Summary of Significant Accounting Policies	12 Months Ended
Dec. 31, 2012
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	2. Summary of Significant Accounting Policies *Basis of Presentation* The accompanying consolidated financial statements of the Company have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") and have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). All intercompany transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year's consolidated financial statements and related footnotes to conform them to the current year presentation. The consolidated financial statements as of and for the year ended December 31, 2012 include the results from the Eagle Property Acquisition beginning October 1, 2012. *Use of Estimates* The preparation of financial statements in conformity with 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 those estimates. Significant estimates include, but are not limited to, the amount of recoverable oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; the fair value of commodity derivative contracts; the fair value of share-based compensation; and the valuation of future asset retirement obligations. *Cash and Cash Equivalents* The Company considers all short-term investments with an original maturity of three months or less to be cash equivalents. *Accounts Receivable and Allowance for Doubtful Accounts* Accounts receivable are stated at the historical carrying amount net of allowance for uncollectible accounts. The carrying amount of the Company's accounts receivable approximate fair value because of the short-term nature of the instruments. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2012 and 2011, the Company had no allowance for doubtful accounts. *Financial Instruments* The Company's financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivative contracts. Commodity derivative contracts are recorded at fair value (see Note 3). The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The carrying amount of the Company's other financial instruments approximate fair value because of the short-term nature of the items or variable pricing. See fair value discussion of Senior Notes and Series A Preferred Shares issued in October 2012 in Notes 8 and 10, respectively. Derivative financial instruments are recorded in the consolidated balance sheets as either an asset or liability measured at estimated fair value. Changes in the derivative's fair value are recognized currently in earnings as gains and losses in the period of change. The gains or losses are recorded in "Losses on commodity derivative contracts—net." The related cash flow impact is reflected within cash flows from operating activities. *Property and Equipment* Oil and Gas Properties The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company's reserve quantities are sold that results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income. Unevaluated Property Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. Oil and Gas Reserves Proved oil and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (FASB), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. The Company's reserve estimates at December 31, 2012, 2011 and 2010 were prepared by a third-party petroleum engineer, Netherland, Sewell & Associates, Inc. ("NSAI"). Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. Other Property and Equipment Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is provided principally using the straight-line method over the estimated useful lives of the assets, which range from five to seven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized. Impairment of Oil and Gas Properties/Ceiling Test Prior to March 31, 2012, the Company performed a ceiling test annually. Beginning with the quarter ended March 31, 2012, the Company now performs a ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may not exceed this "ceiling." The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations. See Note 5. Depreciation, Depletion, and Amortization (DD&A) DD&A of oil and gas properties is calculated using the Units of Production Method (UOP). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated DD&A, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. Capitalized Interest Interest from external borrowings is capitalized on unevaluated properties using the weighted-average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at the first production from the field. Capitalized interest is depleted over the useful lives of the assets in the same manner as the depletion of the underlying assets. The Company paid cash interest of $7.2 million, $4.2 million, and $1.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. *Accrued Liabilities* Accrued liabilities at December 31, 2012 consisted of $69.0 million in oil and gas capital expenditures, $16.2 million in accrued interest, and $13.4 million in other accrued liabilities. At December 31, 2011 the balance consisted of $28.5 million in oil and gas capital expenditures, and $9.0 million in other accrued liabilities. *Asset Retirement Obligations* The legal obligations associated with the retirement of long-lived assets are recognized at estimated fair value at the time that the obligation is incurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. The Company estimates the fair value of an asset retirement obligation in the period in which the obligation is incurred and can be reliably measured. The corresponding asset retirement cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, any adjustment is recorded in the full cost pool. See Note 7. *Share-Based Compensation* We account for share-based compensation awards in accordance with FASB ASC 718, Compensation—Stock Compensation. We measure share-based compensation cost at fair value and generally recognize the corresponding compensation expense on a straight-line basis over the service period during which awards are expected to vest. We include share-based compensation expense in "General and administrative expense" in our consolidated statements of operations. See Note 10. *Revenue Recognition* Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and collection of the revenues is reasonably assured. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met. The Company follows the sales method of accounting for oil and gas revenues, whereby revenue is recognized for all oil and gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil and gas reserves. The Company had no significant imbalances at December 31, 2012 or 2011. *Acquisition and Transaction Costs* The Eagle Property Acquisition qualifies as the acquisition of a business under Accounting Standards Codification Topic 805, Business Combinations ("ASC 805"). Acquisition and transaction costs are costs the Company has incurred as a result of the Eagle Property Acquisition and include finders' fees; advisory, legal, accounting, valuation and other professional and consulting fees; and general and administrative costs. ASC 805 requires these types of acquisition related costs to be expensed as incurred and as services are received. See Note 6. *Income Taxes* Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company's equity holders were responsible for income tax on the Company's profits. In connection with the closing of the Company's IPO, the Company merged into a corporation and became subject to federal and state income taxes. The Company's book and tax basis in assets and liabilities differed at the time of the corporate reorganization due primarily to different cost recovery periods utilized for book and tax purposes for the Company's oil and natural gas properties. See Note 11. *Earnings Per Share* Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period. Diluted earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options using the treasury method, as well as the Company's Series A Preferred Stock using the if-converted method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. *Recent Accounting Pronouncements* The Company reviewed recently issued accounting pronouncements that became effective during the twelve months ended December 31, 2012, and determined that none would have a material impact on the Company's consolidated financial statements.

2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of the Company have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") and have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP").

All intercompany transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year's consolidated financial statements and related footnotes to conform them to the current year presentation.

The consolidated financial statements as of and for the year ended December 31, 2012 include the results from the Eagle Property Acquisition beginning October 1, 2012.

Use of Estimates

The preparation of financial statements in conformity with 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 those estimates.

Significant estimates include, but are not limited to, the amount of recoverable oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; the fair value of commodity derivative contracts; the fair value of share-based compensation; and the valuation of future asset retirement obligations.

Cash and Cash Equivalents

The Company considers all short-term investments with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of allowance for uncollectible accounts. The carrying amount of the Company's accounts receivable approximate fair value because of the short-term nature of the instruments. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2012 and 2011, the Company had no allowance for doubtful accounts.

Financial Instruments

The Company's financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivative contracts. Commodity derivative contracts are recorded at fair value (see Note 3). The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The carrying amount of the Company's other financial instruments approximate fair value because of the short-term nature of the items or variable pricing. See fair value discussion of Senior Notes and Series A Preferred Shares issued in October 2012 in Notes 8 and 10, respectively.

Derivative financial instruments are recorded in the consolidated balance sheets as either an asset or liability measured at estimated fair value. Changes in the derivative's fair value are recognized currently in earnings as gains and losses in the period of change. The gains or losses are recorded in "Losses on commodity derivative contracts—net." The related cash flow impact is reflected within cash flows from operating activities.

Property and Equipment

Oil and Gas Properties

The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company's reserve quantities are sold that results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income.

Unevaluated Property

Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred.

Oil and Gas Reserves

Proved oil and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (FASB), which require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. The Company's reserve estimates at December 31, 2012, 2011 and 2010 were prepared by a third-party petroleum engineer, Netherland, Sewell & Associates, Inc. ("NSAI"). Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other Property and Equipment

Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is provided principally using the straight-line method over the estimated useful lives of the assets, which range from five to seven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.

Impairment of Oil and Gas Properties/Ceiling Test

Prior to March 31, 2012, the Company performed a ceiling test annually. Beginning with the quarter ended March 31, 2012, the Company now performs a ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may not exceed this "ceiling." The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations. See Note 5.

Depreciation, Depletion, and Amortization (DD&A)

DD&A of oil and gas properties is calculated using the Units of Production Method (UOP). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated DD&A, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value.

Capitalized Interest

Interest from external borrowings is capitalized on unevaluated properties using the weighted-average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at the first production from the field. Capitalized interest is depleted over the useful lives of the assets in the same manner as the depletion of the underlying assets. The Company paid cash interest of $7.2 million, $4.2 million, and $1.7 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Accrued Liabilities

Accrued liabilities at December 31, 2012 consisted of $69.0 million in oil and gas capital expenditures, $16.2 million in accrued interest, and $13.4 million in other accrued liabilities. At December 31, 2011 the balance consisted of $28.5 million in oil and gas capital expenditures, and $9.0 million in other accrued liabilities.

Asset Retirement Obligations

The legal obligations associated with the retirement of long-lived assets are recognized at estimated fair value at the time that the obligation is incurred.

Oil and gas producing companies incur such a liability upon acquiring or drilling a well. The Company estimates the fair value of an asset retirement obligation in the period in which the obligation is incurred and can be reliably measured. The corresponding asset retirement cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, any adjustment is recorded in the full cost pool. See Note 7.

Share-Based Compensation

We account for share-based compensation awards in accordance with FASB ASC 718, Compensation—Stock Compensation. We measure share-based compensation cost at fair value and generally recognize the corresponding compensation expense on a straight-line basis over the service period during which awards are expected to vest. We include share-based compensation expense in "General and administrative expense" in our consolidated statements of operations. See Note 10.

Revenue Recognition

Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and collection of the revenues is reasonably assured. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

The Company follows the sales method of accounting for oil and gas revenues, whereby revenue is recognized for all oil and gas sold to purchasers regardless of whether the sales are proportionate to the Company's ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company's share of remaining proved oil and gas reserves. The Company had no significant imbalances at December 31, 2012 or 2011.

Acquisition and Transaction Costs

The Eagle Property Acquisition qualifies as the acquisition of a business under Accounting Standards Codification Topic 805, Business Combinations ("ASC 805"). Acquisition and transaction costs are costs the Company has incurred as a result of the Eagle Property Acquisition and include finders' fees; advisory, legal, accounting, valuation and other professional and consulting fees; and general and administrative costs. ASC 805 requires these types of acquisition related costs to be expensed as incurred and as services are received. See Note 6.

Income Taxes

Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company's equity holders were responsible for income tax on the Company's profits. In connection with the closing of the Company's IPO, the Company merged into a corporation and became subject to federal and state income taxes. The Company's book and tax basis in assets and liabilities differed at the time of the corporate reorganization due primarily to different cost recovery periods utilized for book and tax purposes for the Company's oil and natural gas properties. See Note 11.

Earnings Per Share

Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period. Diluted earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options using the treasury method, as well as the Company's Series A Preferred Stock using the if-converted method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.

Recent Accounting Pronouncements

The Company reviewed recently issued accounting pronouncements that became effective during the twelve months ended December 31, 2012, and determined that none would have a material impact on the Company's consolidated financial statements.