GSX Gasco Energy, Inc.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 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

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

(Address of principal executive offices)       (Zip Code)

(303) 483-0044

(Registrant’s telephone number, including area code)

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

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

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

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

Number of common shares outstanding as of November 14, 2012:  169,749,981

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Cautionary Statement Regarding Forward-Looking Statements

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

Although any forward-looking statements contained in this Quarterly Report on Form 10-Q or otherwise expressed by us are, to the knowledge and in the judgment of our management, believed to be reasonable when made, there can be no assurances that any of these expectations will prove correct or that any of the actions that are planned will be taken. Forward-looking statements involve and can be affected by inaccurate assumptions or by known and unknown risks and uncertainties (some of which are beyond our control) which may cause our actual performance and financial results in future periods to differ materially from any projection, estimate or forecasted result. Known material factors that could cause actual results to differ materially from expected results are discussed under Part I, Item 1A “Risk Factors” and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2011 and under Part II, Item 1A “Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q. Additional risks or uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or future results.

In addition to those discussed in our Annual Report on Form 10-K for the year ended December 31, 2011 and in subsequent Quarterly Reports on Form 10-Q, the following are among the factors that could cause future results to differ materially and adversely from those projected, forecasted, estimated or budgeted and discussed in this Quarterly Report on Form 10-Q:

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

·                   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;

·                   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;

·                   the volatility and recent declines in our stock price, and our ability to remain in compliance with the NYSE MKT’s continued listing requirements;

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·                   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 our debt agreements;

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

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

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

·                   marketing of oil and natural gas;

·                   pipeline constraints;

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

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

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

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

·                   technological changes;

·                   competition;

·                   scope and extent of our insurance coverage;

·                   title defects and deficiencies;

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

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

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

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

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

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GLOSSARY OF NATURAL GAS AND OIL TERMS

The following is a description of the meanings of some of the natural gas and oil industry terms that may be used in this Quarterly Report on Form 10-Q.

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

Bbl/d .  One Bbl per day.

Bcf .  Billion cubic feet of natural gas.

Bcfe .  Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Btu or British Thermal Unit .  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion .  The installation of permanent equipment for the production of natural gas or oil, or in the case of a dry well, the reporting of abandonment to the appropriate agency.

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

Developed acreage .  The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well .  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

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

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

Farm-in or farm-out .  An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage.  Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage.  The assignor usually retains a royalty or reversionary interest in the lease.  The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

Field .  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells .  The total acres or wells, as the case may be, in which a working interest is owned.

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

Mcf .  Thousand cubic feet of natural gas.

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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.

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

Prospect .  A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved area .  The part of a property to which proved reserves have been specifically attributed.

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

Proved reserves or proved oil and gas reserves . Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved properties .  Properties with proved reserves.

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Proved undeveloped reserves .  Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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

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

Undeveloped acreage .  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

Unproved properties .  Properties with no proved reserves.

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

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

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

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

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

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GASCO ENERGY, INC.

NOTES TO UNAUDITED CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011

NOTE 1 – ORGANIZATION AND LIQUIDITY

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

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

The accompanying unaudited condensed 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 extreme volatility in commodity prices in recent years, and the significant extended decline in natural gas prices in particular, the Company has not been able to recover its exploration and development costs as anticipated.  There are significant uncertainties regarding the Company’s ability to generate sufficient cash flows from operations to fund its ongoing operations and planned capital activities, and the Company currently anticipates that cash on hand and forecasted cash flows from operations will only be sufficient to fund cash requirements for working capital, including debt payment obligations, and planned capital expenditures 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.  The Company’s prior revolving credit facility matured on June 29, 2012, and as of the date of this Quarterly 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 three and nine months ended September 30, 2012 and at September 30, 2012 had an accumulated deficit of $235,956,378.

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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’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, it would not have adequate liquidity to fund its operations and meet its obligations (including its debt payment obligations) for the next twelve months, 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 it).  The accompanying unaudited condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets, carrying amounts, or the amount and classification of liabilities that may result, should the Company be unable to continue as a going concern.

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

·                   reducing expenditures by eliminating, delaying or curtailing discretionary and non-essential spending;

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.

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

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Oil and Gas Properties

The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, internal costs directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $0 and $11,520 of internal costs during the three and nine months ended September 30, 2012, respectively, and $0 and $75,167 during the three and nine months ended September 30, 2011,

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respectively. Additionally, the Company capitalized stock compensation expense related to its consultants as further described in Note 7 – Stock-Based Compensation herein. Costs associated with production and general corporate activities are expensed in the period incurred. The Company charges a marketing fee related to the sale of its natural gas production to the wells in which it is the operator and, therefore, the net income attributable to the outside working interest owners from such marketing activities of $37,896 and $69,700 was recorded as an adjustment to proved properties during the three and nine months ended September 30, 2012, respectively, and $22,017 and $88,352 during the three and nine months ended September 30, 2011. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to a cost center.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. Please see Note 3 – Asset Sales, herein.

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include: (i) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion; (ii) estimated future development costs to be incurred in developing proved reserves; and (iii) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties of $37,641,327 as of September 30, 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. During the nine months ended September 30, 2012, the Company reclassified approximately $731,000 of acreage costs in Utah and California into proved property. This acreage represents the value of leases that expired during the third quarter of 2012.

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

Under the full cost method of accounting, the ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (i) 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 (ii) the cost of properties not being amortized, if any; plus (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (iv) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent the excess capitalized costs exceed this ceiling limitation. The present value of estimated future net revenues is computed by applying the average first-day-of-the-month oil and gas price during the 12-month period ended September 30, 2012 to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. As of March 31, 2012, June 30, 2012 and September 30, 2012, the full cost pool exceeded the ceiling limitation based on the average first-day-of-the-month oil and gas prices of $82.58 per barrel and $2.94 per Mcf during the 12-month period ended March 31, 2012, $81.16 per barrel and $2.57 per Mcf during the 12-month period ended June 30, 2012 and $80.35 per barrel and $2.23 per Mcf during the 12-month period ended September 30, 2012. Therefore, impairment expense of $9,071,000 was recorded during the nine months ended September 30, 2012.

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Wells in Progress

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

Facilities and Equipment

The Company’s other oil and gas equipment is depreciated using the straight-line method over an estimated useful life of five to ten years. The rental of the equipment owned by the Company is charged to the wells that are operated by the Company and, therefore, the net expense attributable to the outside working interest owners from the equipment rental was recorded as an adjustment to proved properties in the amount of $22,359 and $14,551 during the three and nine months ended September 30, 2012, respectively, and $9,502 and $57,977 during the three and nine months ended September 30, 2011, respectively.

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 unaudited condensed 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 5 – Derivatives, herein.

Warrants

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

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carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and gathering system using the units-of-production method. The Company’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties. The asset retirement liability is allocated to operating expense using a systematic and rational method.

The information below reconciles the value of the asset retirement obligation for the periods presented.

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

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.

Off Balance Sheet Arrangements

From time to time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of September 30, 2012, the off-balance sheet arrangements and transactions that the Company had entered into included operating lease agreements, gathering, compression, processing and water disposal agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

Computation of Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to common stockholders by the weighted-average number of common shares outstanding during the reporting period. The

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

The treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares that could have been repurchased by the Company with the proceeds from the exercise of the options (the repurchases of shares were assumed to have been made at the average market price of the common shares during the reporting period), is used to measure the dilutive impact of stock options, shares of restricted common stock, warrants and shares into which the 2015 Notes and Preferred Stock are convertible.

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

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

Use of Estimates

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

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

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instruments, estimates used in stock-based compensation calculations and impairments to unproved property and to proved oil and gas properties.

Reclassifications

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

Recently Issued Accounting Pronouncements

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

NOTE 3 – ASSET SALES

Uinta Basin Joint Venture

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

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

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

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

With respect to wells drilled pursuant to the drilling program, the net revenue interest attributable to such wells from the closing through the time when the cumulative proceeds received by Wapiti from such wells equals the amount of costs actually paid by Wapiti in respect of such wells and the drilling program (such time, “Payout”), will be allocated 32.5% to the Company and 67.5% to Wapiti. After Payout, the net revenue interest

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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.  The Company and Wapiti have formed an Operating Committee (the “Operating Committee”) to oversee generally the drilling program and operations in the project area and to approve certain matters specified in the Development Agreement. The Operating Committee consists of two members from each of the Company and Wapiti, with the members appointed by each party having an aggregate 50% vote.

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

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

The Company used approximately $10.5 million of the proceeds from the transaction to repay the borrowings under its prior revolving credit facility. The Company planned to use the remaining proceeds for its capital expenditures consisting of approximately $5.0 million for its drilling program which includes the drilling of 13 wells, its continued up-hole recompletion program targeting natural gas and for additional investment in existing and new California oil and gas prospects in the San Joaquin Basin as well as for working capital, acquisitions of oil and natural gas properties and other general corporate purposes. However, due to low natural gas prices and permitting delays, the Company does not expect to drill any natural gas wells in Utah during the remainder of 2012 and expects to spend only $3.9 million of its 2012 budget.

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

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drilled will be reclassified from unproved property to the full cost pool to be depleted and included in the ceiling test. The cost basis will be determined based on a per acre valuation multiplied by the number of acres for each drilling location.

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

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 nine months ended September 30, 2012.

NOTE 4 - CONVERTIBLE SENIOR NOTES

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

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

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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 2015 Indenture, which would permit the holders of the 2015 Notes to accelerate repayment of the 2015 Notes.

The 2015 Notes are convertible, at the option of the holder, at any time prior to maturity, into shares of common stock or, at the election of such holder, into Preferred Stock. The initial conversion price for converting the 2015 Notes into common stock is $0.60 per share of common stock, which is equal to a conversion rate of 1,666.6667 shares of common stock per $1,000 principal amount of 2015 Notes. The conversion rate is subject to adjustment in certain circumstances and limitations. The initial conversion price for converting the 2015 Notes into Preferred Stock is $100, which is equal to a conversion rate of ten shares of Preferred Stock per $1,000 principal amount of 2015 Notes. Pursuant to the 2015 Indenture, a holder may not convert all or any portion of such holder’s 2015 Notes into common stock to the extent that such holder and its affiliates would, after giving effect to such conversion, beneficially own more than 4.99% of the outstanding shares of common stock (the “Maximum Ownership Percentage”), provided that such holder, upon not less than 61 days’ prior written notice to the Company, may increase the Maximum Ownership Percentage applicable to such holder (but, for the avoidance of doubt, not for any subsequent or other holder) to 9.9% of the outstanding shares of common stock.

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

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

The 2015 Indenture contains usual and customary covenants limiting the Company’s ability to incur additional indebtedness, with certain exceptions, or liens on its property or assets, restricting its ability to make dividends or other distributions, requiring its domestic subsidiaries to guarantee the 2015 Notes, requiring it to list the

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shares of common stock that may be issued upon conversion of the 2015 Notes and the Preferred Stock on the NYSE MKT or any other U.S. national or regional securities exchange on which the common stock is then listed, and requiring it to use reasonable best efforts to obtain stockholder approval for the issuance of shares of common stock upon conversion of the 2015 Notes and upon conversion of any shares of Preferred Stock issuable upon conversion of the 2015 Notes.

The 2015 Notes are unsecured and unsubordinated and rank on a parity in right of payment with all of the Company’s existing and future senior unsecured indebtedness, rank senior in right of payment to any of the Company’s existing and future subordinated indebtedness, and are effectively subordinated in right of payment to any of the Company’s secured indebtedness or other obligations to the extent of the value of the assets securing such indebtedness or other obligations. The Company’s subsidiaries guarantee the 2015 Notes pursuant to a Guaranty Agreement dated as of June 25, 2010, by and among Gasco Production Company, 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 September 30, 2012 and December 31, 2011 was $19,622,007 and $22,574,687, respectively.

NOTE 5 – DERIVATIVES

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

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

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

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

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

NOTE 6 – GAS PROCESSING AGREEMENT

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

The primary term of the Chipeta Processing Agreement is ten years, beginning after the in-service date of a 300 MMcf/d cryogenic processing facility to be built by Chipeta. The primary term will be extended for one year terms unless terminated by either party giving 180 days’ notice prior to the expiration of the then-current term. Questar Pipeline Company has received the necessary regulatory approvals for the conversion of certain of its pipelines and facilities from a dry line to a wet line and has completed its system upgrades. Chipeta is in the final phase of the construction of its cryogenic and related pipeline facilities. The projected in-service date is January 1, 2013.

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

The Company’s natural gas production is presently being transported 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, (i) 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 (ii) 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 the Company is

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unable to meet certain drilling investment targets.  The Company may also be required to make periodic deficiency payments to Monarch for any shortfalls from the specified minimum volume commitment of 25,000 Mcf per day. The term of the Amended and Restated Monarch Agreement extends through February 28, 2025, and, for wells that are already connected to Monarch’s gathering system on February 28, 2025, for so long as the Company’s gas can be produced in commercial quantities from such wells.

NOTE 7 – STOCK-BASED COMPENSATION

The Company has outstanding common stock options, stock appreciation rights (“SARs”) and restricted stock issued under its equity incentive plans. The Company measures the fair value at the grant date for stock option grants and restricted stock awards and records compensation expense over the requisite service period. The expense recognized over the service period includes an estimate of the awards that will be forfeited.  The Company 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 unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair value on that date. During the three and nine months ended September 30, 2012 and 2011, the Company recognized stock-based compensation expense as follows:

Stock Options

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

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

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

The aggregate intrinsic value in the table above represents the total pretax intrinsic value based on the fair value of the Company’s common stock of $0.15 as of September 30, 2012, which would have been received by the option holders had they exercised their options as of that date.

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

As of September 30, 2012, there is $282,078 of total unrecognized compensation cost related to non-vested options granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 2.6 years.

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As of September 30, 2012, there is $74,266 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s equity incentive plans. That cost is expected to be recognized over a period of 2.6 years.

SARs

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

Effective February 28, 2012, the Company granted another SARs award (“February SARs”) related to a total of 1,000,000 shares of our common stock to these directors.  As of September 30, 2012, the SARs were recorded as a liability of $7,765.The February SARs provide the right to receive a lump sum cash payment equal to the value of the product of (i) the excess of (a) (A) the fair market value of one share of common stock on the date of exercise or (2) $2.00, whichever is less, over (b) $0.30, which is an amount greater than the closing price of a share of common stock on the date of grant, multiplied by (ii) the number of shares as to which an award has been exercised. The February SARs vest on January 31, 2013 and will be automatically exercised on February 1, 2013.

NOTE 8 – CREDIT FACILITY

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

While the Company has attempted to secure a replacement facility, as of the date of this Quarterly 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 9 – FAIR VALUE MEASUREMENTS

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

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

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

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

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below in all periods presented.

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