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FORM10-K

GASCO ENERGY INC - GSXN

Filed: March 06, 2013 (period: December 31, 2012)

Annual report with a comprehensive overview of the company

The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user

assumes all risks for any damages or losses arising from any use of this information, except to the extent such damages or losses cannot be

limited or excluded by applicable law. Past financial performance is no guarantee of future results.
Table of Contents

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 x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted

and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to

submit and post such files). Yes x No o

Indicate by check mark 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.

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
Table of Contents

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 5 9

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,

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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;

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
· 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 forwardlooking 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.

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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-dayof-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,

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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.

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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 nonemployee 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 nonemployee 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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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.

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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 nonwildcat 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.

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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 nongovernmental 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.

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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.

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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.

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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 firstday-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

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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;

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· 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

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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.

35

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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.

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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:

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· 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;

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· 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.

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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.

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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;

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
· 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.

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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 NASDAQtraded 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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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-ofthe-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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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 — — — — — —

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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.

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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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 prepackage, 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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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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:

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· 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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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 than

5 years

Convertible 2015 Notes

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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 unitsof-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.

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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.

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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)%

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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 firstday-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.

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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, thirdparty 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%

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Workover expense 2,490,613 361,170 2,129,443 590%

Total operating expenses $ 8,160,646 $ 5,140,084 $ 3,020,562 5 9%

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 6 5%

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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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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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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

Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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) — —

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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,

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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,

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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

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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.

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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, t he 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 firstday-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.

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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 weightedaverage 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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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.

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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.

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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 thencurrent 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

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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.

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
(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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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:

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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 nongovernmental 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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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
(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 13a15(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.

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Table of Contents

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.

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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.

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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

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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).

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#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,

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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***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.

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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

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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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).

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# 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).

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
# 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).

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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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
EXHIBIT 10.19

Contract #9330

AMENDMENT TO GAS PROCESSING AGREEMENT

This Amendment to Gas Processing Agreement (“Amendment”) is made and entered into this 1 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.

1

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

st

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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%

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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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 15d15(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

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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 15d15(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

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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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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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

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
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

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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. Behindpipe 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.

1

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information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.
(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.

2

(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

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(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

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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.

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(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%

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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

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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.

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(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.

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(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.

7

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

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Source: GASCO ENERGY INC, 10-K, March 06, 2013 Powered by Morningstar®

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The information contained herein may not be copied, adapted or distributed and is not warranted to be accurate, complete or timely. The user assumes all risks for any damages or losses arising from any use of this

information, except to the extent such damages or losses cannot be limited or excluded by applicable law. Past financial performance is no guarantee of future results.