	$ (0.01)	$ (0.13)	$ (0.05)	$ 0.08	$ (0.01)	$ (0.01)	$ (0.02)	$ (0.11)	$ (0.04)	$ (0.10)
Number of wells acquired																					32
Purchase price of assets acquired									177,620		481,947										177,620
Acquired working interest per well (as a percent)																						4.00%	10.00%	8.00%
Prospect Fee
Amount of prospect fee received related to California acreage																									$ 750,000
Potential carried interest provided in wells to be drilled on the acreage (as a percent)																									20.00%

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$ (22,232,391)	$ (7,301,645)	$ 10,127,020
Adjustment to reconcile net (loss) income to net cash (used in) provided by operating activities
Depletion, depreciation, amortization, accretion and impairment expense	19,218,694	3,525,806	3,565,672
Stock-based compensation	269,979	323,733	1,365,264
Gain on extinguishment of debt			(15,772,441)
Change in fair value of derivative instruments	(2,462,142)	(472,024)	(9,727,956)
Gain on sale of assets	(2,567,574)
Amortization of debt discount, deferred expenses and other	4,126,759	3,301,796	13,734,361
Payment of deposit	(12,943)
Changes in operating assets and liabilities:
Accounts receivable	(230,971)	1,425,969	117,298
Inventory	180,629	(241,957)	(799,092)
Note receivable	500,000
Prepaid and other expenses	(1,803)	(22,732)	170,784
Accounts payable	(1,040,651)	406,847	816,919
Revenue payable	411,042	(555,453)	353,148
Accrued interest		(5,195)	(250,965)
Accrued expenses	172,700	(814,645)	(56,161)
Net cash (used in) provided by operating activities	(3,668,672)	(429,500)	3,643,851
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for acquisitions, development and exploration	(5,756,886)	(8,790,336)	(6,981,247)
Cash paid for furniture, fixtures and other	(205,774)	(890)	(17,522)
(Decrease) increase in advances from joint interest owners	(50,845)	(1,065,902)	1,164,414
Proceeds from property sales	19,199,265	10,000	24,309,000
Net cash provided by (used in) investing activities	13,185,760	(9,847,128)	18,474,645
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under line of credit	2,000,000	2,000,000	1,000,000
Proceeds from issuance of common stock and warrants		10,000,000
Repayment of borrowings	(10,544,969)		(29,000,000)
Cash paid for debt and stock issuance costs		(1,351,947)	(2,146,894)
Repurchase of convertible notes			(54,400)
Payment of deposit			(500,000)
Repayment of convertible notes		(400,000)
Net cash (used in) provided by financing activities	(8,544,969)	10,248,053	(30,701,294)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	972,119	(28,575)	(8,582,798)
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD	1,965,967	1,994,542	10,577,340
END OF PERIOD	$ 2,938,086	$ 1,965,967	$ 1,994,542

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CREDIT FACILITY (Details) (Revolving credit facility, USD $) In Millions, unless otherwise specified	0 Months Ended
	Jun. 29, 2012
Revolving credit facility
Credit Facility
Credit facility repaid in full	$ 250.0

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2012

INCOME TAXES

Schedule of provision (benefit) for income taxes

	2012			2011			2010
Current taxes:
Federal	$	—		$	—		$	—
State	—			—			—
Deferred taxes:
Deferred provision (benefit)	(5,615,970		)	55,013,560			12,151,778
Less: valuation allowance	5,615,970			(55,013,560		)	(12,151,778		)
Net income tax provision (benefit)	$	—		$	—		$	—

Schedule of reconciliation of provision (benefit) for income taxes computed at statutory rate to the provision for income taxes

	2012			2011			2010
Tax provision (benefit) at federal statutory rate	$	(7,781,337	)	$	(2,555,576	)	$	3,544,457
State taxes, net of federal tax effects	(524,611		)	(167,581		)	2,573,856
Change in tax rate from prior year	(642		)	7,030			25,267
Permanent items and other	2,690,620			(243,639		)	6,008,198
Loss of NOL from Sec. 382 Limitation	—			57,973,328			—
Valuation allowance	5,615,970			(55,013,560		)	(12,151,778		)
Net income tax provision (benefit)	$	—		$	—		$	—

Schedule of components of deferred tax assets and liabilities

	2012			2011
Deferred tax assets:
Federal and state net operating loss carryovers	$	20,790,664		$	20,172,061
Oil and gas property and other property, plant & equipment	1,995,698			—
Deferred compensation	2,357,410			2,344,155
Deferred gain on sale of assets	920,235			994,149
Accrued salaries and bonus	88,169			82,049
Asset Retirement Obligation	304,728			457,535
Other	130,920			316,516
Total deferred tax assets	26,587,824			24,366,465
Less: valuation allowance	(25,419,167		)	(19,803,198		)
	1,168,657			4,563,268
Deferred tax liabilities:
Oil and gas property and other property, plant & equipment	—			4,314,889
Derivatives	1,168,657			248,379
Total deferred tax liabilities	1,168,657			4,563,268
Net deferred tax asset	$	—		$	—

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INCOME TAXES (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Deferred taxes
Deferred provision (benefit)	$ (5,615,970)	$ 55,013,560	$ 12,151,778
Less: valuation allowance	5,615,970	(55,013,560)	(12,151,778)
Reconciliation of provision (benefits) for income taxes
Tax provision (benefit) at federal statutory rate	(7,781,337)	(2,555,576)	3,544,457
State taxes, net of federal tax effects	(524,611)	(167,581)	2,573,856
Change in tax rate from prior year	(642)	7,030	25,267
Permanent items and other	2,690,620	(243,639)	6,008,198
Loss of NOL from Sec. 382 Limitation		57,973,328
Less: valuation allowance	5,615,970	(55,013,560)	(12,151,778)
Deferred tax assets:
Federal and state net operating loss carryovers	20,790,664	20,172,061
Oil and gas property and other property, plant & equipment	1,995,698
Deferred compensation	2,357,410	2,344,155
Deferred gain on sale of assets	920,235	994,149
Accrued salaries and bonus	88,169	82,049
Asset Retirement Obligation	304,728	457,535
Other	130,920	316,516
Total deferred tax assets	26,587,824	24,366,465
Less: valuation allowance	(25,419,167)	(19,803,198)
Net deferred tax assets	1,168,657	4,563,268
Deferred tax liabilities:
Oil and gas property and other property, plant & equipment		4,314,889
Derivatives	1,168,657	248,379
Total deferred tax liabilities	$ 1,168,657	$ 4,563,268

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COMMITMENTS

12 Months Ended

Dec. 31, 2012

COMMITMENTS

COMMITMENTS

NOTE 16 - COMMITMENTS

The Company leases approximately 11,170 square feet of office space in Denver, Colorado under a lease which terminates on May 31, 2017. The Company’s future rental payments due under this lease are as follows:

Year Ending December 31,	Annual Rentals
2013	$	193,613
2014	227,123
2015	236,432
2016	247,602
2017	83,775
	$	988,545

Rent expense for the years ended December 31, 2012, 2011 and 2010 was $153,509, $142,090 and $166,334, respectively.

As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells.  If the Company does not pay such commitments, the acreage positions or wells may be lost.

On February 8, 2011, the Company entered into new employment agreements with its two key officers, W. King Grant and Michael K. Decker, which replace in their entirety the employment agreements previously in effect. The agreements were effective January 1, 2011 and the total minimum compensation under the agreements is an aggregate of $590,000 per annum and the initial terms of the agreements will expire on the second anniversary of the effective date and will automatically renew for additional one-year terms unless either party elects not to renew or the agreements are otherwise terminated in accordance with their terms. These agreements were renewed through January 1, 2014. The agreements contain clauses regarding termination of the officers that could require payment of an amount ranging from 1.5 to two times annual compensation.

During March 2010, per the Base Contract for Sale and Purchase of Natural Gas that the Company has with Anadarko Energy Services Company, dated December 1, 2007, the Company entered into a term sales and transportation transaction to sell up to 50,000 MMBtu per day of its gross production through 2013 from the Uinta Basin.  The transaction contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price.

The Company has gathering, processing, and transportation through-put commitments with Monarch, Chipeta and Questar Pipeline Company that require delivery of a fixed determinable quantity of gas production. The aggregate minimum commitment to deliver is 25,000 Mcf of natural gas per day to Monarch for gathering and 25,000 Mcf of natural gas per day to Chipeta for processing. The aggregate minimum commitment is 25,000 MMBtu of natural gas per day to QPC for transportation services. These contracts expire at various dates through 2023 and the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. The annual minimum payments for the next five years and thereafter are presented below:

Year Ending December 31,	Annual Commitments
2013	$	6,006,803
2014	6,482,782
2015	6,799,638
2016	7,157,293
2017	5,046,652
Thereafter	27,551,825
	$	59,044,993

These amounts are owed regardless of whether the Company delivers any natural gas quantities to the applicable parties. As described in Note 2 — Going Concern, herein, there is substantial doubt regarding the Company’s ability to generate sufficient cash flows from operations to fund its ongoing operations. If the Company is unable to fund additional drilling projects, and based on its December 31, 2012 reserve estimates, assuming no future drilling and constant gas prices, it estimates that it could have a possible minimum production shortfall of approximately 54,000 MMcf valued at approximately $37 million on an undiscounted gross basis.

The Company is considering several alternatives to mitigate the estimated production shortfall such as the sale of its firm commitment positions, seeking relief from the firm commitments because of the permitting delays in the area and the purchase of production quantities to meet its minimum production requirements. Also, future increases in gas prices would increase the related reserve estimates and reduce the possible shortfalls. However, there is no assurance that the Company will be successful in accomplishing these actions should there be a shortfall. Accordingly, the Company has not accrued the possible obligation as of December 31, 2012 as it is not probable or reasonably estimable.

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COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2012

COMMITMENTS

Schedule of the Company's future rental payments due under the lease

Year Ending December 31,	Annual Rentals
2013	$	193,613
2014	227,123
2015	236,432
2016	247,602
2017	83,775
	$	988,545

Schedule of the annual minimum payments for the next five years and thereafter

Year Ending December 31,	Annual Commitments
2013	$	6,006,803
2014	6,482,782
2015	6,799,638
2016	7,157,293
2017	5,046,652
Thereafter	27,551,825
	$	59,044,993

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SELECTED QUARTERLY INFORMATION (Unaudited)

12 Months Ended

Dec. 31, 2012

SELECTED QUARTERLY INFORMATION (Unaudited)

SELECTED QUARTERLY INFORMATION (Unaudited)

NOTE 18 — SELECTED QUARTERLY INFORMATION (Unaudited)

The following represents selected quarterly financial information for the years ended December 31, 2012 and 2011. In March 2012, the Company closed the Uinta Basin Transaction whereby the Company sold to Wapiti an undivided 50% of its interest in certain of its Uinta Basin producing oil and gas assets, and transferred to Wapiti an undivided 50% of its interest in its Uinta Basin non-producing oil and gas assets, as further described in Note 4 — Asset Sales and Acquisitions.

	For the Quarter Ended
2012	March 31,			June 30,			September 30,			December 31,
Gross revenue	$	3,180,267		$	1,603,873		$	1,808,625		$	2,286,908
Gross profit (loss) from oil and gas operations	826,124			(66,983		)	506,244			949,574
Net loss (a)	(5,058,144		)	(5,151,559		)	(3,170,910		)	(8,851,778		)
Net loss per share
Basic and diluted	(0.03		)	(0.03		)	(0.02		)	(0.05		)

(a) The increase in the net loss during the fourth quarter of 2012 is primarily due to a $7,415,000 property impairment recorded during the period.

	For the Quarter Ended
2011	March 31,			June 30,		September 30,			December 31,
Gross revenue	$	4,269,105		$	5,755,471	$	4,577,127		$	3,733,905
Gross profit (loss) from oil and gas operations	2,125,958			3,146,353		2,050,485			(532,796		)
Net (loss) income(b)	(1,592,477		)	30,169		(1,266,533		)	(4,472,804		)
Net (loss) income per share
Basic and diluted	(0.01		)	0.00		(0.01		)	(0.03		)

(b) The increase in net loss and the decrease in gross profit from oil and gas operations during the fourth quarter of 2011 is primarily due to the increase in lease operating expense due to the increased workover activity in 2011.

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COMMITMENTS (Details 2) (USD $)	12 Months Ended	0 Months Ended	12 Months Ended	0 Months Ended	12 Months Ended	0 Months Ended	12 Months Ended	0 Months Ended			1 Months Ended
	Dec. 31, 2012 Mcf	Mar. 22, 2012 Monarch Gathering Agreement	Dec. 31, 2012 Monarch Gathering Agreement	Sep. 21, 2011 Chipeta Processing Agreement	Dec. 31, 2012 Chipeta Processing Agreement	Sep. 21, 2011 QPC Transportation Agreement	Dec. 31, 2012 QPC Transportation Agreement	Feb. 08, 2011 New employment agreements item	Feb. 08, 2011 New employment agreements Minimum item	Feb. 08, 2011 New employment agreements Maximum item	Mar. 31, 2010 Base Contract for Sale and Purchase of Natural Gas Maximum
Commitments
Number of key employees with whom the entity has entered into agreements								2
Compensation per annum								$ 590,000
Initial terms of the agreements								2 years
Automatic renewal of terms of the agreements								1 year
Number of times of annual compensation that could be required to be paid on termination of the officers									1.5	2
Volume of gross production per day to be sold (in MMBtu)											50,000
Volume of gross production per day to be sold that will be priced at the NW Rockies first of month price (in MMBtu)											25,000
Volume of gross production per day to be sold that will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price (in MMBtu)											25,000
Contractual commitment	25,000	25,000	25,000	25,000	25,000	25,000	25,000
Annual Commitments
2013	6,006,803
2014	6,482,782
2015	6,799,638
2016	7,157,293
2017	5,046,652
Thereafter	27,551,825
Total	59,044,993
Quantity of possible minimum production shortfall due to no future drilling and constant gas prices	54,000,000
Possible minimum production shortfall due to no future drilling and constant gas prices on an undiscounted gross basis	$ 37,000,000

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ORGANIZATION

12 Months Ended

Dec. 31, 2012

ORGANIZATION

ORGANIZATION

NOTE 1 — ORGANIZATION

Gasco Energy, Inc. (“Gasco,” the “Company,” “we,” “our” or “us”) was incorporated under the laws of the State of Nevada on April 21, 1997. Gasco 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.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Interest Rate, Convertible Senior Notes due 2015 (as a percent)	5.50%	5.50%
5.5% Convertible Senior Notes due 2015, unamortized discount (in dollars)	$ 18,530,539	$ 22,574,687
Common stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	169,823,681	168,084,515
Common stock, shares outstanding	169,749,981	168,010,815
Treasury stock, common shares	73,700	73,700
Series B Convertible Preferred stock
Convertible Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Convertible Preferred stock, shares authorized	20,000	20,000
Convertible Preferred stock, shares outstanding	0	0
Series C Convertible Preferred stock
Convertible Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Convertible Preferred stock, shares authorized	2,000,000	2,000,000
Convertible Preferred stock, shares outstanding	182,065	191,000

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2012

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 11 — 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 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 December 31, 2012 and 2011 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
December 31, 2012
Liabilities:
Warrant derivatives	$	—	$	—	$	907,500	$	907,500
December 31, 2011
Assets:
Commodity derivatives	$	—	$	856,358	$	—	$	856,358
Liabilities:
Warrant derivatives	$	—	$	—	$	4,235,000	$	4,235,000

As of December 31, 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 December 31, 2012:

(i) the warrant derivative liability would remain unchanged if the trading price of Gasco’s common stock was reduced to zero, and would increase by approximately $1.9 million for a $0.10 increase in the trading price of our common stock.

(ii) the warrant derivative liability would remain unchanged with a 10% increase in the volatility rate and would decrease by approximately $302,000 with a 10% decrease in the volatility rate.

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 12/31/2011	30,250,000	$	0.35	54.1 months
Warrants issued	—			—
Warrants outstanding as of 12/31/2012	30,250,000	$	0.35	42.0 months

The significant assumptions used in the valuation of the warrant derivative liability are as follows:

Exercise price	$0.35 per share
Volatility	105%
Remaining Term of Warrants	41-43 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:

	For the Year Ended December 31,
	2012			2011
Balance as of January 1,	$	(4,235,000	)	$	—
Total losses (realized or unrealized):
Included in earnings	3,327,500			(199,375		)
Included in other comprehensive income	—			—
Issuances	—			(4,035,625		)
Settlements	—			—
Transfers in and out of Level 3	—			—
Balance as of December 31	$	(907,500	)	$	(4,235,000	)
Change in unrealized gains included in earnings relating to instruments still held as of December 31	$	3,327,500		$	(199,375	)

The carrying amounts of cash and cash equivalents, accounts 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 $28,833,000 and $31,443,000 as of December 31, 2012 and 2011, respectively, was determined using the income valuation technique and option pricing model. This valuation is classified as a Level 3 in the fair value hierarchy as it relies primarily on unobservable pricing inputs.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012	Mar. 06, 2013	Jun. 29, 2012
Document and Entity Information
Entity Registrant Name	GASCO ENERGY INC
Entity Central Index Key	0001086319
Document Type	10-K
Document Period End Date	Dec. 31, 2012
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 30,216,255
Entity Common Stock, Shares Outstanding		169,749,981
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY

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STOCKHOLDERS' EQUITY

12 Months Ended

Dec. 31, 2012

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

NOTE 12 - STOCKHOLDERS’ EQUITY

The Company’s capital stock as of December 31, 2012 and 2011 consists of 600,000,000 authorized shares of common stock, par value $0.0001 per share, 20,000 authorized shares of Series B Convertible Preferred stock, par value $0.001 per share, and 2,000,000 authorized shares of Series C Convertible Preferred stock  (“Preferred Stock”).

Series B Convertible Preferred Stock

As of December 31, 2012 and 2011, the Company had no shares of Series B Preferred Stock issued and outstanding.

Series C Convertible Preferred Stock

As of December 31, 2012 and 2011, the Company had 182,065 and 191,000 shares, respectively, of Preferred Stock issued and outstanding. The Preferred Stock is entitled to receive cash dividends and other distributions declared on the common stock, as well as distributions upon liquidation, dissolution or any other winding up event, in each case as set forth in the Certificate of Designations. The Preferred Stock does not have any right or power to vote on any question or in any proceeding or to be represented at or to receive notice of any meeting of holders of capital stock of the Company, except as required by law. The Preferred Stock may not be redeemed by the Company at any time.

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

During the first quarter of 2011, 36,400 shares of Preferred Stock were converted into 5,766,667 shares of common stock. During March 2012, 8,935 shares of Preferred Stock were converted into 1,489,166 shares of common stock.

Common Stock

The Company had 169,823,681 shares of common stock issued and 73,700 shares held in treasury as of December 31, 2012. The common shareholders are entitled to one vote per share on all matters to be voted on by the shareholders; however, there are no cumulative voting rights. The common shareholders are entitled to dividends and other distributions as may be declared by the board of directors. Upon liquidation or dissolution, the common shareholders will be entitled to share ratably in the distribution of all assets remaining available for distribution after satisfaction of all liabilities and payment of the liquidation preference of any outstanding preferred stock.

As of December 31, 2012, the Company had 9,506,943 shares of common stock issuable upon exercise of outstanding options, 336,000 shares of unvested restricted stock and additional 11,466,640 shares of common stock available for issuance under its long term incentive plan.

As of December 31, 2012, assuming all of the 2015 Notes are converted at the applicable conversion prices and all of the Preferred Stock is converted, the number of shares of our common stock outstanding would increase by approximately 105,624,173 shares of common stock resulting in an increase in the outstanding shares as December 31, 2012 to approximately 275,374,154 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).

The Company’s common stock equity transactions during 2012 and 2011 are described as follows:

On June 15, 2011, the Company closed its underwritten registered offering of 25,000,000 units (the “June Offering”) at a price of $0.24 per unit, for gross proceeds of $6.0 million. Each unit consisted of (i) one share of common stock and (ii) one warrant to purchase 0.75 of a share of common stock. The shares of common stock and June Warrants were issued separately. The net proceeds from the June Offering were $5,108,143, after deducting underwriting discounts and commissions and other offering expenses of $891,857.

On August 3, 2011, the Company closed an underwritten registered offering of 16,000,000 units (the “August Offering” and collectively with the June Offering, the “Offerings”) at a price of $0.25 per unit, for gross proceeds of $4.0 million.  Each unit consisted of (i) one share of common stock and (ii) one warrant to purchase 0.71875 of a share of common stock .  The shares of common stock and August Warrants were issued separately. The net proceeds from the August Offering were $3,604,910, after deducting underwriting discounts, commissions and other offering expenses of $395,090.

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 sheet with changes in their fair value reported in earnings. The June Warrants and the August Warrants were recorded at their fair values of $1,850,625 and $2,185,000, respectively, at the issuance dates. 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 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.

During the first quarter of 2012 and 2011, 8,935 and 34,600 shares of Preferred Stock were converted into 1,489,166 and 5,766,667 shares of common stock, respectively.

During the years ended December 31, 2012 and 2011, the Company’s Board of Directors approved the issuance of 250,000 and 75,000 restricted shares of common stock, respectively, to certain of the Company’s employees. The restricted shares vest at varying schedules within three to five years. The shares fully vest upon certain events, such as a change in control of the Company, expiration of the individual’s employment agreement and termination by the Company of the individual’s employment without cause.  Any unvested shares are forfeited upon termination of employment for any other reason. The shares of restricted stock are considered issued and outstanding at the date of grant and are included in shares outstanding upon vesting for the purposes of computing diluted earnings per share.

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
REVENUES
Gas	$ 6,779,540	$ 15,359,973	$ 17,053,924
Oil	2,100,133	2,975,635	2,612,233
Gathering			595,942
Total	8,879,673	18,335,608	20,262,099
OPERATING EXPENSES
Lease operating	4,960,037	8,879,502	6,057,571
Gathering operations			375,848
Transportation and processing	1,704,677	2,759,780	3,002,719
Depletion, depreciation and amortization	2,732,694	3,525,806	3,565,672
Impairment	16,486,000
General and administrative	4,818,644	4,933,691	6,743,539
Total	30,702,052	20,098,779	19,745,349
OPERATING (LOSS) INCOME	(21,822,379)	(1,763,171)	516,750
OTHER (EXPENSE) INCOME
Interest expense	(6,922,814)	(6,764,933)	(17,683,753)
Gain on sale of assets	2,567,574
Derivative gains	3,718,090	996,484	11,316,191
Gain on extinguishment of debt			15,772,441
Amortization of deferred income from sale of assets	202,452	202,452	168,710
Interest income	24,686	27,523	36,681
Total	(410,012)	(5,538,474)	9,610,270
NET (LOSS) INCOME	$ (22,232,391)	$ (7,301,645)	$ 10,127,020
NET (LOSS) INCOME PER COMMON SHARE
BASIC (in dollars per share)	$ (0.13)	$ (0.05)	$ 0.08
DILUTED (in dollars per share)	$ (0.13)	$ (0.05)	$ 0.08

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DERIVATIVES

12 Months Ended

Dec. 31, 2012

DERIVATIVES

DERIVATIVES

NOTE 6 — 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, 2012, 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 consolidated balance sheets:

	Location on Consolidated	Fair Value at December 31,
	Balance Sheets	2012		2011
Natural gas derivative contracts	Current assets	$	—	$	865,358
Warrant derivative	Noncurrent liabilities	907,500		4,235,000

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2012, 2011 and 2010.

	For the Years Ended December 31,
	2012			2011			2010
Realized gains on commodity instruments	$	1,255,948		$	524,460		$	1,588,235
Change in fair value of commodity instruments	(865,358		)	671,399			2,887,564
Change in fair value of warrant derivative	3,327,500			(199,375		)	—
Change in fair value of embedded derivative feature	—			—			6,840,392
Total realized and unrealized gains (losses) recorded	$	3,718,090		$	996,484		$	11,316,191

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

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CONVERTIBLE SENIOR NOTES

12 Months Ended

Dec. 31, 2012

CONVERTIBLE SENIOR NOTES

CONVERTIBLE SENIOR NOTES

NOTE 5 - CONVERTIBLE SENIOR NOTES

As of December 31, 2012, 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 (the “2015 Indenture”), by and between the Company and Wells Fargo Bank, National Association, as trustee (the “Trustee”) 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, payable in cash semi-annually in arrears on April 5th and October 5th of each year.  The Company’s failure to make an interest payment on the 2015 Notes, if not cured within 30 days, or the delisting of the Company’s common stock from the Exchange, would result in a default under the 2015 Indenture, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes.

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 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 LLC 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, 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 December 31, 2012 and 2011 was $18,530,539 and $22,574,687, respectively.

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EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2012

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

NOTE 17 - EMPLOYEE BENEFIT PLANS

The Company adopted a 401(k) profit sharing plan (the “401(k) Plan”) in October 2001 available to employees who meet the 401(k) Plan’s eligibility requirements.  The 401(k) Plan is a defined contribution plan.  The Company may make discretionary contributions to the 401(k)Plan and is required to contribute 3% of each participating employee’s compensation to the 401(k) Plan.  The contributions made by the Company totaled $129,354, $118,573 and $127,169 during the years ended December 31, 2012, 2011 and 2010, respectively.

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STATEMENTS OF CASH FLOWS

12 Months Ended

Dec. 31, 2012

STATEMENTS OF CASH FLOWS

STATEMENTS OF CASH FLOWS

NOTE 13 - STATEMENTS OF CASH FLOWS

During the year ended December 31, 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.

· Additions to oil and gas properties included in accounts payable of $454,000.

· Write-off of fully depreciated furniture, fixtures and equipment of $252,424.

During the year ended December 31, 2011, the Company’s non-cash investing and financing activities consisted of the following transactions:

· Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and gas properties valued at $1,405.

· Reduction in stock-based compensation expense of $674 capitalized as proved property.

· 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 $830,000.

Cash paid for interest during the years ended December 31, 2012, 2011 and 2010 was $2,598,381, $3,786,641 and $4,095,566, respectively. There was no cash paid for income taxes during the years ended December 31, 2012, 2011 and 2010.

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OIL AND GAS PROPERTY

12 Months Ended

Dec. 31, 2012

OIL AND GAS PROPERTY

OIL AND GAS PROPERTY

NOTE 9 — OIL AND GAS PROPERTY

The Company’s oil and gas properties are summarized in the following table:

	As of December 31,
	2012			2011
Proved properties	$	264,814,427		$	268,793,463
Unproved properties	31,486,314			36,938,162
Wells in progress	—			1,938,691
Facilities and equipment	1,493,314			1,502,921
Total	297,794,055			309,173,237
Less accumulated depletion, depreciation, amortization and impairment	(253,092,709		)	(233,987,193		)
	$	44,701,346		$	75,186,044

The following table presents information regarding the Company’s net costs incurred in the purchase of proved and unproved properties and in exploration and development activities:

	For the Years Ended December 31,
	2012		2011		2010
Property acquisition costs:
Unproved	$	2,490,305	$	2,094,969	$	313,238
Proved	177,620		—		481,947
Exploration costs	2,599,168		3,864,866		968,683
Development costs	13,818		2,506,176		5,151,909
Total	$	5,280,911	$	8,466,011	$	6,915,777

At December 31, 2012 and 2011, the Company’s unproved properties consist of leasehold acquisition and exploration costs in the following areas:

	2012		2011
Utah	$	29,097,179	$	35,335,449
California	2,389,135		1,602,713
	$	31,486,314	$	36,938,162

During the year ended December 31, 2012, the Company reclassified approximately $7,942,000 of acreage costs in Utah and California into proved property. This reclassification was comprised of a $7,000,000 decrease in the carrying value of its Utah acreage based upon an independent appraisal as of December 31, 2012 and $942,000 representing the value of leases that expired during 2012.  During 2011, the Company reclassified $660,000 of acreage costs in Nevada into proved property as it relinquished our control over this acreage to another party in exchange for a small overriding royalty interest on any future drilling projects.  These costs were included in the ceiling test and depletion calculations during the quarter in which the reclassifications were made.

Depreciation, depletion and amortization expense per Mcfe was $1.07, $0.91 and $0.82 for the years ended December 31, 2012, 2011 and 2010, respectively. Impairment expense was $6.44 per Mcfe during the year ended December 31, 2012. No impairment expense was recorded during the years ended December 31, 2011 and 2010.

The following table sets forth a summary of unproved oil and gas property costs as of December 31, 2012, by the year in which such costs were incurred.

	Balance		Costs Incurred During Years Ended December 31,
	12/31/12		2012		2011		2010		Prior
Acquisition costs	$	23,445,306	$	1,762,979	$	673,351	$	166,772	$	20,842,204
Exploration costs	8,041,008		727,326		1,503,763		146,467		5,663,452
Total	$	31,486,314	$	2,490,305	$	2,177,114	$	313,239	$	26,505,656

The Company believes that the majority of its unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further, or by making decisions that further exploration and development activity will not occur.

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FAIR VALUE MEASUREMENTS (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011	Aug. 03, 2011	Jun. 15, 2011
Assets:
Commodity derivatives		$ 865,358
Liabilities:
Warrant derivatives	907,500	4,235,000	2,185,000	1,850,625
Recurring | Level 2
Assets:
Commodity derivatives		856,358
Recurring | Level 3
Liabilities:
Warrant derivatives	907,500	4,235,000
Recurring | Total
Assets:
Commodity derivatives		856,358
Liabilities:
Warrant derivatives	$ 907,500	$ 4,235,000

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GAS PROCESSING AGREEMENT

12 Months Ended

Dec. 31, 2012

GAS PROCESSING AGREEMENT

GAS PROCESSING AGREEMENT

NOTE 7 — 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 constructed.

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.  The cryogenic processing facility was completed and placed in service on February 7, 2013.

Pursuant to the Chipeta Processing Agreement, the Company reserved 25,000 Mcf/d of capacity in the Chipeta processing plant for cryogenic processing.  Under this agreement, the Company committed to deliver, on average, at least 90% of its contracted cryogenic capacity of 25,000 Mcf/d during each monthly accounting period. 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, the Company 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 the Company’s 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 the Company’s reserves in excess of the Excluded Production.  The Excluded Production may be reduced if the Company fails to meet certain drilling investment targets.  The Company is committed to deliver to Monarch for gathering a minimum of 25,000 Mcf/day and it is obligated to pay for any shortfall following the end of each quarterly period, measured by the shortfall quantity for the quarter multiplied by the then-current gathering and processing fees under the agreement.

In connection with the Amended and Restated Monarch Agreement, we also entered into the Questar Wet Line Agreement (the “QPC Transportation Agreement”), dated September 20, 2011, by and between Questar Pipeline Company (“QPC”), pursuant to which we agreed to enter into separate transportation services agreements for firm transportation services. We are currently committed to deliver to QPC for transportation services a minimum of 25,000 MMBtu/day.

See Note 16 — Commitments for further discussion.

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STOCK-BASED COMPENSATION

12 Months Ended

Dec. 31, 2012

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

NOTE 8 — STOCK-BASED COMPENSATION

The Company has outstanding common stock options, 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 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 the unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair value on that date. During the years ended December 31, 2012, 2011 and 2010, the Company recognized stock-based compensation as follows:

	Year Ended December 31,
	2012			2011			2010
Employee compensation	$	270,086		$	324,408		$	1,368,863
Consultant compensation (reduction in compensation)	(213		)	(1,349		)	(4,969		)
Total stock-based compensation	269,873			323,059			1,363,894
Less: consultant compensation expense (reduction in expense) capitalized as proved property	(106		)	(674		)	(1,370		)
Stock-based compensation expense	$	269,979		$	323,733		$	1,365,264

The Company did not recognize a tax benefit from stock-based compensation expense because the Company considers it more likely than not that the related deferred tax assets, which have been reduced by a full valuation allowance, will not be recognized.

The Company uses the Black-Scholes option-pricing model to estimate the fair value of the options at the grant date. The fair value of options granted to the Company’s employees and directors during 2012, 2011 and 2010 was calculated using the following assumptions:

	Employee and Director Options
	2012	2011	2010
Expected dividend yield	—	—	—
Expected price volatility	182-188%	80-137%	76-78%

	Employee and Director Options
	2012	2011	2010
Risk-free interest rate	0.02 – 0.9%	0.1 – 1.3%	1.4 – 2.3%
Expected life of options	0.3 – 5 years	0.3 – 5 years	5 years

The weighted average grant-date fair value of options granted to employees and directors during 2012, 2011 and 2010 was $0.12, $0.08 and $0.23, respectively.

The expected stock price volatility assumption was determined using the historical volatility of the Company’s common stock over the expected life of the option.

Stock Options

During the year ended December 31, 2012, the Company granted 2,096,485 options to purchase common stock with exercise prices ranging from $0.16 to $0.30 per share. These options have a two-year vesting period and expire five years from the grant date.

During the year ended December 31, 2011, the Company granted 751,000 options to purchase common stock with exercise prices of $0.17 to $0.25. These options vest in equal portions over the following two-year period and expire five years from the grant date.

During the year ended December 31, 2010, the Company granted 1,371,000 options to purchase 50,000, 175,000, 646,000 and 500,000 shares of common stock with exercise prices of $0.34, $0.35, $0.36 and $0.37 per share, respectively. These options have a one- or two-year vesting period and expire five years from the grant date.

The following table summarizes the stock option activity in the equity incentive plans during the years ended December 31, 2012, 2011 and 2010:

	2012				2011				2010
	Stock Options		Weighted Average Exercise Price		Stock Options		Weighted Average Exercise Price		Stock Options		Weighted Average Exercise Price
Outstanding at beginning of year	8,182,647		$	1.37	12,689,733		$	1.63	12,096,672		$	1.82
Granted	2,096,485		$	0.24	751,000		$	0.22	1,371,000		$	0.36
Exercised	—		—		—		—		—		—
Forfeited	(17,179	)	$	0.22	(201,450	)	$	0.97	(86,547	)	$	1.64
Cancelled	(755,010	)	$	1.36	(5,056,636	)	$	1.75	(691,392	)	$	2.46
Outstanding at the end of year	9,506,943		$	1.04	8,182,647		$	1.37	12,689,733		$	1.63
Exercisable at December 31,	7,565,518		$	1.35	6,950,973		$	1.63	10,548,230		$	1.83

The following table summarizes information related to the outstanding and vested options as of December 31, 2012:

	Outstanding Options	Vested Options
Number of shares	9,506,943	7,565,518
Weighted-Average Remaining Contractual Life	2.4 years	2.2 years
Weighted-Average Exercise Price	$1.04	$1.35
Aggregate intrinsic value	$—	$—

The aggregate intrinsic value in the table above is based on the Company’s closing common stock price of $0.07 as of December 31, 2012, which would have been received by the option holders had all option holders exercised their options as of that date.

There were no options exercised during the years ending December 31, 2012, 2011 and 2010.

The Company settles employee stock option exercises with newly issued common shares. SARs are settled with cash equal to the difference between the fair market value of the stock and the exercise price on the date of grant.

As of December 31, 2012, there was $241,557 of total unrecognized compensation cost related to non-vested options and SARs granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 2.4 years.

The following table summarizes the stock options outstanding at December 31, 2012:

Range of exercise Prices per Share	Number of Shares Outstanding	Number of Shares Exercisable	Weighted-Average Remaining Contractual Life of Shares Outstanding (years)
$0.00 – $0.99	5,169,060	3,227,635	2.8
$1.00 – $1.99	2,955,800	2,955,800	1.3
$2.00 – $2.99	300,000	300,000	2.5
$3.00 – $3.99	990,000	990,000	2.7
$4.00 – $4.99	40,000	40,000	5.5
$5.00 – $5.99	52,083	52,083	3.3
Total	9,506,943	7,565,518	2.4

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 provided 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 its common stock to these directors.  As of December 31, 2012, the liability for February SARs was approximately zero. The February SARs provided 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 was  less, over (ii) $0.30, which was 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 vested on January 31, 2013 and were automatically exercised on February 1, 2013. 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.

Restricted Stock

The following table summarizes the restricted stock activity for the years ending December 31, 2012, 2011 and 2010:

	2012				2011				2010
	Restricted Stock		Weighted Average Fair Value		Restricted Stock		Weighted Average Fair Value		Restricted Stock		Weighted Average Fair Value
Outstanding at the beginning of the year	184,500		$	0.36	191,300		$	0.70	140,500		$	2.39
Granted	250,000		$	0.18	75,000		$	0.25	150,000		$	0.37
Vested	(98,500	)	$	0.36	(68,900	)	$	0.93	(78,500	)	$	2.51
Forfeited	—		—		(12,900	)	$	1.79	(20,700	)	$	2.83
Outstanding at the end of the year	336,000		$	0.22	184,500		$	0.36	191,300		$	0.70

The total grant date fair value of the restricted shares vested during the years ending December 31, 2012, 2011 and 2010 was $35,460, $64,204 and $197,075, respectively.

As of December 31, 2012, there was $64,347 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a weighted-average period of 2.4 years.

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CREDIT FACILITY

12 Months Ended

Dec. 31, 2012

CREDIT FACILITY

CREDIT FACILITY

NOTE 10 — CREDIT FACILITY

The Company’s prior $250 million revolving credit facility matured on June 29, 2012 and was repaid in full.

While the Company has attempted to secure a replacement facility, as of the date of this Annual Report, it has been unable to do so on acceptable terms and is no longer actively in discussions to obtain a replacement facility.  There can be no assurance that the Company will be able to adequately finance its operations or execute its existing short-term and long-term business plans, and its liquidity and results of operations are likely to be materially adversely affected if the Company is unable to generate sufficient operating cash flows, secure additional capital or otherwise pursue a strategic restructuring, refinancing or other transaction to provide it with additional liquidity.

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STATEMENTS OF CASH FLOWS (Details) (USD $)	1 Months Ended	3 Months Ended		12 Months Ended
	Mar. 31, 2012	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
STATEMENTS OF CASH FLOWS
Recognition of an asset retirement obligation for the plugging and abandonment costs related to the oil and gas properties					$ 1,405
Reduction in stock-based compensation expenses capitalized as proved property				106	674	1,370
Number of shares of preferred stock converted into common stock	8,935	8,935	34,600	8,935	34,600
Number of shares of common stock issued	1,489,166	1,489,166	5,766,667	1,489,166	5,766,667
Settlement of liability with prepaid deposit				121,000
Additions to oil and gas properties included in accounts payable				454,000	830,000
Write-off of fully depreciated furniture, fixtures and equipment				252,424
Cash paid for interest				$ 2,598,381	$ 3,786,641	$ 4,095,566

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INCOME TAXES (Details 2) (USD $)	Dec. 31, 2012
Federal
Operating loss carryovers
Net operating loss carryovers	$ 54,541,750
Net operating loss carryover not benefited for financial statement purpose	3,030,233
State
Operating loss carryovers
Net operating loss carryover not benefited for financial statement purpose	$ 41,063,071

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STOCKHOLDERS' EQUITY (Details) (USD $)	0 Months Ended		1 Months Ended	3 Months Ended		12 Months Ended							12 Months Ended							12 Months Ended
	Aug. 03, 2011	Jun. 15, 2011	Mar. 31, 2012	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2012 item	Dec. 31, 2011	Mar. 30, 2012	Dec. 31, 2012 Stock Options	Dec. 31, 2011 Stock Options	Dec. 31, 2010 Stock Options	Dec. 31, 2009 Stock Options	Dec. 31, 2012 Restricted Stock	Dec. 31, 2011 Restricted Stock	Dec. 31, 2010 Restricted Stock	Dec. 31, 2009 Restricted Stock	Dec. 31, 2012 2015 Notes	Dec. 31, 2012 Series B Convertible Preferred Stock	Dec. 31, 2011 Series B Convertible Preferred Stock	Dec. 31, 2012 Series C Convertible Preferred Stock	Dec. 31, 2011 Series C Convertible Preferred Stock
Stockholders equity
Authorized shares of common stock						600,000,000	600,000,000
Par value of common stock (in dollars per share)						$ 0.0001	$ 0.0001
Authorized shares of preferred stock																		20,000	20,000	2,000,000	2,000,000
Par value of preferred stock (in dollars per share)																		$ 0.001	$ 0.001	$ 0.001	$ 0.001
Shares of preferred stock outstanding																		0	0	182,065	191,000
Amount which is divided by the conversion price applicable to shares of common stock to calculate the number of fully paid and nonassessable shares of common stock into which each share of Preferred Stock is convertible																				$ 100
Number of shares of common stock into which shares of preferred stock were converted			1,489,166	1,489,166	5,766,667	1,489,166	5,766,667	5,766,667
Number of shares of preferred stock converted into shares of common stock			8,935	8,935	34,600	8,935	34,600
Shares of common stock outstanding						169,823,681	168,084,515
Shares of common stock held in treasury						73,700	73,700
Number of votes per share to which common shareholders are entitled to						1
Shares of common stock issuable upon exercise of outstanding options									9,506,943	8,182,647	12,689,733	12,096,672
Shares of unvested restricted stock													336,000	184,500	191,300	140,500
Shares of common stock available for issuance under long term incentive plan						11,466,640
Increase in the number of shares of common stock outstanding, assuming all of the notes and preferred stock are converted																	105,624,173
Outstanding shares of common stock, after assuming that all of the notes and preferred stock are converted																	275,374,154
Issuance of common stock (in shares)	16,000,000	25,000,000
Offer price per unit (in dollars per share)	$ 0.25	$ 0.24
Gross proceeds from offerings	4,000,000	6,000,000					10,000,000
Number of shares of common stock in each unit issued	0.71875	0.75
Number of warrants in each unit issued (in shares)	1	1
Net proceeds from offerings	3,604,910	5,108,143
Underwriting discounts, commissions and other offering expenses	395,090	891,857
Exercisable term of warrants	60 months	60 months
Initial exercise price of warrants (in dollars per share)	$ 0.35	$ 0.35
Fair value of derivative liabilities, noncurrent	$ 2,185,000	$ 1,850,625				$ 907,500	$ 4,235,000
Percentage of initial exercise price of warrants that the average of the daily volume weighted-average price of a share of common stock must equal or exceed in order to require the holders of the warrants to exercise						200.00%
Number of shares approved by the Board of Directors for issuance													250,000	75,000

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2012

FAIR VALUE MEASUREMENTS

Schedule of financial assets and liabilities accounted for at fair value on a recurring basis

	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Total
December 31, 2012
Liabilities:
Warrant derivatives	$	—	$	—	$	907,500	$	907,500
December 31, 2011
Assets:
Commodity derivatives	$	—	$	856,358	$	—	$	856,358
Liabilities:
Warrant derivatives	$	—	$	—	$	4,235,000	$	4,235,000

Summary of warrants issued

	Number of Warrants	Exercise Price		Weighted Average Remaining Contractual Life
Warrants outstanding as of 12/31/2011	30,250,000	$	0.35	54.1 months
Warrants issued	—			—
Warrants outstanding as of 12/31/2012	30,250,000	$	0.35	42.0 months

Schedule of significant assumptions used in the valuation of the warrant derivative liability

Exercise price	$0.35 per share
Volatility	105%
Remaining Term of Warrants	41-43 months
Risk-free interest rate	1% - 2%

Schedule of reconciliation of changes in the fair value of financial liabilities classified as Level 3

	For the Year Ended December 31,
	2012			2011
Balance as of January 1,	$	(4,235,000	)	$	—
Total losses (realized or unrealized):
Included in earnings	3,327,500			(199,375		)
Included in other comprehensive income	—			—
Issuances	—			(4,035,625		)
Settlements	—			—
Transfers in and out of Level 3	—			—
Balance as of December 31	$	(907,500	)	$	(4,235,000	)
Change in unrealized gains included in earnings relating to instruments still held as of December 31	$	3,327,500		$	(199,375	)

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STOCK-BASED COMPENSATION (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
STOCK-BASED COMPENSATION
Employee compensation	$ 270,086	$ 324,408	$ 1,368,863
Consultant compensation (reduction in compensation)	(213)	(1,349)	(4,969)
Total stock-based compensation	269,873	323,059	1,363,894
Less: consultant compensation expense (reduction in expense) capitalized as proved property	(106)	(674)	(1,370)
Stock-based compensation expense	$ 269,979	$ 323,733	$ 1,365,264

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2012

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

NOTE 15 — RELATED PARTY TRANSACTIONS

Certain of the Company’s directors and officers have working and/or overriding royalty interests in oil and gas properties in which the Company has an interest.  It is expected that the directors and officers may participate with the Company in future projects. All participation by directors and officers will continue to be approved by the disinterested members of the Company’s Board of Directors.

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GUARANTOR SUBSIDIARIES

12 Months Ended

Dec. 31, 2012

GUARANTOR SUBSIDIARIES

GUARANTOR SUBSIDIARIES

NOTE 20 — 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 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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DERIVATIVES (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Realized and unrealized gains and losses related to derivative instruments
Total realized and unrealized gains recorded	$ 3,718,090	$ 996,484	$ 11,316,191
Natural gas derivative contracts
Realized and unrealized gains and losses related to derivative instruments
Realized gains on commodity instruments	1,255,948	524,460	1,588,235
Change in fair value	(865,358)	671,399	2,887,564
Warrant derivatives
Realized and unrealized gains and losses related to derivative instruments
Change in fair value	3,327,500	(199,375)
Embedded derivative
Realized and unrealized gains and losses related to derivative instruments
Change in fair value			$ 6,840,392

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SIGNIFICANT ACCOUNTING POLICIES (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2012 Mcf bbl item	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011 item	Dec. 31, 2010	Dec. 31, 2009
Oil and Gas Properties
Internal costs capitalized during the period	$ 41,644				$ 76,973	$ 123,753
Net income from marketing activities attributable to the outside working interest owners recorded as an adjustment to proved properties	112,301				123,844	127,639
Minimum percentage of sale of proved reserves related to a single full cost pool for significant alteration	25.00%
Costs of unproved properties withheld from depletion base	31,486,314				36,938,162		26,505,656
Costs of acreage reclassified from unproved properties into proved properties	7,942,000				660,000		1,100,000
Decrease in the carrying value of acreage due to reclassification	7,000,000
Value of leases expired	942,000
Relative volumes of oil and gas production and reserves converted at energy equivalent rate	1
Ceiling limitation based on average, first-day-of-the-month oil and gas prices	80.25	2.23	81.16	2.94	81.35	3.62
Impairment expense	16,486,000
Wells in progress					2
Oil and gas equipment
Facilities and equipment
Net income (expense) attributable to the outside working interest owners recorded as an adjustment to proved properties	$ (28,080)				$ (93,208)	$ (16,109)
Oil and gas equipment | Minimum
Facilities and equipment
Estimated useful life	3 years
Oil and gas equipment | Maximum
Facilities and equipment
Estimated useful life	10 years

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $)	Total	Preferred Stock	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock
Balance at Dec. 31, 2009	$ (4,193,399)		$ 10,779	$ 221,327,257	$ (225,401,140)	$ (130,295)
Balance (in shares) at Dec. 31, 2009			107,789,597
Increase (Decrease) in Shareholders' Equity
Issuance of preferred stock	19,364,000	306		19,363,694
Issuance of preferred stock (in shares)		305,754
Reclassification of debt derivative	15,358,616			15,358,616
Conversion of preferred stock into common stock	(52,824)	(80)	1,336	(54,080)
Conversion of preferred stock into common stock (in shares)		(80,154)	13,359,001
Stock compensation	1,331,839		11	1,331,828
Stock compensation (in shares)			107,150
Net (loss) income	10,127,020				10,127,020
Balance at Dec. 31, 2010	41,935,252	226	12,126	257,327,315	(215,274,120)	(130,295)
Balance (in shares) at Dec. 31, 2010		225,600	121,255,748
Increase (Decrease) in Shareholders' Equity
Conversion of preferred stock into common stock		(35)	576	(541)
Conversion of preferred stock into common stock (in shares)		(34,600)	5,766,667
Issuance of common stock	4,677,428		4,100	4,673,328
Issuance of common stock (in shares)			41,000,000
Stock compensation	344,190		6	344,184
Stock compensation (in shares)			62,100
Net (loss) income	(7,301,645)				(7,301,645)
Balance at Dec. 31, 2011	39,655,225	191	16,808	262,344,286	(222,575,765)	(130,295)
Balance (in shares) at Dec. 31, 2011		191,000	168,084,515
Increase (Decrease) in Shareholders' Equity
Conversion of preferred stock into common stock		(9)	149	(140)
Conversion of preferred stock into common stock (in shares)		(8,935)	1,489,166
Stock compensation	280,797		25	280,772
Stock compensation (in shares)			250,000
Net (loss) income	(22,232,391)				(22,232,391)
Balance at Dec. 31, 2012	$ 17,703,631	$ 182	$ 16,982	$ 262,624,918	$ (244,808,156)	$ (130,295)
Balance (in shares) at Dec. 31, 2012		182,065	169,823,681

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ASSET SALES AND ACQUISITIONS

12 Months Ended

Dec. 31, 2012

ASSET SALES AND ACQUISITIONS

ASSET SALES AND ACQUISITIONS

NOTE 4 — ASSET SALES AND ACQUISITIONS

Uinta Basin Joint Venture

On March 22, 2012, the Company closed a 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. If the Company is not able to pay its share of the above costs, it may lose certain rights granted under the Development Agreement and related operating agreements, including the right to continue as operator or contract operator of the properties, the right to make proposals or elect to participate in operations under the Development Agreement or any operating agreement, the right to call, attend and vote at meetings of the operating committee, the right to transfer its interest in the properties and the joint venture, the right to acquire Wapiti’s interest in the properties under the right of first offer provisions of the Development Agreement and the right to acquire its pro rata share of additional properties acquired by Wapiti within the area of mutual interest identified in the Development Agreement. We have not incurred any costs to date and there is substantial doubt regarding our ability to fund our share of the drilling and completion 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, 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.  However, to the extent that Gasco Production Company, as operator under these agreements, becomes insolvent, bankrupt or is placed into receivership, it will be deemed to have resigned as operator or the other party may have a termination right.  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 the Company 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 the Company or Wapiti upon six months’ advance notice.

Due to low natural gas prices and permitting delays, the Company did not drill any natural gas wells in Utah from the closing of the Uinta Basin Transaction through the remainder of 2012.

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.

The Company used approximately $10.5 million of the proceeds from the transaction to repay the borrowings under its prior revolving credit facility. The Company planned to use the remaining proceeds for its capital expenditures consisting of approximately $5.0 million 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 low natural gas prices and permitting delays, the Company did not drill any natural gas wells in Utah during the remainder of 2012.

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, 2010, 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, 2010.

	For the Years Ended December 31,
	2012			2011			2010
Revenue as reported	$	8,879,673		$	18,335,608		$	20,262,099
Less: revenue from the Uinta Basin Transaction	1,206,145			6,382,289			7,052,865
Pro forma revenue	$	10,085,818		$	11,953,319		$	13,209,234
Net (loss) income as reported	$	(22,232,391	)	$	(7,301,645	)	$	10,127,020
Less: operating loss resulting from the Uinta Basin Transaction	(2,390,235		)	(816,119		)	(2,441,482		)
Pro forma net (loss) income	$	(19,842,156	)	$	(6,485,526	)	$	12,568,502	)
Net (loss) income per share — basic and diluted as reported	$	(0.13	)	$	(0.05	)	$	0.08
Less net (loss) income per share - from the Uinta Basin Transaction	(0.01		)	(0.01		)	(0.02		)
Pro forma net (loss) income per share — basic and diluted	$	(0.12	)	$	(0.04	)	$	(0.10	)

Working Interest Acquisition

During December 2012, the Company acquired additional working interests in 32 producing wells in the Riverbend area of Utah in which the Company has a working interest and operates for $177,620. The acquired interests range from 4% to 10% per well with an average of 8% per well.

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 one well to be drilled on the acreage. The proceeds were recorded as a credit to unproved properties during the year ended December 31, 2012.

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OIL AND GAS PROPERTY (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
OIL AND GAS PROPERTY
Costs of acreage reclassified from unproved properties into proved properties	$ 7,942,000	$ 660,000		$ 1,100,000
Decrease in the carrying value of acreage due to reclassification	7,000,000
Value of leases expired	942,000
Depreciation, depletion and amortization expense per Mcfe	1.07	0.91	0.82
Impairment expense per Mcfe	6.44
Balance
Acquisition costs	23,445,306			20,842,204
Exploration costs	8,041,008			5,663,452
Total	31,486,314	36,938,162		26,505,656
Cost incurred during period
Acquisition costs	1,762,979	673,351	166,772
Exploration costs	727,326	1,503,763	146,467
Total	$ 2,490,305	$ 2,177,114	$ 313,239
Period within which unproved costs will become subject to depletion	P5Y

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EMPLOYEE BENEFIT PLANS (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
EMPLOYEE BENEFIT PLANS
Percentage of each participating employee's compensation that the Company is required to contribute to the 401(k)Plan	3.00%
Contributions made by the Company	$ 129,354	$ 118,573	$ 127,169

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)

12 Months Ended

Dec. 31, 2012

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)

NOTE 21 — SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)

The following reserve quantity and future net cash flow information for the Company represents estimated proved reserves located in the United States. The reserves as of December 31, 2012, 2011 and 2010 have been estimated by Netherland, Sewell and Associates, Inc., independent petroleum engineers. The determination of oil and gas reserves is based on estimates, which are highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available.

The standardized measure of discounted future net cash flows is prepared under the guidelines set forth by the Securities and Exchange Commission (the “SEC”) which requires the use of the average, first-of-the-month price. The oil and gas prices weighted by production over the lives of the proved reserves used as of December 31, 2012, 2011 and 2010 were $80.25 per Bbl and $2.15 per Mcf of gas, $81.35 per Bbl and $3.59 per Mcf of gas, and $64.97 per Bbl of oil and $3.62 per Mcf of gas, respectively. Future production costs are based on year-end costs and include severance taxes. Each property that is operated by the Company is also charged with field-level overhead in the reserve calculation. The present value of future cash inflows is based on a 10% discount rate.

Reserve Quantities

	Gas		Oil
	Mcf		Bbls
Proved Reserves:
Balance, December 31, 2009	44,229,950		450,858
Extensions and discoveries	—		—
Revisions of previous estimates (a)	632,807		68,912
Sales of reserves in place	(2,213,000	)	(19,000	)
Purchases of reserves in place	1,181,442		4,421
Production	(4,105,139	)	(40,532	)
Balance, December 31, 2010	39,726,060		464,659
Extensions and discoveries	—		33,382
Revisions of previous estimates (a)	732,040		40,866
Sales of reserves in place	—		—
Purchases of reserves in place	—		—
Production	(3,659,790	)	(36,852	)
Balance, December 31, 2011	36,798,310		502,055
Extensions and discoveries	—		10,400
Revisions of previous estimates (b)	(10,110,081	)	(28,351	)
Sales of reserves in place	(12,251,600	)	(210,500	)
Purchases of reserves in place	573,600		3,800
Production	(2,406,512	)	(25,805	)
Balance, December 31, 2012	12,603,717		251,599

	Gas	Oil
	Mcf	Bbls
Proved Developed Reserves
Balance, December 31, 2012	12,603,717	251,599
Balance, December 31, 2011	36,798,310	502,055
Balance, December 31, 2010	39,726,060	464,659

(a) Better than anticipated existing well performances related to behind pipe reserves that began producing during both years yielded positive reserve revisions during the years ended December 31, 2011 and 2010.

(b) Downward revisions during the year ended December 31, 2012 are comprised of the following:

	Gas		Oil
	Mcf		Bbls
Commodity price decreases	(5,489,900	)	(30,400	)
Lease operating expense estimate revisions	(3,558,800	)	(25,300	)
Revision due to well performance	(1,061,381	)	27,349
Revisions of previous estimates	(10,110,081	)	(28,351	)

Standardized Measure of Discounted Future Net Cash Flows

	December 31,
	2012			2011			2010
Future cash flows	$	47,303,900		$	172,844,800		$	173,982,700
Future production and development costs	(31,144,200		)	(92,505,100		)	(91,157,000		)
Future income taxes (a)	—			—			—
Future net cash flows before discount	16,159,700			80,339,700			82,825,700
10% discount to present value	(5,842,100		)	(35,689,700		)	(35,898,700		)
Standardized measure of discounted future net cash flows	$	10,317,600		$	44,650,000		$	46,927,000

(a) The calculations of standardized measure do not include deductions for future income tax expenses because the tax basis of the properties involved and the future tax deductions were greater than the net cash flows from the proved oil and gas reserves for the years ended December 31, 2012, 2011 and 2010.

Changes in the Standardized Measure of Discounted Future Net Cash Flows

	For the Years Ended December 31,
	2012			2011			2010
Standardized measure of discounted future net cash flows at the beginning of year	$	44,650,000		$	46,927,000		$	35,561,400
Sales of oil and gas produced, net of production costs	(3,919,636		)	(9,549,780		)	(13,643,312		)
Net changes in prices and production costs	(12,419,867		)	1,499,400			12,137,633
Extensions and discoveries, net of future production and development costs	45,618			224,640			—
Previously estimated development costs incurred	13,818			1,781,487			4,411,807
Changes in estimated future development costs	(872,576		)	148,872			2,556,404
Revisions of previous quantity estimates	(7,515,377		)	1,096,031			1,154,884
Purchases of reserves in place	647,899			—			2,228,917
Sales of reserves in place	(14,681,586		)	—			(1,663,100		)
Accretion of discount	3,861,014			4,073,524			3,398,429
Other	508,293			(1,551,174		)	783,938
Standardized measure of discounted future net cash flows at the end of year	$	10,317,600		$	44,650,000		$	46,927,000

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SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)

Schedule of reserve quantities

Reserve Quantities

	Gas		Oil
	Mcf		Bbls
Proved Reserves:
Balance, December 31, 2009	44,229,950		450,858
Extensions and discoveries	—		—
Revisions of previous estimates (a)	632,807		68,912
Sales of reserves in place	(2,213,000	)	(19,000	)
Purchases of reserves in place	1,181,442		4,421
Production	(4,105,139	)	(40,532	)
Balance, December 31, 2010	39,726,060		464,659
Extensions and discoveries	—		33,382
Revisions of previous estimates (a)	732,040		40,866
Sales of reserves in place	—		—
Purchases of reserves in place	—		—
Production	(3,659,790	)	(36,852	)
Balance, December 31, 2011	36,798,310		502,055
Extensions and discoveries	—		10,400
Revisions of previous estimates (b)	(10,110,081	)	(28,351	)
Sales of reserves in place	(12,251,600	)	(210,500	)
Purchases of reserves in place	573,600		3,800
Production	(2,406,512	)	(25,805	)
Balance, December 31, 2012	12,603,717		251,599

	Gas	Oil
	Mcf	Bbls
Proved Developed Reserves
Balance, December 31, 2012	12,603,717	251,599
Balance, December 31, 2011	36,798,310	502,055
Balance, December 31, 2010	39,726,060	464,659

(a) Better than anticipated existing well performances related to behind pipe reserves that began producing during both years yielded positive reserve revisions during the years ended December 31, 2011 and 2010.

(b) Downward revisions during the year ended December 31, 2012 are comprised of the following:

	Gas		Oil
	Mcf		Bbls
Commodity price decreases	(5,489,900	)	(30,400	)
Lease operating expense estimate revisions	(3,558,800	)	(25,300	)
Revision due to well performance	(1,061,381	)	27,349
Revisions of previous estimates	(10,110,081	)	(28,351	)

Schedule of downward revisions of previous estimates of proved reserves

	Gas	Oil
	Mcf	Bbls
Proved Developed Reserves
Balance, December 31, 2012	12,603,717	251,599
Balance, December 31, 2011	36,798,310	502,055
Balance, December 31, 2010	39,726,060	464,659

Downward revisions during the year ended December 31, 2012 are comprised of the following:

	Gas		Oil
	Mcf		Bbls
Commodity price decreases	(5,489,900	)	(30,400	)
Lease operating expense estimate revisions	(3,558,800	)	(25,300	)
Revision due to well performance	(1,061,381	)	27,349
Revisions of previous estimates	(10,110,081	)	(28,351	)

Schedule of standardized measure of discounted future net cash flows

Standardized Measure of Discounted Future Net Cash Flows

	December 31,
	2012			2011			2010
Future cash flows	$	47,303,900		$	172,844,800		$	173,982,700
Future production and development costs	(31,144,200		)	(92,505,100		)	(91,157,000		)
Future income taxes (a)	—			—			—
Future net cash flows before discount	16,159,700			80,339,700			82,825,700
10% discount to present value	(5,842,100		)	(35,689,700		)	(35,898,700		)
Standardized measure of discounted future net cash flows	$	10,317,600		$	44,650,000		$	46,927,000

(a) The calculations of standardized measure do not include deductions for future income tax expenses because the tax basis of the properties involved and the future tax deductions were greater than the net cash flows from the proved oil and gas reserves for the years ended December 31, 2012, 2011 and 2010.

Schedule of changes in standardized measure of discounted future net cash flows

Changes in the Standardized Measure of Discounted Future Net Cash Flows

	For the Years Ended December 31,
	2012			2011			2010
Standardized measure of discounted future net cash flows at the beginning of year	$	44,650,000		$	46,927,000		$	35,561,400
Sales of oil and gas produced, net of production costs	(3,919,636		)	(9,549,780		)	(13,643,312		)
Net changes in prices and production costs	(12,419,867		)	1,499,400			12,137,633
Extensions and discoveries, net of future production and development costs	45,618			224,640			—
Previously estimated development costs incurred	13,818			1,781,487			4,411,807
Changes in estimated future development costs	(872,576		)	148,872			2,556,404
Revisions of previous quantity estimates	(7,515,377		)	1,096,031			1,154,884
Purchases of reserves in place	647,899			—			2,228,917
Sales of reserves in place	(14,681,586		)	—			(1,663,100		)
Accretion of discount	3,861,014			4,073,524			3,398,429
Other	508,293			(1,551,174		)	783,938
Standardized measure of discounted future net cash flows at the end of year	$	10,317,600		$	44,650,000		$	46,927,000

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INCOME TAXES

12 Months Ended

Dec. 31, 2012

INCOME TAXES

INCOME TAXES

NOTE 14 — INCOME TAXES

The provision (benefit) for income taxes for the years ended December 31, 2012, 2011 and 2010 consists of the following:

	2012			2011			2010
Current taxes:
Federal	$	—		$	—		$	—
State	—			—			—
Deferred taxes:
Deferred provision (benefit)	(5,615,970		)	55,013,560			12,151,778
Less: valuation allowance	5,615,970			(55,013,560		)	(12,151,778		)
Net income tax provision (benefit)	$	—		$	—		$	—

A reconciliation of the provision (benefit) for income taxes computed at the statutory rate to the provision for income taxes as shown in the consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010 is summarized below:

	2012			2011			2010
Tax provision (benefit) at federal statutory rate	$	(7,781,337	)	$	(2,555,576	)	$	3,544,457
State taxes, net of federal tax effects	(524,611		)	(167,581		)	2,573,856
Change in tax rate from prior year	(642		)	7,030			25,267
Permanent items and other	2,690,620			(243,639		)	6,008,198
Loss of NOL from Sec. 382 Limitation	—			57,973,328			—
Valuation allowance	5,615,970			(55,013,560		)	(12,151,778		)
Net income tax provision (benefit)	$	—		$	—		$	—

The components of the deferred tax assets and liabilities as of December 31, 2012 and 2011 are as follows:

	2012			2011
Deferred tax assets:
Federal and state net operating loss carryovers	$	20,790,664		$	20,172,061
Oil and gas property and other property, plant & equipment	1,995,698			—
Deferred compensation	2,357,410			2,344,155
Deferred gain on sale of assets	920,235			994,149
Accrued salaries and bonus	88,169			82,049
Asset Retirement Obligation	304,728			457,535
Other	130,920			316,516
Total deferred tax assets	26,587,824			24,366,465
Less: valuation allowance	(25,419,167		)	(19,803,198		)
	1,168,657			4,563,268
Deferred tax liabilities:
Oil and gas property and other property, plant & equipment	—			4,314,889
Derivatives	1,168,657			248,379
Total deferred tax liabilities	1,168,657			4,563,268
Net deferred tax asset	$	—		$	—

The Company has $54,541,750 of net operating loss carryovers for federal income tax purposes as of December 31, 2012, of which $3,030,233 is not benefited for financial statement purposes as it relates to tax deductions that deviate from compensation expense for financial statement purposes. The benefit of these excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce taxes payable.  The Company has $41,063,071 of net operating loss carryovers for state income tax purposes as of December 31, 2012, of which the above excess tax deductions have similarly not been benefited for financial statement purposes. The net operating losses may offset against taxable income through the year ended December 31, 2032. A portion of the net operating loss carryovers begins expiring in 2019.  The Company has analyzed the implications of an ownership change pursuant to IRC Section 382 on its net operating losses and has made appropriate adjustments to the federal and state net operating loss carryovers and related deferred tax assets in its financial statements.  Such adjustments have no impact on the financial statements as the Company’s deferred tax assets net of liabilities are subject to a full valuation allowance.  The Company provided a valuation allowance against its net deferred tax asset of $25,301,485 and $19,803,198 as of December 31, 2012 and 2011, respectively, since it believes that it is more likely than not that the net deferred tax assets will not be fully realized on future income tax returns. The decrease and increase in the valuation allowance for 2012 and 2011 is $5,498,287 and $(55,013,560), respectively.