Summary of Significant Accounting Policies (Policies)	12 Months Ended
Dec. 31, 2011
Accounting Policies [Abstract]
Basis of Presentation	These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Certain amounts in prior years' financial statements have been reclassified to conform to the 2011 financial statement presentation.
Assumptions, Judgements, and Estimates	In the course of preparing the financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established. The more significant areas requiring the use of assumptions, judgments, and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) valuation of derivative instruments; and (8) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents	The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. The Company's cash management process provides for the daily funding of checks as they are presented to the bank.
Accounts Receivable	Trade accounts receivable consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and natural gas receivables are collected within two months.
Bad debt recovery	The Company recognized $38.5 million in bad debt expense in the year ended December 31, 2008 related to the Flying J bankruptcy. On July 6, 2010, the Joint Plan of Reorganization of Flying J was confirmed under Chapter 11 of the United States Bankruptcy Code. Additionally, the United States Bankruptcy Court approved and confirmed the June 15, 2010 Stipulation and Agreed Order (the Stipulation) with Flying J regarding the resolution of the Company's claim in Flying J's pending bankruptcy. Pursuant to the Stipulation, Flying J agreed that the total amount owed to the Company by Flying J was $60.5 million and, as a result, the Company received $60.5 million in cash on July 23, 2010. In the quarter ended September 30, 2010, the Company recorded a settlement of the Company's Flying J bankruptcy claim of $22.0 million and a bad debt recovery of $38.5 million.
Discontinued operations	In 2009, the Company sold its DJ assets, the results of operations of which are reported as discontinued operations in the 2009 Statements of Operations. See Note 2 to the Financial Statements.
Income Taxes and Uncertain Tax Positions	The Company recognizes deferred income tax liabilities and assets for the expected future income tax consequences of temporary differences between financial accounting bases and income tax bases of assets and liabilities. Deferred income taxes are measured by applying currently enacted income tax rates. The Company accounts for uncertainty in income taxes for income tax positions taken or expected to be taken in an income tax return. Only income tax positions that meet the more-likely-than-not recognition threshold will be recognized.
Derivatives Instruments	The Company enters into derivative contracts, primarily swaps and collars, to manage its exposure to commodity price risk. All derivative instruments, other than those that meet the "normal purchases normal sales" exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. The Company is required to formally document, at the inception of a hedge, the hedging relationship and the risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment. Effective January 1, 2010, the Company elected to discontinue all hedge accounting prospectively. As a result, subsequent to December 31, 2009, the Company records all derivative instruments as either assets or liabilities at fair value and recognizes all gains and losses from changes in derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive loss (AOCL). See Notes 8 and 9 to the Financial Statements. Cash settlements of derivative instruments used to manage commodity price risk are classified as cash flows from operating activities in the Statements of Cash Flows along with the cash flows from the related oil and natural gas production activities. The Company nets derivative assets and liabilities of a given counterparty whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The Company uses these agreements to manage and reduce its potential counterparty credit risk. The Company does not enter into derivative instruments for speculative or trading purposes.
Oil and Gas Properties, Building and Equipment	The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive. The provision for depletion of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis. Buildings and equipment are recorded at cost. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment. Capitalized Interest Acquisition costs of proved undeveloped and unproved properties qualify for interest capitalization during a period if interest cost is incurred and activities necessary to bring the properties into a productive state are in progress. As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re-designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re-designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field. Impairment of Proved and Unproved Properties Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows. Due to the impact of lower natural gas prices, the Company recorded an impairment of $625.0 million related to its E. Texas natural gas assets. See Notes 9 and 11 to the Financial Statements.
Assets Held for Sale	Any properties held for sale as of the date of presentation of the balance sheets have been classified as assets held for sale and are separately presented on the balance sheets at the lower of net book value or fair value less the cost to sell
Asset Retirement Obligations	The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability
Deferred Financing Costs	Costs incurred in connection with the execution or modification of the Company’s credit facility, and in connection with the Company's senior and subordinated notes, are capitalized and amortized over the life, or expected life, of the debt using the effective interest method.
Revenue Recognition	Revenues associated with sales of oil, natural gas, electricity and natural gas marketing are recognized when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. The electricity and natural gas the Company produces and uses in its operations are not included in revenues. Revenues from oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of its net working interest. Revenues are also derived from natural gas marketing sales, which represent excess capacity on the Rockies Express, Wyoming Interstate, and Ruby pipelines used by the Company to market natural gas for its working interest partners and other third parties.
Significant Customers	The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and electricity to utility companies. Credit is extended based on an evaluation of the customer's financial condition and historical payment record. The Company does not believe that the loss of any one customer would impact the marketability of its products, but it may impact the profitability of its oil, natural gas or electricity sold. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the Company's crude oil sales customer in Utah could impact the marketability of a portion of the Company's Utah crude oil volumes.
Concentrations of Market Risk	The results of the Company's oil and natural gas operations are impacted by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future depends on numerous factors beyond the Company's control, including weather, imports, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil and natural gas products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. The Company places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution.
Electricity Cost Allocation	The Company owns three cogeneration facilities. Its investment in cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power (CHP), extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. The Company allocates steam costs to its oil and natural gas operating costs based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to utility companies. A portion of the capital costs of the cogeneration facilities is allocated to DD&A—oil and natural gas production. Electricity production used in oil and natural gas operations is allocated to operating costs
Transportation Costs	Natural gas transportation costs are included in either operating costs—oil and natural gas production or operating costs—electricity generation, as applicable.
Share-based Compensation	The Company recognizes the grant date fair value of stock options and other stock based compensation issued in the Statements of Operations. Expense is recognized on a straight-line basis over the employee's requisite service period (generally the vesting period of the award).
(Loss) Earnings Per Share	The two-class method of computing earnings per share is required for entities that have participating securities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Unvested restricted stock issued prior to January 1, 2010, under the Company's equity incentive plans, has the right to receive non-forfeitable dividends, participating on an equal basis with common stock, and thus these securities are classified as participating securities. Participating securities do not have a contractual obligation to share in the Company's losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating securities. Unvested restricted stock issued subsequent to January 1, 2010, under the Company's equity incentive plans does not participate in dividends. Stock options issued under the Company's equity incentive plans do not participate in dividends. Basic (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-basic during each period. Under the treasury stock method, diluted (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-dilutive, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of non-participating unvested restricted stock awards and outstanding stock options. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted (loss) earnings per share.
Equity Method Investments	The Company's net investment in these entities is included under the caption other assets on its Balance Sheets.
Comprehensive (Loss) Earnings	Comprehensive (loss) earnings is a term used to refer to net (loss) earnings plus other comprehensive earnings (loss). Other comprehensive (loss) earnings is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders' equity instead of net (loss) earnings.
Industy Segment and Geographic Information	The Company operates in one industry segment, which is the exploration, development, and production of oil and natural gas, and all of the Company's operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Certain amounts in prior years' financial statements have been reclassified to conform to the 2011 financial statement presentation.

Assumptions, Judgements, and Estimates

In the course of preparing the financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

The more significant areas requiring the use of assumptions, judgments, and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) valuation of derivative instruments; and (8) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a remaining maturity of three months or less to be cash equivalents. The Company's cash management process provides for the daily funding of checks as they are presented to the bank.

Accounts Receivable

Trade accounts receivable consist mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and natural gas receivables are collected within two months.

Bad debt recovery

The Company recognized $38.5 million in bad debt expense in the year ended December 31, 2008 related to the Flying J bankruptcy. On July 6, 2010, the Joint Plan of Reorganization of Flying J was confirmed under Chapter 11 of the United States Bankruptcy Code. Additionally, the United States Bankruptcy Court approved and confirmed the June 15, 2010 Stipulation and Agreed Order (the Stipulation) with Flying J regarding the resolution of the Company's claim in Flying J's pending bankruptcy. Pursuant to the Stipulation, Flying J agreed that the total amount owed to the Company by Flying J was $60.5 million and, as a result, the Company received $60.5 million in cash on July 23, 2010. In the quarter ended September 30, 2010, the Company recorded a settlement of the Company's Flying J bankruptcy claim of $22.0 million and a bad debt recovery of $38.5 million.

Discontinued operations

In 2009, the Company sold its DJ assets, the results of operations of which are reported as discontinued operations in the 2009 Statements of Operations. See Note 2 to the Financial Statements.

Income Taxes and Uncertain Tax Positions

The Company recognizes deferred income tax liabilities and assets for the expected future income tax consequences of temporary differences between financial accounting bases and income tax bases of assets and liabilities. Deferred income taxes are measured by applying currently enacted income tax rates. The Company accounts for uncertainty in income taxes for income tax positions taken or expected to be taken in an income tax return. Only income tax positions that meet the more-likely-than-not recognition threshold will be recognized.

Derivatives Instruments

The Company enters into derivative contracts, primarily swaps and collars, to manage its exposure to commodity price risk. All derivative instruments, other than those that meet the "normal purchases normal sales" exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. The Company is required to formally document, at the inception of a hedge, the hedging relationship and the risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment. Effective January 1, 2010, the Company elected to discontinue all hedge accounting prospectively. As a result, subsequent to December 31, 2009, the Company records all derivative instruments as either assets or liabilities at fair value and recognizes all gains and losses from changes in derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive loss (AOCL). See Notes 8 and 9 to the Financial Statements. Cash settlements of derivative instruments used to manage commodity price risk are classified as cash flows from operating activities in the Statements of Cash Flows along with the cash flows from the related oil and natural gas production activities. The Company nets derivative assets and liabilities of a given counterparty whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The Company uses these agreements to manage and reduce its potential counterparty credit risk. The Company does not enter into derivative instruments for speculative or trading purposes.

Oil and Gas Properties, Building and Equipment

The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive.

The provision for depletion of oil and natural gas properties is calculated on a field-by-field basis using the unit-of-production method. If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis.

Buildings and equipment are recorded at cost. Depreciation is calculated on a straight-line basis over estimated useful lives ranging from 5 to 30 years for buildings and improvements and 3 to 10 years for machinery and equipment.

Capitalized Interest

Acquisition costs of proved undeveloped and unproved properties qualify for interest capitalization during a period if interest cost is incurred and activities necessary to bring the properties into a productive state are in progress. As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re-designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re-designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

Impairment of Proved and Unproved Properties

Proved oil and natural gas properties are reviewed for impairment on a field-by-field basis, annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, and discount rates commensurate with the risk associated with realizing the projected cash flows. Due to the impact of lower natural gas prices, the Company recorded an impairment of $625.0 million related to its E. Texas natural gas assets. See Notes 9 and 11 to the Financial Statements.

Assets Held for Sale

Any properties held for sale as of the date of presentation of the balance sheets have been classified as assets held for sale and are separately presented on the balance sheets at the lower of net book value or fair value less the cost to sell

Asset Retirement Obligations

The Company's asset retirement obligations (AROs) relate to future costs associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred (typically when the asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability

Deferred Financing Costs

Costs incurred in connection with the execution or modification of the Company’s credit facility, and in connection with the Company's senior and subordinated notes, are capitalized and amortized over the life, or expected life, of the debt using the effective interest method.

Revenue Recognition

Revenues associated with sales of oil, natural gas, electricity and natural gas marketing are recognized when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. The electricity and natural gas the Company produces and uses in its operations are not included in revenues. Revenues from oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of its net working interest. Revenues are also derived from natural gas marketing sales, which represent excess capacity on the Rockies Express, Wyoming Interstate, and Ruby pipelines used by the Company to market natural gas for its working interest partners and other third parties.

Significant Customers

The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and electricity to utility companies. Credit is extended based on an evaluation of the customer's financial condition and historical payment record. The Company does not believe that the loss of any one customer would impact the marketability of its products, but it may impact the profitability of its oil, natural gas or electricity sold. Due to the possibility of refinery constraints in the Utah region, it is possible that the loss of the Company's crude oil sales customer in Utah could impact the marketability of a portion of the Company's Utah crude oil volumes.

Concentrations of Market Risk

The results of the Company's oil and natural gas operations are impacted by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future depends on numerous factors beyond the Company's control, including weather, imports, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil and natural gas products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

The Company places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution.

Electricity Cost Allocation

The Company owns three cogeneration facilities. Its investment in cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power (CHP), extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. The Company allocates steam costs to its oil and natural gas operating costs based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. Electricity revenue represents sales to utility companies. A portion of the capital costs of the cogeneration facilities is allocated to DD&A—oil and natural gas production. Electricity production used in oil and natural gas operations is allocated to operating costs

Transportation Costs

Natural gas transportation costs are included in either operating costs—oil and natural gas production or operating costs—electricity generation, as applicable.

Share-based Compensation

The Company recognizes the grant date fair value of stock options and other stock based compensation issued in the Statements of Operations. Expense is recognized on a straight-line basis over the employee's requisite service period (generally the vesting period of the award).

(Loss) Earnings Per Share

The two-class method of computing earnings per share is required for entities that have participating securities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Unvested restricted stock issued prior to January 1, 2010, under the Company's equity incentive plans, has the right to receive non-forfeitable dividends, participating on an equal basis with common stock, and thus these securities are classified as participating securities. Participating securities do not have a contractual obligation to share in the Company's losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating securities. Unvested restricted stock issued subsequent to January 1, 2010, under the Company's equity incentive plans does not participate in dividends. Stock options issued under the Company's equity incentive plans do not participate in dividends.

Basic (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-basic during each period. Under the treasury stock method, diluted (loss) earnings per share is calculated by dividing (loss) earnings available to common shareholders by the weighted average shares-dilutive, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of non-participating unvested restricted stock awards and outstanding stock options. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted (loss) earnings per share.

Equity Method Investments

The Company's net investment in these entities is included under the caption other assets on its Balance Sheets.

Comprehensive (Loss) Earnings

Comprehensive (loss) earnings is a term used to refer to net (loss) earnings plus other comprehensive earnings (loss). Other comprehensive (loss) earnings is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of shareholders' equity instead of net (loss) earnings.

Industy Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development, and production of oil and natural gas, and all of the Company's operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment