Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2013 | Feb. 24, 2014 | Jun. 28, 2013 |
Document And Entity Information [Abstract] | ' | ' | ' |
Document Type | '10-K | ' | ' |
Amendment Flag | 'false | ' | ' |
Document Period End Date | 31-Dec-13 | ' | ' |
Document Fiscal Year Focus | '2013 | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' |
Trading Symbol | 'AREX | ' | ' |
Entity Registrant Name | 'Approach Resources Inc | ' | ' |
Entity Central Index Key | '0001405073 | ' | ' |
Current Fiscal Year End Date | '--12-31 | ' | ' |
Entity Well-known Seasoned Issuer | 'Yes | ' | ' |
Entity Current Reporting Status | 'Yes | ' | ' |
Entity Voluntary Filers | 'No | ' | ' |
Entity Filer Category | 'Large Accelerated Filer | ' | ' |
Entity Common Stock, Shares Outstanding | ' | 39,398,090 | ' |
Entity Public Float | ' | ' | $856.50 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
CURRENT ASSETS: | ' | ' |
Cash and cash equivalents | $58,761 | $767 |
Restricted cash | 7,350 | ' |
Accounts receivable: | ' | ' |
Joint interest owners | 158 | 215 |
Oil, NGL and gas sales | 22,871 | 12,575 |
Unrealized gain on commodity derivatives | ' | 1,552 |
Prepaid expenses and other current assets | 592 | 547 |
Deferred income taxes - current | 681 | ' |
Total current assets | 90,413 | 15,656 |
PROPERTIES AND EQUIPMENT: | ' | ' |
Oil and gas properties, at cost, using the successful efforts method of accounting | 1,320,195 | 1,025,440 |
Furniture, fixtures and equipment | 2,537 | 2,108 |
Total properties and equipment | 1,322,732 | 1,027,548 |
Less accumulated depletion, depreciation and amortization | -275,702 | -199,081 |
Net properties and equipment | 1,047,030 | 828,467 |
Equity method investment | ' | 9,892 |
Unrealized gain on commodity derivatives | ' | 881 |
Other assets | 8,041 | 843 |
Total assets | 1,145,484 | 855,739 |
CURRENT LIABILITIES: | ' | ' |
Accounts payable | 38,575 | 24,916 |
Oil, NGL and gas sales payable | 6,101 | 4,960 |
Deferred income taxes - current | ' | 531 |
Accrued liabilities | 37,918 | 29,840 |
Unrealized loss on commodity derivatives | 1,847 | ' |
Total current liabilities | 84,441 | 60,247 |
NON-CURRENT LIABILITIES: | ' | ' |
Senior secured credit facility | ' | 106,000 |
Senior notes | 250,000 | ' |
Deferred income taxes | 91,883 | 48,593 |
Unrealized loss on commodity derivatives | 315 | ' |
Asset retirement obligations | 8,350 | 7,431 |
Total liabilities | 434,989 | 222,271 |
COMMITMENTS AND CONTINGENCIES (Note 8) | ' | ' |
STOCKHOLDERS' EQUITY : | ' | ' |
Preferred stock, $0.01 par value, 10,000,000 shares authorized none outstanding | ' | ' |
Common stock, $0.01 par value, 90,000,000 shares authorized, 39,047,699 and 38,829,368 issued and outstanding, respectively | 390 | 388 |
Additional paid-in capital | 565,237 | 560,468 |
Retained earnings | 144,868 | 72,612 |
Total stockholders' equity | 710,495 | 633,468 |
Total liabilities and stockholders' equity | $1,145,484 | $855,739 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
Statement Of Financial Position [Abstract] | ' | ' |
Preferred stock, par value | $0.01 | $0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, shares outstanding | ' | ' |
Common stock, par value | $0.01 | $0.01 |
Common stock, shares authorized | 90,000,000 | 90,000,000 |
Common stock, issued | 39,047,699 | 38,829,368 |
Common stock, outstanding | 39,047,699 | 38,829,368 |
Consolidated_Statements_of_Ope
Consolidated Statements of Operations (USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
REVENUES: | ' | ' | ' |
Oil, NGL and gas sales | $181,302 | $128,892 | $108,387 |
EXPENSES: | ' | ' | ' |
Lease operating | 19,152 | 19,002 | 10,687 |
Production and ad valorem taxes | 12,840 | 9,255 | 8,447 |
Exploration | 2,238 | 4,550 | 9,546 |
Impairment | ' | ' | 18,476 |
General and administrative | 26,524 | 24,903 | 17,900 |
Depletion, depreciation and amortization | 76,956 | 60,381 | 32,475 |
Total expenses | 137,710 | 118,091 | 97,531 |
OPERATING INCOME | 43,592 | 10,801 | 10,856 |
OTHER: | ' | ' | ' |
Interest expense, net | -14,084 | -4,737 | -3,402 |
Equity in earnings (losses) of investee | 156 | -108 | ' |
Gain on sale of equity method investment | 90,743 | ' | ' |
Realized (loss) gain on commodity derivatives | -1,048 | -108 | 3,375 |
Unrealized (loss) gain on commodity derivatives | -4,596 | 3,874 | -347 |
Gain on sale of oil and gas properties, net of foreign currency transaction loss | ' | ' | 248 |
INCOME BEFORE INCOME TAX PROVISION | 114,763 | 9,722 | 10,730 |
INCOME TAX PROVISION: | ' | ' | ' |
Current | 429 | ' | ' |
Deferred | 42,078 | 3,338 | 3,488 |
NET INCOME | $72,256 | $6,384 | $7,242 |
EARNINGS PER SHARE: | ' | ' | ' |
Basic | $1.85 | $0.18 | $0.25 |
Diluted | $1.85 | $0.18 | $0.25 |
WEIGHTED AVERAGE SHARES OUTSTANDING: | ' | ' | ' |
Basic | 38,997,815 | 34,965,182 | 28,930,792 |
Diluted | 39,019,149 | 35,030,323 | 29,158,598 |
Consolidated_Statements_of_Cha
Consolidated Statements of Changes in Stockholders' Equity (USD $) | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] |
In Thousands, except Share data | |||||
Beginning balance, value at Dec. 31, 2010 | $332,946 | $282 | $273,912 | $58,986 | ($234) |
Beginning balance, shares at Dec. 31, 2010 | ' | 28,226,890 | ' | ' | ' |
Issuance of common stock upon exercise of options, value | 1,009 | 1 | 1,008 | ' | ' |
Issuance of common stock upon exercise of options, shares | 74,241 | 74,241 | ' | ' | ' |
Issuance of common stock, net of issuance costs, value | 122,150 | 46 | 122,104 | ' | ' |
Issuance of common stock, net of issuance costs, shares | ' | 4,600,000 | ' | ' | ' |
Issuance of common shares to directors for compensation, value | 420 | ' | 420 | ' | ' |
Issuance of common shares to directors for compensation, shares | ' | 18,446 | ' | ' | ' |
Restricted stock issuance, net of cancellations, value | ' | 2 | -2 | ' | ' |
Restricted stock issuance, net of cancellations, shares | ' | 205,475 | ' | ' | ' |
Share-based compensation expense | 4,263 | ' | 4,263 | ' | ' |
Surrender of restricted shares for payment of income taxes, value | -815 | ' | -815 | ' | ' |
Surrender of restricted shares for payment of income taxes, shares | ' | -31,458 | ' | ' | ' |
Net income | 7,242 | ' | ' | 7,242 | ' |
Foreign currency transaction and translation adjustments, net of related income tax of $85 | 234 | ' | ' | ' | 234 |
Ending balance, value at Dec. 31, 2011 | 467,449 | 331 | 400,890 | 66,228 | ' |
Ending balance, shares at Dec. 31, 2011 | ' | 33,093,594 | ' | ' | ' |
Issuance of common stock upon exercise of options, value | 798 | 2 | 796 | ' | ' |
Issuance of common stock upon exercise of options, shares | 216,822 | 216,822 | ' | ' | ' |
Issuance of common stock, net of issuance costs, value | 154,417 | 53 | 154,364 | ' | ' |
Issuance of common stock, net of issuance costs, shares | ' | 5,325,000 | ' | ' | ' |
Issuance of common shares to directors for compensation, value | 535 | ' | 535 | ' | ' |
Issuance of common shares to directors for compensation, shares | ' | 16,935 | ' | ' | ' |
Restricted stock issuance, net of cancellations, value | ' | 2 | -2 | ' | ' |
Restricted stock issuance, net of cancellations, shares | ' | 293,382 | ' | ' | ' |
Share-based compensation expense | 6,930 | ' | 6,930 | ' | ' |
Surrender of restricted shares for payment of income taxes, value | -3,045 | ' | -3,045 | ' | ' |
Surrender of restricted shares for payment of income taxes, shares | ' | -116,365 | ' | ' | ' |
Net income | 6,384 | ' | ' | 6,384 | ' |
Ending balance, value at Dec. 31, 2012 | 633,468 | 388 | 560,468 | 72,612 | ' |
Ending balance, shares at Dec. 31, 2012 | ' | 38,829,368 | ' | ' | ' |
Issuance of common stock upon exercise of options, value | 58 | ' | 58 | ' | ' |
Issuance of common stock upon exercise of options, shares | 3,750 | 3,750 | ' | ' | ' |
Issuance of common shares to directors for compensation, value | 630 | ' | 630 | ' | ' |
Issuance of common shares to directors for compensation, shares | ' | 24,317 | ' | ' | ' |
Restricted stock issuance, net of cancellations, value | ' | 2 | -2 | ' | ' |
Restricted stock issuance, net of cancellations, shares | ' | 245,262 | ' | ' | ' |
Share-based compensation expense | 5,271 | ' | 5,271 | ' | ' |
Surrender of restricted shares for payment of income taxes, value | -1,188 | ' | -1,188 | ' | ' |
Surrender of restricted shares for payment of income taxes, shares | ' | -54,998 | ' | ' | ' |
Net income | 72,256 | ' | ' | 72,256 | ' |
Ending balance, value at Dec. 31, 2013 | $710,495 | $390 | $565,237 | $144,868 | ' |
Ending balance, shares at Dec. 31, 2013 | ' | 39,047,699 | ' | ' | ' |
Consolidated_Statements_of_Cha1
Consolidated Statements of Changes in Stockholders' Equity (Parenthetical) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2011 |
Income tax expense relating to foreign currency translation adjustments | $85 |
Accumulated Other Comprehensive Income (Loss) [Member] | ' |
Income tax expense relating to foreign currency translation adjustments | $85 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
OPERATING ACTIVITIES: | ' | ' | ' |
Net income | $72,256 | $6,384 | $7,242 |
Adjustments to reconcile net income to net cash provided by operating activities: | ' | ' | ' |
Depletion, depreciation and amortization | 76,956 | 60,381 | 32,475 |
Amortization of loan origination fees | 1,048 | ' | ' |
Unrealized loss (gain) on commodity derivatives | 4,596 | -3,874 | 347 |
Impairment | ' | ' | 18,476 |
Gain on sale of oil and gas properties, net of foreign currency transaction loss | ' | ' | -248 |
Gain on sale of equity method investment | -90,743 | ' | ' |
Exploration expense | 2,238 | 4,550 | 9,546 |
Share-based compensation expense | 5,901 | 7,465 | 4,683 |
Deferred income taxes | 42,078 | 3,338 | 3,488 |
Equity in (earnings) losses of investee | -156 | 108 | ' |
Changes in operating assets and liabilities: | ' | ' | ' |
Accounts receivable | -10,239 | -2,550 | 6,168 |
Prepaid expenses and other current assets | -45 | 296 | 378 |
Accounts payable | 12,471 | 9,271 | -151 |
Oil, NGL and gas sales payable | 1,141 | 212 | -786 |
Accrued liabilities | 8,078 | 5,004 | 14,152 |
Cash provided by operating activities | 125,580 | 90,585 | 95,770 |
INVESTING ACTIVITIES: | ' | ' | ' |
Additions to oil and gas properties | -296,409 | -296,927 | -284,574 |
Proceeds from sale of equity method investment, net of contributions | 100,791 | -10,000 | ' |
Proceeds from gain on sale of oil and gas properties, net | ' | ' | 360 |
Change in restricted cash | -7,350 | ' | ' |
Additions to furniture, fixtures and equipment, net | -429 | -487 | -544 |
Cash used in investing activities | -203,397 | -307,414 | -284,758 |
FINANCING ACTIVITIES: | ' | ' | ' |
Borrowings under credit facility | 129,950 | 304,600 | 246,800 |
Repayment of amounts outstanding under credit facility | -235,950 | -242,400 | -203,000 |
Proceeds from issuance of senior notes | 242,824 | ' | ' |
Proceeds from issuance of common stock, net offering costs | ' | 154,417 | 122,150 |
Proceeds from issuance of common stock upon exercise of stock options | 58 | 798 | 1,009 |
Loan origination fees | -1,071 | -120 | -1,116 |
Cash provided by financing activities | 135,811 | 217,295 | 165,843 |
CHANGE IN CASH AND CASH EQUIVALENTS | 57,994 | 466 | -23,145 |
EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH EQUIVALENTS | ' | ' | -19 |
CASH AND CASH EQUIVALENTS, beginning of year | 767 | 301 | 23,465 |
CASH AND CASH EQUIVALENTS, end of year | 58,761 | 767 | 301 |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ' | ' | ' |
Cash paid for interest | 12,392 | 4,192 | 2,856 |
SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION: | ' | ' | ' |
Acquisition of oil and gas properties | 132 | ' | 547 |
Asset retirement obligations capitalized | $584 | $409 | $1,190 |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Accounting Policies [Abstract] | ' | ||||||||||||
Summary of Significant Accounting Policies | ' | ||||||||||||
1 | Summary of Significant Accounting Policies | ||||||||||||
Organization and Nature of Operations | |||||||||||||
Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin. | |||||||||||||
Consolidation, Basis of Presentation and Significant Estimates | |||||||||||||
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect our estimate of depletion expense as well as our impairment analyses. Significant assumptions also are required in our estimation of accrued liabilities, commodity derivatives, income tax provision, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior-year amounts have been reclassified to conform to current-year presentation. These classifications have no impact on the net income or loss reported. | |||||||||||||
Cash and Cash Equivalents | |||||||||||||
We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible. | |||||||||||||
Restricted Cash | |||||||||||||
The restricted cash on our balance sheet consists of $7.4 million in proceeds from the sale of our equity method investment that are restricted pursuant to an escrow agreement. The escrow termination date is June 1, 2014. | |||||||||||||
Oil and Gas Properties | |||||||||||||
Capitalized Costs. Our oil and gas properties comprised the following (in thousands): | |||||||||||||
December 31, | |||||||||||||
2013 | 2012 | ||||||||||||
Mineral interests in properties: | |||||||||||||
Unproved leasehold costs | $ | 47,096 | $ | 49,148 | |||||||||
Proved leasehold costs | 40,620 | 32,252 | |||||||||||
Wells and related equipment and facilities | 1,195,556 | 908,456 | |||||||||||
Support equipment | 10,773 | 6,753 | |||||||||||
Uncompleted wells, equipment and facilities | 26,150 | 28,831 | |||||||||||
Total costs | 1,320,195 | 1,025,440 | |||||||||||
Less accumulated depreciation, depletion and amortization | (273,915 | ) | (197,751 | ) | |||||||||
Net capitalized costs | $ | 1,046,280 | $ | 827,689 | |||||||||
We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized, pending determination of whether the wells have proved reserves, at December 31, 2013 or 2012. Geological and geophysical costs, including seismic studies are charged to exploration expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use and while these expenditures are excluded from our depletable base. Through December 31, 2013, we have capitalized no interest costs because our individual wells and infrastructure projects are generally developed in less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred. | |||||||||||||
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with no gain or loss recognized in income. | |||||||||||||
Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment was $76.5 million, $60 million and $32.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. | |||||||||||||
Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. For 2011, we recorded an impairment expense of $15.2 million, which was attributable to our oil and gas properties in the East Texas Basin. At December 31, 2011, we had $2.7 million recorded for the East Texas Basin, which was the estimated fair value at December 31, 2011. We noted no impairment of our proved properties based on our analysis for the years ended December 31, 2013 and 2012. | |||||||||||||
Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. For 2011, we recorded an impairment expense of $3.3 million, related to all of our remaining carrying costs associated with our unproved properties in Northern New Mexico. | |||||||||||||
On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. During 2011, we sold our working interest in Northeast British Columbia for net proceeds of $360,000. The gain on the sale of this interest, net of foreign currency, was $248,000 and is included under “Other” on the consolidated statement of operations for the year ended December 31, 2011. | |||||||||||||
Other Property | |||||||||||||
Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to ten years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $502,000, $333,000 and $372,000 for the years ended December 31, 2013, 2012 and 2011, respectively. | |||||||||||||
Equity Method Investment | |||||||||||||
For investments in which we have the ability to exercise significant influence but do not have control, we follow the equity method of accounting. In September 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which is used to transport our oil to market. In 2013, we contributed $8.3 million to the equity joint venture for pipeline and facilities construction prior to its sale in October 2013. | |||||||||||||
Other Assets | |||||||||||||
Other assets consist of deferred costs associated with the issuance of the $250 million principal amount of 7% Senior Notes due 2021 (the “Senior Notes”) and the revolving credit facility. These costs are amortized over the life of the Senior Notes and the life of the revolving credit facility on a straight-line basis, which approximates the amortization that would be calculated using an effective interest rate method. | |||||||||||||
Financial Instruments | |||||||||||||
The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, as of December 31, 2013 and 2012. See Note 7 for commodity derivative and Senior Notes fair value disclosures. | |||||||||||||
Income Taxes | |||||||||||||
We are subject to U.S. federal income taxes along with state income taxes in Texas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in the consolidated statement of income. | |||||||||||||
Based on our analysis, we did not have any uncertain tax positions as of December 31, 2013 or 2012. The Company’s income tax returns are subject to examination by the relevant taxing authorities as follows: U.S. Federal income tax returns for tax years 2010 and forward, Texas income and margin tax returns for tax years 2010 and forward, New Mexico income tax returns for years 2010 and forward, and Kentucky income tax returns for the years 2010 and forward. There are currently no income tax examinations underway for these jurisdictions. | |||||||||||||
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change. | |||||||||||||
Derivative Activity | |||||||||||||
We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.” | |||||||||||||
Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations. | |||||||||||||
Accrued Liabilities | |||||||||||||
The following is a summary of our accrued liabilities at December 31, 2013 and 2012 (in thousands): | |||||||||||||
2013 | 2012 | ||||||||||||
Capital expenditures accrual | $ | 30,606 | $ | 25,526 | |||||||||
Operating expenses and other | 7,312 | 4,314 | |||||||||||
Total | $ | 37,918 | $ | 29,840 | |||||||||
Asset Retirement Obligations | |||||||||||||
Our asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. Based on the expected timing of payments, the full asset retirement obligation is classified as non-current. There were no significant changes to the asset retirement obligations for the years ended December 31, 2013, 2012 and 2011. | |||||||||||||
Foreign Currency Translation | |||||||||||||
The functional currency of the country in which we currently operate is the U.S. dollar in the United States. For the year ended December 31, 2011, the functional currency of our Canadian subsidiary was the Canadian dollar. Assets and liabilities of our Canadian subsidiary that are denominated in currencies other than the Canadian dollar are translated at current exchange rates. Gains and losses resulting from such translations, along with gains or losses realized from transactions denominated in currencies other than the Canadian dollar are included in operating results on our statements of operations. For purposes of consolidation, we translate the assets and liabilities of our Canadian subsidiary into U.S. dollars at current exchange rates while revenues and expenses are translated at the average rates in effect for the period. The related translation gains and losses are included in accumulated other comprehensive income within stockholders’ equity on our consolidated balance sheets. We recognized no translation gains or losses during the year ended December 31, 2012, since we sold our working interest in northeast British Columbia in 2011. During the year ended December 31, 2011, we recognized a translation loss of $20,000, net of the related income taxes. | |||||||||||||
Share-Based Compensation | |||||||||||||
We measure and record compensation expense for all share-based payment awards to employees and outside directors based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value. | |||||||||||||
Earnings Per Common Share | |||||||||||||
We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts): | |||||||||||||
For the Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Income (numerator): | |||||||||||||
Net income — basic | $ | 72,256 | $ | 6,384 | $ | 7,242 | |||||||
Weighted average shares (denominator): | |||||||||||||
Weighted average shares — basic | 38,997,815 | 34,965,182 | 28,930,792 | ||||||||||
Dilution effect of share-based compensation, treasury method | 21,334 | 65,141 | 227,806 | ||||||||||
Weighted average shares — diluted | 39,019,149 | 35,030,323 | 29,158,598 | ||||||||||
Earnings per share: | |||||||||||||
Basic | $ | 1.85 | $ | 0.18 | $ | 0.25 | |||||||
Diluted | $ | 1.85 | $ | 0.18 | $ | 0.25 | |||||||
Oil and Gas Operations | |||||||||||||
Revenue and Accounts Receivable. We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. | |||||||||||||
Accounts receivable, joint interest owners, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil, NGL and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2013 or 2012. | |||||||||||||
Oil, NGL and Gas Sales Payable. Oil, NGL and gas sales payable represents amounts collected from purchasers for oil, NGL and gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 30 days of the end of the month in which the related production occurred. | |||||||||||||
Production Costs. Production costs, including compressor rental and repair, pumpers’ and supervisors’ salaries, saltwater disposal, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on our consolidated statements of operations. | |||||||||||||
Exploration expenses. Exploration expenses include dry hole costs, delay rentals and geological and geophysical costs. | |||||||||||||
Dependence on Major Customers. For the year ended December 31, 2013, sales to Wildcat Permian Services, LLC (“Wildcat”), DCP Midstream, LLC (“DCP”) and JP Energy Permian, LLC (“JPE”) accounted for approximately 30%, 27% and 23%, respectively, of our total sales. Additionally, substantially all of our accounts receivable related to oil and gas sales were due from JPE and DCP at December 31, 2013. As of December 31, 2013, we had dedicated all of our oil production from northern Project Pangea and Pangea West through 2022 to JP Energy Development, LP (“JP Energy”). In addition, as of December 31, 2013, we had contracted to sell all of our NGLs and natural gas production from Project Pangea to DCP through January 2016. For the years ended December 31, 2012 and 2011, we sold substantially all of our oil and gas produced to seven purchasers. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy. | |||||||||||||
Dependence on Suppliers. Our industry is cyclical, and from time-to-time there is a shortage of drilling rigs, equipment, services, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment, services and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, services, supplies or qualified personnel were particularly severe in the area where we operate, we could be materially and adversely affected. We believe that there are potential alternative providers of drilling and completion services and that it may be necessary to establish relationships with new contractors. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased availability of drilling rigs or other services. | |||||||||||||
Segment Reporting | |||||||||||||
The Company presently operates in one business segment, the exploration and production of oil, NGLs and natural gas. |
Equity_Method_Investment
Equity Method Investment | 12 Months Ended | |
Dec. 31, 2013 | ||
Equity Method Investments And Joint Ventures [Abstract] | ' | |
Equity Method Investment | ' | |
2 | Equity Method Investment | |
In September 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which is used to transport our oil to market. In October 2012, we made an initial contribution of $10 million to the joint venture for pipeline and facilities construction. In 2013, we contributed $8.3 million to the equity joint venture for pipeline and facilities construction prior to its sale in October 2013. Our contributions are recorded at cost and are included in noncurrent assets, “Equity method investment,” on our consolidated balance sheets and in investing activities, “Contribution to equity method investment,” on our consolidated statements of cash flows. Our share of the investee earnings was recorded on our consolidated statement of operations for the year ended December 31, 2013. In October 2013, we completed the sale of the joint venture, and net proceeds to Approach at closing totaled approximately $109.1 million, after deducting our share of transactional costs paid at closing. Of the $109.1 million in proceeds, $7.4 million is restricted pursuant to an escrow agreement and recorded as restricted cash at December 31, 2013. The escrow termination date is June 1, 2014. We recognized a pre-tax gain of $90.7 million related to this transaction, subject to normal post-closing adjustments. |
Public_Equity_Offerings
Public Equity Offerings | 12 Months Ended | |
Dec. 31, 2013 | ||
Text Block [Abstract] | ' | |
Public Equity Offerings | ' | |
3 | Public Equity Offerings | |
On September 19, 2012, we completed a public offering of 5 million shares of our common stock. The underwriters exercised their option and purchased an additional 325,000 shares on October 3, 2012. After deducting underwriting discounts and transaction costs of approximately $8 million, we received net proceeds of approximately $154.4 million. We used the proceeds of the 2012 equity offering to repay outstanding borrowings under our revolving credit facility, fund our capital expenditures for the Wolfcamp oil shale resource play and for general working capital needs. | ||
On November 15, 2011, we completed a public offering of 4 million shares of our common stock. The underwriters were granted an option to purchase up to 600,000 additional shares of our common stock. The underwriters fully exercised this option and purchased the additional shares on November 16, 2011. After deducting underwriting discounts and transaction costs of approximately $6.6 million, we received net proceeds of approximately $122.2 million. We used the proceeds of the 2011 equity offering to repay outstanding borrowings under our revolving credit facility, fund our capital expenditures for the Wolfcamp oil shale resource play, fund working interest and leasehold acquisitions in the Permian Basin and for general working capital needs. |
LongTerm_Debt
Long-Term Debt | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Debt Disclosure [Abstract] | ' | ||||||||
Long-Term Debt | ' | ||||||||
4 | Long-Term Debt | ||||||||
The following table provides a summary of our long-term debt at December 31, 2013, and December 31, 2012 (in thousands). | |||||||||
December 31, | December 31, | ||||||||
2013 | 2012 | ||||||||
Senior secured credit facility | $ | — | $ | 106,000 | |||||
Senior Notes | 250,000 | — | |||||||
Total long-term debt | $ | 250,000 | $ | 106,000 | |||||
Credit Facility | |||||||||
Our credit facility has a maturity date of July 31, 2016. At December 31, 2013, our borrowing base was $350 million, with maximum commitments from the lenders in the credit facility of $500 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our oil, NGL and gas reserves. We, or the lenders, can each request one additional borrowing base redetermination each calendar year. | |||||||||
Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 0.75% to 1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%. Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an annual commitment of 0.50% of unused borrowings available under our credit facility. | |||||||||
On May 1, 2013, we entered into a fifteenth amendment to the credit facility, which (i) increased the borrowing base to $315 million from $280 million, (ii) increased the lenders’ aggregate maximum commitment to $500 million from $300 million, and (iii) extended the maturity date by two years, to July 31, 2016. Loans under our credit facility are secured by first-priority liens on substantially all of our West Texas assets and are guaranteed by certain of our subsidiaries. | |||||||||
On November 6, 2013, we entered into a sixteenth amendment to the credit facility, which, among other things, increased the borrowing base to $350 million from $315 million. | |||||||||
On January 23, 2014, we entered into a seventeenth amendment to the credit facility. This amendment provides the Company with more hedging flexibility by allowing the Company to enter into commodity derivative contracts on a rolling basis for (i) up to 85% of projected production from proved oil and gas properties for the two years following a commodities derivative contract, (ii) up to 100% of projected production from proved producing oil and gas properties during year three of such contract and (iii) up to 85% of projected production from proved producing oil and gas properties during years four and five of such contract. | |||||||||
We had no outstanding borrowings under our credit facility at December 31, 2013, compared to outstanding borrowings of $106 million at December 31, 2012. The weighted average interest rate applicable to borrowings under our credit facility at December 31, 2012, was 2.7%. We also had outstanding unused letters of credit under our credit facility totaling $0.3 million at December 31, 2013 and 2012, which reduce amounts available for borrowing under our credit facility. | |||||||||
Loans under our revolving credit facility are secured by first-priority liens on substantially all of our West Texas assets, a pledge of our equity interests in our subsidiaries and are guaranteed by our subsidiaries. | |||||||||
Covenants | |||||||||
Our credit agreement contains two principal financial covenants: | |||||||||
• | a consolidated modified current ratio covenant that requires us to maintain a ratio of not less than 1.0 to 1.0 at all times. The consolidated modified current ratio is calculated by dividing Consolidated Current Assets (as defined in the credit agreement) by Consolidated Current Liabilities (as defined in the credit agreement). As defined more specifically in the credit agreement, the consolidated modified current ratio is calculated as current assets less current unrealized gains on commodity derivatives plus the available borrowing base at the respective balance sheet date, divided by current liabilities less current unrealized losses on commodity derivatives at the respective balance sheet date. | ||||||||
• | a consolidated funded debt-to-consolidated EBITDAX ratio covenant that requires us to maintain a ratio of not more than 4.0 to 1.0 at the end of each fiscal quarter. The consolidated funded debt-to-consolidated EBITDAX ratio is calculated by dividing Consolidated Funded Debt (as defined in the credit agreement) by Consolidated EBITDAX (as defined in the credit agreement). As defined more specifically in the credit agreement, consolidated EBITDAX is calculated as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, (6) income and franchise taxes and (7) certain other noncash expenses, less (1) gains or losses from sales or dispositions of assets, (2) unrealized gain on commodity derivatives and (3) extraordinary or nonrecurring gains. For purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is annualized pursuant to the credit agreement. | ||||||||
Our credit agreement also restricts cash dividends and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investments in other entities and liens on properties. | |||||||||
In addition, our credit agreement contains customary events of default that would permit our lenders to accelerate the debt under our credit agreement if not cured within applicable grace periods, including, among others, failure to make payments of principal or interest when due, materially incorrect representations and warranties, failure to make mandatory prepayments in the event of borrowing base deficiencies, breach of covenants, defaults upon other obligations in excess of $500,000, events of bankruptcy, the occurrence of one or more unstayed judgments in excess of $500,000 not covered by an acceptable policy of insurance, failure to pay any obligation in excess of $500,000 owed under any derivatives transaction or in any amount if the obligation under the derivatives transaction is secured by collateral under the credit agreement, any event of default by the Company occurs under any agreement entered into in connection with a derivatives transaction, liens securing the loans under the credit agreement cease to be in place, a Change in Control (as defined in the credit agreement) of the Company occurs and dissolution of the Company. | |||||||||
At December 31, 2013, we were in compliance with all of our covenants and had not committed any acts of default under the credit agreement. | |||||||||
Senior Notes | |||||||||
In June 2013, we completed our public offering of $250 million principal amount of 7% Senior Notes due 2021. Interest on the Senior Notes is payable semi-annually on June 15 and December 15, beginning December 15, 2013. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under our credit facility. | |||||||||
We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wells Fargo Bank, National Association, as trustee. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.” | |||||||||
On and after June 15, 2016, we may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. Before June 15, 2016, we may redeem up to 35% of the Senior Notes at a redemption price of 107% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. In addition, before June 15, 2016, we may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the Senior Notes from holders. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee: | |||||||||
• | in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if the sale or other disposition otherwise complies with the indenture; | ||||||||
• | in connection with any sale or other disposition of the capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if that guarantor no longer qualifies as a subsidiary of the Company as a result of such disposition and the sale or other disposition otherwise complies with the indenture; | ||||||||
• | if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture; | ||||||||
• | upon defeasance or covenant defeasance of the notes or satisfaction and discharge of the indenture, in each case, in accordance with the indenture; | ||||||||
• | upon the liquidation or dissolution of that guarantor, provided that no default or event of default occurs under the indenture as a result thereof or shall have occurred and is continuing; or | ||||||||
• | in the case of any restricted subsidiary that, after the issue date of the notes is required under the indenture to guarantee the notes because it becomes a guarantor of indebtedness issued or an obligor under a credit facility with respect to the Company and/or its subsidiaries, upon the release or discharge in full from its (x) guarantee of such indebtedness or (y) obligation under such credit facility, in each case, which resulted in such restricted subsidiary’s obligation to guarantee the notes. | ||||||||
The Indenture restricts our ability, among other things, to (i) sell certain assets, (ii) pay distributions on, redeem or repurchase, equity interests, (iii) incur additional debt, (iv) make certain investments, (v) enter into transactions with affiliates, (vi) incur liens and (vii) merge or consolidate with another company. These restrictions are subject to a number of important exceptions and qualifications. If at any time the Senior Notes are rated investment grade by both Moody’s Investors Service and Standard & Poor’s Ratings Services and no default (as defined in the Indenture) has occurred and is continuing, many of these restrictions will terminate. The Indenture contains customary events of default. | |||||||||
At December 31, 2013, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments. On December 15, 2013, we made a semi-annual interest payment of $8.9 million. | |||||||||
Subsidiary Guarantors | |||||||||
The Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. Approach Resources Inc. is a holding company with no independent assets or operations. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no significant restrictions on the Company’s ability, or the ability of any subsidiary guarantor, to obtain funds from its subsidiaries through dividends, loans, advances or otherwise. |
ShareBased_Compensation
Share-Based Compensation | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | ' | ||||||||||||||||
Share-Based Compensation | ' | ||||||||||||||||
5 | Share-Based Compensation | ||||||||||||||||
In June 2007, the board of directors and stockholders approved the 2007 Stock Incentive Plan (“the 2007 Plan”). Under the 2007 Plan, we may grant restricted stock, stock options, stock appreciation rights, restricted stock units, performance awards, unrestricted stock awards and other incentive awards. Under a Second Amendment to the 2007 Plan effective May 31, 2012, the maximum number of shares of common stock available for the grant of awards under the 2007 Plan after May 31, 2012, is 2,100,000. Awards of any stock options are to be priced at not less than the fair market value at the date of the grant. The vesting period of any stock award is to be determined by the board or an authorized committee at the time of the grant. The term of each stock option is to be fixed at the time of grant and may not exceed 10 years. Shares issued upon stock options exercised are issued as new shares. | |||||||||||||||||
Share-based compensation expense amounted to $5.9 million, $7.5 million and $4.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Such amounts represent the estimated fair value of stock awards for which the requisite service period elapsed during those periods. Included in share-based compensation expense in 2013 is a benefit of $1 million for forfeited stock awards related to the retirement of one of our executive officers effective December 31, 2013. Share-based compensation expense for the years ended December 31, 2013, 2012 and 2011, included $630,000, $535,000 and $420,000, respectively, related to grants to nonemployee directors. | |||||||||||||||||
Stock Options | |||||||||||||||||
There were no stock option grants during the years ended December 31, 2013, 2012 and 2011. As of December 31, 2013, all stock options are fully vested. | |||||||||||||||||
The following table summarizes stock options outstanding and activity as of and for the years ended December 31, 2013, 2012 and 2011, (dollars in thousands): | |||||||||||||||||
Shares | Weighted | Weighted | Aggregate | ||||||||||||||
Subject to | Average | Average | Intrinsic | ||||||||||||||
Stock | Exercise | Remaining | Value | ||||||||||||||
Options | Price | Contractual | |||||||||||||||
Term | |||||||||||||||||
(in years) | |||||||||||||||||
Outstanding at January 1, 2011 | 334,338 | $ | 7.01 | 3.85 | $ | 4,567 | |||||||||||
Granted | — | — | |||||||||||||||
Exercised | (74,241 | ) | 13.59 | ||||||||||||||
Canceled | — | — | |||||||||||||||
Outstanding at December 31, 2011 | 260,097 | $ | 5.13 | 1.94 | $ | 6,315 | |||||||||||
Granted | — | — | |||||||||||||||
Exercised | (216,822 | ) | 3.68 | ||||||||||||||
Canceled | — | — | |||||||||||||||
Outstanding at December 31, 2012 | 43,275 | $ | 12.38 | 4.88 | $ | 547 | |||||||||||
Granted | — | — | |||||||||||||||
Exercised | (3,750 | ) | 15.42 | ||||||||||||||
Canceled | — | — | |||||||||||||||
Outstanding at December 31, 2013 | 39,525 | $ | 12.09 | 3.84 | $ | 285 | |||||||||||
Exercisable (fully vested) at December 31, 2013 | 39,525 | $ | 12.09 | 3.84 | $ | 285 | |||||||||||
The intrinsic value of the options exercised during the years ended December 31, 2013, 2012 and 2011, was $35,000, $7 million and $1.1 million, respectively. There was no tax benefit recognized related to the stock option exercises in the years ended December 31, 2013 and 2012. | |||||||||||||||||
Nonvested Shares | |||||||||||||||||
Share grants totaling 377,379 shares, 316,279 shares and 256,317 shares with an approximate aggregate fair market value of $8.6 million, $10.4 million and $8.1 million at the time of grant were granted to employees during the years ended December 31, 2013, 2012 and 2011, respectively. Included in the share grants for 2013, 2012 and 2011, are 183,672 shares, 129,890 shares and 204,000 shares, respectively, awarded to our executive officers. The aggregate fair market value of these shares on the grant date was $4.4 million, $4.8 million and $6.5 million, respectively, to be expensed over a remaining service period of approximately three years, subject to certain performance restrictions. | |||||||||||||||||
A summary of the status of nonvested shares for the years ended December 31, 2013, 2012 and 2011, is presented below: | |||||||||||||||||
Shares | Weighted | ||||||||||||||||
Average | |||||||||||||||||
Grant-Date | |||||||||||||||||
Fair Value | |||||||||||||||||
Nonvested at January 1, 2011 | 708,781 | $ | 8.04 | ||||||||||||||
Granted | 256,317 | 31.54 | |||||||||||||||
Vested | (124,134 | ) | 9.93 | ||||||||||||||
Canceled | (50,842 | ) | 12.03 | ||||||||||||||
Nonvested at December 31, 2011 | 790,122 | 15.06 | |||||||||||||||
Granted | 316,279 | 32.94 | |||||||||||||||
Vested | (333,957 | ) | 14.57 | ||||||||||||||
Canceled | (19,365 | ) | 23.74 | ||||||||||||||
Nonvested at December 31, 2012 | 753,079 | 22.35 | |||||||||||||||
Granted | 377,379 | 22.77 | |||||||||||||||
Vested | (299,110 | ) | 18.79 | ||||||||||||||
Canceled | (132,117 | ) | 24.47 | ||||||||||||||
Nonvested at December 31, 2013 | 699,231 | $ | 23.7 | ||||||||||||||
As of December 31, 2013, unrecognized compensation expense related to the nonvested shares amounted to $16.6 million, which will be recognized over a remaining service period of three years. | |||||||||||||||||
Subsequent Restricted Share Award | |||||||||||||||||
Subsequent to December 31, 2013, 245,157 restricted shares were awarded to our executive officers of which 163,438 shares are subject to certain performance conditions and 81,719 shares are subject to three-year total shareholder return (“TSR”) conditions, assuming maximum TSR. The aggregate fair market value of the shares subject to performance conditions on the grant date was $3.4 million, to be expensed over a remaining service period of approximately three years. |
Income_Taxes
Income Taxes | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Income Tax Disclosure [Abstract] | ' | ||||||||||||
Income Taxes | ' | ||||||||||||
6 | Income Taxes | ||||||||||||
Our provision for income taxes comprised the following (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Current: | |||||||||||||
Federal | $ | 429 | $ | — | $ | — | |||||||
State | — | — | — | ||||||||||
Total current provision for income taxes | $ | 429 | $ | — | $ | — | |||||||
Deferred: | |||||||||||||
Federal | $ | 41,175 | $ | 3,359 | $ | 3,199 | |||||||
State | 903 | (21 | ) | 289 | |||||||||
Total deferred provision for income taxes | $ | 42,078 | $ | 3,338 | $ | 3,488 | |||||||
Total income tax expense differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Statutory tax at 35% | $ | 40,167 | $ | 3,306 | $ | 3,648 | |||||||
State taxes, net of federal impact | 709 | (21 | ) | 289 | |||||||||
Permanent differences(1) | 34 | 53 | (289 | ) | |||||||||
Other differences | 1,597 | — | (160 | ) | |||||||||
Total | $ | 42,507 | $ | 3,338 | $ | 3,488 | |||||||
-1 | Amounts primarily relate to share-based compensation expense. | ||||||||||||
Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax basis of assets and liabilities. Our net deferred tax assets and liabilities are recorded as a long-term liability of $91.9 million and $48.6 million at December 31, 2013 and 2012, respectively. At December 31, 2013, $0.7 million of deferred taxes expected to be realized within one year were included in current assets. At December 31, 2012, $0.5 million of deferred taxes expected to be realized within one year were included in current liabilities. | |||||||||||||
Significant components of net deferred tax assets and liabilities are (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2013 | 2012 | ||||||||||||
Deferred tax assets: | |||||||||||||
Current portion of unrealized loss on commodity derivatives | $ | 681 | — | ||||||||||
Net operating loss carryforwards | 26,674 | $ | 27,353 | ||||||||||
Unrealized loss on commodity derivatives | 113 | — | |||||||||||
Other | 295 | 542 | |||||||||||
Total deferred tax assets | 27,763 | 27,895 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Difference in depreciation, depletion and capitalization methods—oil and gas properties | (118,965 | ) | (76,170 | ) | |||||||||
Unrealized gain on commodity derivatives | — | (849 | ) | ||||||||||
Total deferred tax liabilities | (118,965 | ) | (77,019 | ) | |||||||||
Net deferred tax liability | $ | (91,202 | ) | $ | (49,124 | ) | |||||||
Net operating loss carryforwards for tax purposes have the following expiration dates (in thousands): | |||||||||||||
Expiration Dates | Amounts | Stock | Total | ||||||||||
Adjustments | |||||||||||||
2030 | $ | 4,083 | $ | 750 | $ | 4,833 | |||||||
2031 | 18,642 | 1,012 | 19,654 | ||||||||||
2032 | 51,931 | 2,724 | 54,655 | ||||||||||
2033 | — | 741 | 741 | ||||||||||
Total | $ | 74,656 | $ | 5,227 | $ | 79,883 | |||||||
As of December 31, 2013, we had net operating loss carryfowards of approximately $79.9 million, of which approximately $5.2 million was generated from the benefit of stock options. When these benefits are realized, they will be credited to additional paid-in capital. |
Derivatives
Derivatives | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ' | ||||||||||||||||||||
Derivatives | ' | ||||||||||||||||||||
7 | Derivatives | ||||||||||||||||||||
At December 31, 2013, we had the following commodity derivatives positions outstanding: | |||||||||||||||||||||
Commodity and Period | Contract | Volume Transacted | Contract Price | ||||||||||||||||||
Type | |||||||||||||||||||||
Crude Oil | |||||||||||||||||||||
2014 | Collar | 550 Bbls/d | $90.00/Bbl – $105.50/Bbl | ||||||||||||||||||
2014 | Collar | 950 Bbls/d | $85.05/Bbl – $95.05/Bbl | ||||||||||||||||||
2014 | Collar | 2,000 Bbls/d | $89.00/Bbl – $98.85/Bbl | ||||||||||||||||||
2015 | Collar | 2,600 Bbls/d | $84.00/Bbl – $91.00/Bbl | ||||||||||||||||||
Crude Oil Basis Differential (Midland/Cushing) | |||||||||||||||||||||
2014 | Swap | 1,500 Bbls/d | $0.55/Bbl | ||||||||||||||||||
Natural Gas Liquids | |||||||||||||||||||||
Propane 2014 | Swap | 500 Bbls/d | $41.16/Bbl | ||||||||||||||||||
Natural Gasoline 2014 | Swap | 175 Bbls/d | $83.37/Bbl | ||||||||||||||||||
Natural Gas | |||||||||||||||||||||
2014 | Swap | 360,000 MMBtu/month | $4.18/MMBtu | ||||||||||||||||||
2014(1) | Swap | 35,000 MMBtu/month | $4.29/MMBtu | ||||||||||||||||||
2015 | Swap | 200,000 MMBtu/month | $4.10/MMBtu | ||||||||||||||||||
2015 | Collar | 130,000 MMBtu/month | $4.00/MMBtu – $4.25/MMBtu | ||||||||||||||||||
-1 | February 2014 — December 2014. | ||||||||||||||||||||
Subsequent to December 31, 2013, we entered into a natural gas swap covering 160,000 MMBtu per month for March through December 2014 at a contract price of $4.40/MMBtu. We also entered into a natural gas collar covering 80,000 MMBtu per month for September 2014 through June 2015 at a floor price of $4.00/MMBtu and a ceiling price of $4.74/MMBtu, and a crude oil collar covering 1,500 Bbls per day for April 2014 through March 2015 at a floor price of $85.00/Bbl and a ceiling price of $95.30/Bbl. In January 2014, we early settled the crude oil basis differential swap for $0.7 million. | |||||||||||||||||||||
The following summarizes the fair value of our open commodity derivatives as of December 31, 2013 and 2012 (in thousands): | |||||||||||||||||||||
Asset Derivatives | Liability Derivatives | ||||||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||||||
Balance Sheet | December 31, | December 31, | Balance Sheet | December 31, | December 31, | ||||||||||||||||
Location | 2013 | 2012 | Location | 2013 | 2012 | ||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||
Commodity derivatives | Unrealized gain on commodity derivatives | $ | 9,108 | $ | 2,433 | Unrealized loss on commodity derivatives | $ | 11,270 | $ | — | |||||||||||
The following summarizes the change in the fair value of our commodity derivatives (in thousands): | |||||||||||||||||||||
Income Statement Location | |||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||
Commodity derivatives | Unrealized (loss) gain on commodity derivatives | $ | (4,596 | ) | $ | 3,874 | $ | (347 | ) | ||||||||||||
Realized (loss) gain on commodity derivatives | (1,048 | ) | (108 | ) | 3,375 | ||||||||||||||||
$ | (5,644 | ) | $ | 3,766 | $ | 3,028 | |||||||||||||||
Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair value of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations. | |||||||||||||||||||||
We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. | |||||||||||||||||||||
To estimate the fair value of our commodity derivatives positions, we use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows: | |||||||||||||||||||||
• | Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At December 31, 2013, we had no Level 1 measurements. | ||||||||||||||||||||
• | Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At December 31, 2013, all of our commodity derivatives were valued using Level 2 measurements. | ||||||||||||||||||||
• | Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At December 31, 2013, we had no Level 3 measurements. | ||||||||||||||||||||
Financial Instruments Not Recorded at Fair Value | |||||||||||||||||||||
The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands). | |||||||||||||||||||||
December 31, 2013 | |||||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||||
Amount | |||||||||||||||||||||
Senior Notes | $ | 250,000 | $ | 256,875 | |||||||||||||||||
The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy. |
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended | ||||
Dec. 31, 2013 | |||||
Commitments And Contingencies Disclosure [Abstract] | ' | ||||
Commitments and Contingencies | ' | ||||
8 | Commitments and Contingencies | ||||
In connection with the closing of the Wildcat sale, in October 2013, we entered into an amendment to our crude oil purchase agreement with JP Energy. The amendment, among other things, amends the dedicated area to include certain portions of Crockett and Schleicher Counties, Texas; amends the transportation and marketing fee; provides for the construction of future gathering lines and connection facilities; provides us with priority and preference rights for crude oil capacity on the pipeline system; and provides for trucking of crude oil during construction of gathering lines and connection facilities. | |||||
We periodically enter into contractual arrangements under which we are committed to expend funds to drill wells in the future, including agreements to secure drilling rig services, which require us to make future minimum payments to the rig operators. We record drilling commitments in the periods in which well capital expenditures are incurred or rig services are provided. Our commitment under daywork drilling contracts was $1.9 million at December 31, 2013. | |||||
At December 31, 2013, we had outstanding employment agreements with four of our five executive officers that contained automatic renewal provisions providing that such agreements may be automatically renewed for successive terms of one year unless the employment is terminated at the end of the term by written notice given to the employee not less than 60 days prior to the end of such term. On January 3, 2014, we entered into an employment agreement with Sergei Krylov as the Company’s Executive Vice President and Chief Financial Officer. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, was approximately $4.5 million at December 31, 2013. The commitment under the employment agreement entered into with the Company’s Executive Vice President and Chief Financial Officer on January 3, 2014 is $1.3 million. This estimate assumes the maximum potential bonus for 2014 is earned by each employee during 2014. | |||||
We lease our office space in Fort Worth, Texas, under a non-cancelable agreement that expires on December 31, 2017. We also have non-cancelable operating lease commitments related to office equipment that expire by 2017. The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2013 (in thousands): | |||||
2014 | $ | 668 | |||
2015 — 2018 | 2,014 | ||||
Total | $ | 2,682 | |||
Rent expense under our lease arrangements amounted to $734,000, $716,000 and $630,000 for the years ended December 31, 2013, 2012 and 2011, respectively. | |||||
Litigation | |||||
We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows. | |||||
Environmental Issues | |||||
We are engaged in oil and gas exploration and production and may become subject to certain liabilities or damages as they relate to environmental clean up of well sites or other environmental restoration or ground water contamination, in connection with drilling or operating oil and gas wells. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up, restoration or contamination, we would be responsible for curing such a violation or paying damages. No claim has been made, nor are we aware of any liability that exists, as it relates to any environmental clean up, restoration, contamination or the violation of any rules or regulations relating thereto. |
Oil_and_Gas_Producing_Activiti
Oil and Gas Producing Activities | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Extractive Industries [Abstract] | ' | ||||||||||||
Oil and Gas Producing Activities | ' | ||||||||||||
9 | Oil and Gas Producing Activities | ||||||||||||
Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities (in thousands): | |||||||||||||
For the Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Property acquisition costs: | |||||||||||||
Unproved properties | $ | 5,857 | $ | 2,335 | $ | 17,361 | |||||||
Proved properties | 1,000 | 5,407 | 5,063 | ||||||||||
Working Interest Acquisition | — | — | 70,827 | ||||||||||
Exploration costs | 2,238 | 4,550 | 9,991 | ||||||||||
Development costs(1) | 287,898 | 285,039 | 182,522 | ||||||||||
Total costs incurred | $ | 296,993 | $ | 297,331 | $ | 285,764 | |||||||
-1 | For the years ended December 31, 2013, 2012 and 2011, development costs include $584,000, $409,000 and $1.2 million in non-cash asset retirement obligations, respectively. | ||||||||||||
Set forth below is certain information regarding the results of operations for oil and gas producing activities (in thousands): | |||||||||||||
For the Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Revenues | $ | 181,302 | $ | 128,892 | $ | 108,387 | |||||||
Production costs | (31,992 | ) | (28,257 | ) | (19,134 | ) | |||||||
Exploration expense | (2,238 | ) | (4,550 | ) | (9,546 | ) | |||||||
Impairment | — | — | (18,476 | ) | |||||||||
Depletion | (76,956 | ) | (60,381 | ) | (31,858 | ) | |||||||
Income tax expense | (42,507 | ) | (12,139 | ) | (9,546 | ) | |||||||
Results of operations | $ | 27,609 | $ | 23,565 | $ | 19,827 | |||||||
Disclosures_About_Oil_and_Gas_
Disclosures About Oil and Gas Producing Activities (unaudited) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Text Block [Abstract] | ' | ||||||||||||||||
Disclosures About Oil and Gas Producing Activities (unaudited) | ' | ||||||||||||||||
10 | Disclosures About Oil and Gas Producing Activities (unaudited) | ||||||||||||||||
Proved Reserves | |||||||||||||||||
All of our estimated oil and natural gas reserves are attributable to properties within the United States, primarily in the Permian Basin in West Texas. The estimates of proved reserves and related valuations for the years ended December 31, 2013, 2012 and 2011, were prepared by DeGolyer and MacNaughton, independent petroleum engineers. Each year’s estimate of proved reserves and related valuations were also prepared in accordance with then-current rules and guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board. | |||||||||||||||||
The following table summarizes the prices used in the reserve estimates for 2013, 2012 and 2011. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows: | |||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||
Oil (per Bbl) | $ | 97.28 | $ | 90.21 | $ | 89.65 | |||||||||||
Natural gas liquids (per Bbl) | $ | 30.16 | $ | 37.88 | $ | 49.63 | |||||||||||
Gas (per Mcf) | $ | 3.66 | $ | 2.62 | $ | 3.97 | |||||||||||
Oil, NGL and natural gas reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. | |||||||||||||||||
The following table provides a summary of the changes of the total proved reserves for the years ended December 31, 2013, 2012 and 2011, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year. | |||||||||||||||||
Total Proved Reserves | Oil | NGLs | Natural Gas | Total | |||||||||||||
(MBbls) | (MBbls) | (MMcf) | (MBoe) | ||||||||||||||
Balance — December 31, 2010 | 4,951 | 20,699 | 150,389 | 50,715 | |||||||||||||
Extensions and discoveries | 11,847 | 7,010 | 40,146 | 25,548 | |||||||||||||
Purchases of minerals in place | 2,200 | 4,284 | 24,083 | 10,498 | |||||||||||||
Production | (482 | ) | (798 | ) | (6,345 | ) | (2,338 | ) | |||||||||
Revisions to previous estimates | (465 | ) | (2,072 | ) | (29,466 | ) | (7,448 | ) | |||||||||
Balance — December 31, 2011 | 18,051 | 29,123 | 178,807 | 76,975 | |||||||||||||
Extensions and discoveries | 21,993 | 8,639 | 49,372 | 38,861 | |||||||||||||
Production | (969 | ) | (904 | ) | (6,089 | ) | (2,888 | ) | |||||||||
Revisions to previous estimates | (1,823 | ) | (7,758 | ) | (47,330 | ) | (17,469 | ) | |||||||||
Balance — December 31, 2012 | 37,252 | 29,100 | 174,760 | 95,479 | |||||||||||||
Extensions and discoveries | 14,252 | 6,531 | 38,993 | 27,282 | |||||||||||||
Purchases of minerals in place | 62 | 14 | 197 | 109 | |||||||||||||
Production(1) | (1,444 | ) | (951 | ) | (6,737 | ) | (3,517 | ) | |||||||||
Revisions to previous estimates | (4,055 | ) | (2,102 | ) | (8,789 | ) | (4,692 | ) | |||||||||
Balance — December 31, 2013 | 46,067 | 32,593 | 216,002 | 114,661 | |||||||||||||
(1) Production includes 560 MMcf related to field fuel. | |||||||||||||||||
Proved Developed Reserves: | |||||||||||||||||
January 1, 2011 | 2,146 | 11,193 | 74,739 | 25,795 | |||||||||||||
December 31, 2011 | 5,542 | 13,945 | 84,743 | 33,611 | |||||||||||||
January 1, 2012 | 5,542 | 13,945 | 84,743 | 33,611 | |||||||||||||
December 31, 2012 | 8,816 | 11,761 | 73,178 | 32,774 | |||||||||||||
January 1, 2013 | 8,816 | 11,761 | 73,178 | 32,774 | |||||||||||||
December 31, 2013 | 13,646 | 14,919 | 99,742 | 45,189 | |||||||||||||
Proved Undeveloped Reserves: | |||||||||||||||||
January 1, 2011 | 2,805 | 9,506 | 75,650 | 24,920 | |||||||||||||
December 31, 2011 | 12,509 | 15,178 | 94,064 | 43,365 | |||||||||||||
January 1, 2012 | 12,509 | 15,178 | 94,064 | 43,365 | |||||||||||||
December 31, 2012 | 28,436 | 17,339 | 101,582 | 62,705 | |||||||||||||
January 1, 2013 | 28,436 | 17,339 | 101,582 | 62,705 | |||||||||||||
December 31, 2013 | 32,421 | 17,674 | 116,260 | 69,472 | |||||||||||||
The following is a discussion of the material changes in our proved reserve quantities for the years ended December 31, 2013, 2012 and 2011: | |||||||||||||||||
Year Ended December 31, 2013 | |||||||||||||||||
Extensions and discoveries for 2013 were 27.3 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. We produced 3.5 MMBoe during 2013. This production included 560 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lifts) before the gas was delivered to a sales point. During 2013, we recorded downward revisions totaling 4.7 MMBoe. Revisions included the reclassification of 7.8 MMBoe of proved undeveloped reserves to probable undeveloped, partially offset by 3.1 MMBoe of positive revisions attributable to gas that will be produced and utilized as field fuel. The reserves reclassified from proved undeveloped to probable undeveloped were attributable to vertical Canyon locations in Project Pangea. Due to our horizontal Wolfcamp development project, including pad drilling, postponement of these deeper locations beyond five years from initial booking is necessary to integrate their development with the shallower Clearfork and Wolfcamp target zones. We expect this integrated development to minimize surface impact and maximize reservoir recoveries. | |||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||
Extensions and discoveries of 38.9 MMBoe for 2012 were primarily attributable to ongoing development of Project Pangea in the Wolfcamp oil shale resource play in the Permian Basin. We produced 2.9 MMBoe during 2012, 99.4% of which is attributable to our assets in the Permian Basin. We recorded downward revisions of 17.5 MMBoe to the December 31, 2011, estimates of our proved reserves at year-end 2012. Downward revisions of 17.5 MMBoe include 8.9 MMBoe of deeper, Canyon reserves in southeast Project Pangea that we reclassified to probable undeveloped. Due to our horizontal Wolfcamp development project, including pad drilling, postponement of these deeper Canyon locations beyond five years from initial booking is necessary in order to integrate their development with shallower Clearfork and Wolfcamp target zones. Revisions in 2012 also include 3.3 MMBoe of performance revisions related to vertical Canyon wells in Project Pangea, 2.9 MMBoe of revisions resulting from technical evaluations and 2.4 MMBoe of revisions resulting from lower natural gas and NGL prices in 2012. | |||||||||||||||||
Year Ended December 31, 2011 | |||||||||||||||||
Extensions and discoveries of 25.5 MMBoe for 2011 include 24.2 MMBoe attributable to our Wolfcamp oil shale resource play in the Permian Basin. During 2011, we acquired approximately 10.5 MMBoe of proved reserves through the Working Interest Acquisition. We produced 2.4 MMBoe during 2011, 99% of which is attributable to our assets in the Permian Basin. We recorded downward revisions of 7.5 MMBoe to the December 31, 2010, estimates of our proved reserves at year-end 2011. Downward revisions of 7.5 MMBoe include 5.6 MMBoe of economic revisions in southeast Project Pangea in the Permian Basin and 2.2 MMBoe of proved undeveloped reserves in the East Texas Basin that, due to ongoing, low natural gas prices, we did not expect to develop by year-end 2013. Also included in the revisions were 0.3 MMBoe of positive revisions resulting from higher oil and NGL prices using the average 12-month price in 2011. | |||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves | |||||||||||||||||
The Standardized Measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference. | |||||||||||||||||
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise. | |||||||||||||||||
The following table provides the Standardized Measure of discounted future net cash flows at December 31, 2013, 2012 and 2011: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||
Future cash flows | $ | 5,953,060 | $ | 4,920,231 | $ | 3,772,633 | |||||||||||
Future production costs | (1,372,005 | ) | (1,220,403 | ) | (1,012,044 | ) | |||||||||||
Future development costs | (1,154,685 | ) | (1,025,193 | ) | (625,994 | ) | |||||||||||
Future income tax expense | (919,454 | ) | (692,528 | ) | (583,961 | ) | |||||||||||
Future net cash flows | 2,506,916 | 1,982,107 | 1,550,634 | ||||||||||||||
10% annual discount for estimated timing of cash flows | (1,830,639 | ) | (1,487,887 | ) | (1,136,253 | ) | |||||||||||
Standardized measure of discounted future net cash flows | $ | 676,277 | $ | 494,220 | $ | 414,381 | |||||||||||
Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end. | |||||||||||||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows | |||||||||||||||||
The changes in the Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||
Balance, beginning of period | $ | 494,220 | $ | 414,381 | $ | 204,232 | |||||||||||
Net change in sales and transfer prices and in production (lifting) costs related to future production | 74,088 | 147,421 | 334,104 | ||||||||||||||
Changes in estimated future development costs | (301,132 | ) | (486,435 | ) | (395,037 | ) | |||||||||||
Sales and transfers of oil and gas produced during the period | (149,310 | ) | (100,634 | ) | (89,253 | ) | |||||||||||
Net change due to extensions, discoveries and improved recovery | 360,080 | 467,822 | 291,501 | ||||||||||||||
Net change due to purchase of minerals in place | 1,435 | — | 119,780 | ||||||||||||||
Net change due to revisions in quantity estimates | (61,931 | ) | (210,296 | ) | (84,988 | ) | |||||||||||
Previously estimated development costs incurred during the period | 287,898 | 285,039 | 182,522 | ||||||||||||||
Accretion of discount | 87,937 | 60,162 | 32,793 | ||||||||||||||
Other | 1,896 | (11,281 | ) | (38,107 | ) | ||||||||||||
Net change in income taxes | (118,904 | ) | (71,959 | ) | (143,166 | ) | |||||||||||
Standardized Measure of discounted future net cash flows | $ | 676,277 | $ | 494,220 | $ | 414,381 |
Supplementary_Data
Supplementary Data | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ' | ||||||||||||||||
Supplementary Data | ' | ||||||||||||||||
11 | Supplementary Data | ||||||||||||||||
Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts): | |||||||||||||||||
2013 Quarters Ended | |||||||||||||||||
December 31 | September 30 | June 30 | March 31 | ||||||||||||||
Net revenue | $ | 58,565 | $ | 44,196 | $ | 42,272 | $ | 36,269 | |||||||||
Net operating expenses | (40,402 | ) | (34,314 | ) | (31,329 | ) | (31,665 | ) | |||||||||
Interest expense, net | (5,225 | ) | (5,179 | ) | (2,451 | ) | (1,229 | ) | |||||||||
Equity in (losses) earnings of investee | (4 | ) | 340 | (64 | ) | (116 | ) | ||||||||||
Gain on sale of Wildcat pipeline | 90,743 | — | — | — | |||||||||||||
Realized gain (loss) on commodity derivatives | 199 | (840 | ) | (714 | ) | 307 | |||||||||||
Unrealized (loss) gain on commodity derivatives | (1,348 | ) | (3,438 | ) | 4,290 | (4,100 | ) | ||||||||||
Income (loss) before income tax (benefit) | 102,528 | 765 | 12,004 | (534 | ) | ||||||||||||
Income tax provision (benefit) | 38,207 | 270 | 4,217 | (187 | ) | ||||||||||||
Net income (loss) | $ | 64,321 | $ | 495 | $ | 7,787 | $ | (347 | ) | ||||||||
Basic net income (loss) applicable to common stockholders per common share | $ | 1.65 | $ | 0.01 | $ | 0.2 | $ | (0.01 | ) | ||||||||
Diluted net income (loss) applicable to common stockholders per common share | $ | 1.65 | $ | 0.01 | $ | 0.2 | $ | (0.01 | ) | ||||||||
2012 Quarters Ended | |||||||||||||||||
December 31 | September 30 | June 30 | March 31 | ||||||||||||||
Net revenue | $ | 35,309 | $ | 33,038 | $ | 29,927 | $ | 30,618 | |||||||||
Net operating expenses | (36,777 | ) | (31,340 | ) | (26,095 | ) | (23,879 | ) | |||||||||
Interest expense, net | (926 | ) | (1,544 | ) | (1,380 | ) | (887 | ) | |||||||||
Equity in losses of investee | (108 | ) | — | — | — | ||||||||||||
Realized (loss) gain on commodity derivatives | (408 | ) | 423 | 361 | (484 | ) | |||||||||||
Unrealized gain (loss) on commodity derivatives | 1,292 | (4,185 | ) | 9,439 | (2,672 | ) | |||||||||||
(Loss) income before income tax (benefit) | (1,618 | ) | (3,608 | ) | 12,252 | 2,696 | |||||||||||
Income tax (benefit) provision | (781 | ) | (1,253 | ) | 4,390 | 982 | |||||||||||
Net (loss) income | $ | (837 | ) | $ | (2,355 | ) | $ | 7,862 | $ | 1,714 | |||||||
Basic net (loss) income applicable to common stockholders per common share | $ | (0.02 | ) | $ | (0.07 | ) | $ | 0.23 | $ | 0.05 | |||||||
Diluted net (loss) income applicable to common stockholders per common share | $ | (0.02 | ) | $ | (0.07 | ) | $ | 0.23 | $ | 0.05 | |||||||
2011 Quarters Ended | |||||||||||||||||
December 31 | September 30 | June 30 | March 31 | ||||||||||||||
Net revenue | $ | 31,123 | $ | 27,958 | $ | 29,123 | $ | 20,183 | |||||||||
Net operating expenses | (42,339 | ) | (19,092 | ) | (18,170 | ) | (17,930 | ) | |||||||||
Interest expense, net | (1,010 | ) | (1,016 | ) | (863 | ) | (513 | ) | |||||||||
Realized gain on commodity derivatives | 1,720 | 1,392 | 66 | 197 | |||||||||||||
Unrealized (loss) gain on commodity derivatives | (4,168 | ) | 1,739 | 2,231 | (149 | ) | |||||||||||
(Loss) gain on sale of oil and gas properties | (243 | ) | — | 3 | 488 | ||||||||||||
(Loss) income before income (benefit) tax | (14,917 | ) | 10,981 | 12,390 | 2,276 | ||||||||||||
Income tax (benefit) provision | (5,632 | ) | 3,908 | 4,400 | 812 | ||||||||||||
Net (loss) income | $ | (9,285 | ) | $ | 7,073 | $ | 7,990 | $ | 1,464 | ||||||||
Basic net (loss) income applicable to common stockholders per common share | $ | (0.30 | ) | $ | 0.25 | $ | 0.28 | $ | 0.05 | ||||||||
Diluted net (loss) income applicable to common stockholders per common share | $ | (0.30 | ) | $ | 0.25 | $ | 0.28 | $ | 0.05 | ||||||||
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Accounting Policies [Abstract] | ' | ||||||||||||
Organization and Nature of Operations | ' | ||||||||||||
Organization and Nature of Operations | |||||||||||||
Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin. | |||||||||||||
Consolidation, Basis of Presentation and Significant Estimates | ' | ||||||||||||
Consolidation, Basis of Presentation and Significant Estimates | |||||||||||||
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect our estimate of depletion expense as well as our impairment analyses. Significant assumptions also are required in our estimation of accrued liabilities, commodity derivatives, income tax provision, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior-year amounts have been reclassified to conform to current-year presentation. These classifications have no impact on the net income or loss reported. | |||||||||||||
Cash and Cash Equivalents | ' | ||||||||||||
Cash and Cash Equivalents | |||||||||||||
We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible. | |||||||||||||
Restricted cash | ' | ||||||||||||
Restricted Cash | |||||||||||||
The restricted cash on our balance sheet consists of $7.4 million in proceeds from the sale of our equity method investment that are restricted pursuant to an escrow agreement. The escrow termination date is June 1, 2014. | |||||||||||||
Capitalized Costs | ' | ||||||||||||
Capitalized Costs. Our oil and gas properties comprised the following (in thousands): | |||||||||||||
December 31, | |||||||||||||
2013 | 2012 | ||||||||||||
Mineral interests in properties: | |||||||||||||
Unproved leasehold costs | $ | 47,096 | $ | 49,148 | |||||||||
Proved leasehold costs | 40,620 | 32,252 | |||||||||||
Wells and related equipment and facilities | 1,195,556 | 908,456 | |||||||||||
Support equipment | 10,773 | 6,753 | |||||||||||
Uncompleted wells, equipment and facilities | 26,150 | 28,831 | |||||||||||
Total costs | 1,320,195 | 1,025,440 | |||||||||||
Less accumulated depreciation, depletion and amortization | (273,915 | ) | (197,751 | ) | |||||||||
Net capitalized costs | $ | 1,046,280 | $ | 827,689 | |||||||||
We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized, pending determination of whether the wells have proved reserves, at December 31, 2013 or 2012. Geological and geophysical costs, including seismic studies are charged to exploration expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use and while these expenditures are excluded from our depletable base. Through December 31, 2013, we have capitalized no interest costs because our individual wells and infrastructure projects are generally developed in less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred. | |||||||||||||
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with no gain or loss recognized in income. | |||||||||||||
Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment was $76.5 million, $60 million and $32.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. | |||||||||||||
Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. For 2011, we recorded an impairment expense of $15.2 million, which was attributable to our oil and gas properties in the East Texas Basin. At December 31, 2011, we had $2.7 million recorded for the East Texas Basin, which was the estimated fair value at December 31, 2011. We noted no impairment of our proved properties based on our analysis for the years ended December 31, 2013 and 2012. | |||||||||||||
Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. For 2011, we recorded an impairment expense of $3.3 million, related to all of our remaining carrying costs associated with our unproved properties in Northern New Mexico. | |||||||||||||
On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. During 2011, we sold our working interest in Northeast British Columbia for net proceeds of $360,000. The gain on the sale of this interest, net of foreign currency, was $248,000 and is included under “Other” on the consolidated statement of operations for the year ended December 31, 2011. | |||||||||||||
Other Property | ' | ||||||||||||
Other Property | |||||||||||||
Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to ten years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $502,000, $333,000 and $372,000 for the years ended December 31, 2013, 2012 and 2011, respectively. | |||||||||||||
Equity Method Investment | ' | ||||||||||||
Equity Method Investment | |||||||||||||
For investments in which we have the ability to exercise significant influence but do not have control, we follow the equity method of accounting. In September 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which is used to transport our oil to market. In 2013, we contributed $8.3 million to the equity joint venture for pipeline and facilities construction prior to its sale in October 2013. | |||||||||||||
Other Assets | ' | ||||||||||||
Other Assets | |||||||||||||
Other assets consist of deferred costs associated with the issuance of the $250 million principal amount of 7% Senior Notes due 2021 (the “Senior Notes”) and the revolving credit facility. These costs are amortized over the life of the Senior Notes and the life of the revolving credit facility on a straight-line basis, which approximates the amortization that would be calculated using an effective interest rate method. | |||||||||||||
Financial Instruments | ' | ||||||||||||
Financial Instruments | |||||||||||||
The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, as of December 31, 2013 and 2012. See Note 7 for commodity derivative and Senior Notes fair value disclosures. | |||||||||||||
Income Taxes | ' | ||||||||||||
Income Taxes | |||||||||||||
We are subject to U.S. federal income taxes along with state income taxes in Texas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in the consolidated statement of income. | |||||||||||||
Based on our analysis, we did not have any uncertain tax positions as of December 31, 2013 or 2012. The Company’s income tax returns are subject to examination by the relevant taxing authorities as follows: U.S. Federal income tax returns for tax years 2010 and forward, Texas income and margin tax returns for tax years 2010 and forward, New Mexico income tax returns for years 2010 and forward, and Kentucky income tax returns for the years 2010 and forward. There are currently no income tax examinations underway for these jurisdictions. | |||||||||||||
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change. | |||||||||||||
Derivative Activity | ' | ||||||||||||
Derivative Activity | |||||||||||||
We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.” | |||||||||||||
Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations. | |||||||||||||
Accrued Liabilities | ' | ||||||||||||
Accrued Liabilities | |||||||||||||
The following is a summary of our accrued liabilities at December 31, 2013 and 2012 (in thousands): | |||||||||||||
2013 | 2012 | ||||||||||||
Capital expenditures accrual | $ | 30,606 | $ | 25,526 | |||||||||
Operating expenses and other | 7,312 | 4,314 | |||||||||||
Total | $ | 37,918 | $ | 29,840 | |||||||||
Asset Retirement Obligations | ' | ||||||||||||
Asset Retirement Obligations | |||||||||||||
Our asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. Based on the expected timing of payments, the full asset retirement obligation is classified as non-current. There were no significant changes to the asset retirement obligations for the years ended December 31, 2013, 2012 and 2011. | |||||||||||||
Foreign Currency Translation | ' | ||||||||||||
Foreign Currency Translation | |||||||||||||
The functional currency of the country in which we currently operate is the U.S. dollar in the United States. For the year ended December 31, 2011, the functional currency of our Canadian subsidiary was the Canadian dollar. Assets and liabilities of our Canadian subsidiary that are denominated in currencies other than the Canadian dollar are translated at current exchange rates. Gains and losses resulting from such translations, along with gains or losses realized from transactions denominated in currencies other than the Canadian dollar are included in operating results on our statements of operations. For purposes of consolidation, we translate the assets and liabilities of our Canadian subsidiary into U.S. dollars at current exchange rates while revenues and expenses are translated at the average rates in effect for the period. The related translation gains and losses are included in accumulated other comprehensive income within stockholders’ equity on our consolidated balance sheets. We recognized no translation gains or losses during the year ended December 31, 2012, since we sold our working interest in northeast British Columbia in 2011. During the year ended December 31, 2011, we recognized a translation loss of $20,000, net of the related income taxes. | |||||||||||||
Share-Based Compensation | ' | ||||||||||||
Share-Based Compensation | |||||||||||||
We measure and record compensation expense for all share-based payment awards to employees and outside directors based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value. | |||||||||||||
Earnings Per Common Share | ' | ||||||||||||
Earnings Per Common Share | |||||||||||||
We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts): | |||||||||||||
For the Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Income (numerator): | |||||||||||||
Net income — basic | $ | 72,256 | $ | 6,384 | $ | 7,242 | |||||||
Weighted average shares (denominator): | |||||||||||||
Weighted average shares — basic | 38,997,815 | 34,965,182 | 28,930,792 | ||||||||||
Dilution effect of share-based compensation, treasury method | 21,334 | 65,141 | 227,806 | ||||||||||
Weighted average shares — diluted | 39,019,149 | 35,030,323 | 29,158,598 | ||||||||||
Earnings per share: | |||||||||||||
Basic | $ | 1.85 | $ | 0.18 | $ | 0.25 | |||||||
Diluted | $ | 1.85 | $ | 0.18 | $ | 0.25 | |||||||
Revenue and Accounts Receivable from Purchasers and Joint Interest Owners | ' | ||||||||||||
Revenue and Accounts Receivable. We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. | |||||||||||||
Accounts receivable, joint interest owners, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil, NGL and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2013 or 2012. | |||||||||||||
Oil and Gas Sales Payable | ' | ||||||||||||
Oil, NGL and Gas Sales Payable. Oil, NGL and gas sales payable represents amounts collected from purchasers for oil, NGL and gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 30 days of the end of the month in which the related production occurred. | |||||||||||||
Production Costs | ' | ||||||||||||
Production Costs. Production costs, including compressor rental and repair, pumpers’ and supervisors’ salaries, saltwater disposal, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on our consolidated statements of operations. | |||||||||||||
Exploration expenses | ' | ||||||||||||
Exploration expenses. Exploration expenses include dry hole costs, delay rentals and geological and geophysical costs. | |||||||||||||
Dependence on Suppliers | ' | ||||||||||||
Dependence on Suppliers. Our industry is cyclical, and from time-to-time there is a shortage of drilling rigs, equipment, services, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment, services and supplies are substantially greater. If the unavailability or high cost of drilling rigs, equipment, services, supplies or qualified personnel were particularly severe in the area where we operate, we could be materially and adversely affected. We believe that there are potential alternative providers of drilling and completion services and that it may be necessary to establish relationships with new contractors. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased availability of drilling rigs or other services. | |||||||||||||
Segment Reporting | ' | ||||||||||||
Segment Reporting | |||||||||||||
The Company presently operates in one business segment, the exploration and production of oil, NGLs and natural gas. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Accounting Policies [Abstract] | ' | ||||||||||||
Summary of Oil and Gas Properties | ' | ||||||||||||
Our oil and gas properties comprised the following (in thousands): | |||||||||||||
December 31, | |||||||||||||
2013 | 2012 | ||||||||||||
Mineral interests in properties: | |||||||||||||
Unproved leasehold costs | $ | 47,096 | $ | 49,148 | |||||||||
Proved leasehold costs | 40,620 | 32,252 | |||||||||||
Wells and related equipment and facilities | 1,195,556 | 908,456 | |||||||||||
Support equipment | 10,773 | 6,753 | |||||||||||
Uncompleted wells, equipment and facilities | 26,150 | 28,831 | |||||||||||
Total costs | 1,320,195 | 1,025,440 | |||||||||||
Less accumulated depreciation, depletion and amortization | (273,915 | ) | (197,751 | ) | |||||||||
Net capitalized costs | $ | 1,046,280 | $ | 827,689 | |||||||||
Summary of Accrued Liabilities | ' | ||||||||||||
The following is a summary of our accrued liabilities at December 31, 2013 and 2012 (in thousands): | |||||||||||||
2013 | 2012 | ||||||||||||
Capital expenditures accrual | $ | 30,606 | $ | 25,526 | |||||||||
Operating expenses and other | 7,312 | 4,314 | |||||||||||
Total | $ | 37,918 | $ | 29,840 | |||||||||
Reconciliations of Numerators and Denominators of our Basic and Diluted Earnings Per Share | ' | ||||||||||||
The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts): | |||||||||||||
For the Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Income (numerator): | |||||||||||||
Net income — basic | $ | 72,256 | $ | 6,384 | $ | 7,242 | |||||||
Weighted average shares (denominator): | |||||||||||||
Weighted average shares — basic | 38,997,815 | 34,965,182 | 28,930,792 | ||||||||||
Dilution effect of share-based compensation, treasury method | 21,334 | 65,141 | 227,806 | ||||||||||
Weighted average shares — diluted | 39,019,149 | 35,030,323 | 29,158,598 | ||||||||||
Earnings per share: | |||||||||||||
Basic | $ | 1.85 | $ | 0.18 | $ | 0.25 | |||||||
Diluted | $ | 1.85 | $ | 0.18 | $ | 0.25 | |||||||
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Debt Disclosure [Abstract] | ' | ||||||||
Schedule of Long Term Debt | ' | ||||||||
The following table provides a summary of our long-term debt at December 31, 2013, and December 31, 2012 (in thousands). | |||||||||
December 31, | December 31, | ||||||||
2013 | 2012 | ||||||||
Senior secured credit facility | $ | — | $ | 106,000 | |||||
Senior Notes | 250,000 | — | |||||||
Total long-term debt | $ | 250,000 | $ | 106,000 | |||||
ShareBased_Compensation_Tables
Share-Based Compensation (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | ' | ||||||||||||||||
Summary of Stock Options Outstanding and Activity | ' | ||||||||||||||||
The following table summarizes stock options outstanding and activity as of and for the years ended December 31, 2013, 2012 and 2011, (dollars in thousands): | |||||||||||||||||
Shares | Weighted | Weighted | Aggregate | ||||||||||||||
Subject to | Average | Average | Intrinsic | ||||||||||||||
Stock | Exercise | Remaining | Value | ||||||||||||||
Options | Price | Contractual | |||||||||||||||
Term | |||||||||||||||||
(in years) | |||||||||||||||||
Outstanding at January 1, 2011 | 334,338 | $ | 7.01 | 3.85 | $ | 4,567 | |||||||||||
Granted | — | — | |||||||||||||||
Exercised | (74,241 | ) | 13.59 | ||||||||||||||
Canceled | — | — | |||||||||||||||
Outstanding at December 31, 2011 | 260,097 | $ | 5.13 | 1.94 | $ | 6,315 | |||||||||||
Granted | — | — | |||||||||||||||
Exercised | (216,822 | ) | 3.68 | ||||||||||||||
Canceled | — | — | |||||||||||||||
Outstanding at December 31, 2012 | 43,275 | $ | 12.38 | 4.88 | $ | 547 | |||||||||||
Granted | — | — | |||||||||||||||
Exercised | (3,750 | ) | 15.42 | ||||||||||||||
Canceled | — | — | |||||||||||||||
Outstanding at December 31, 2013 | 39,525 | $ | 12.09 | 3.84 | $ | 285 | |||||||||||
Exercisable (fully vested) at December 31, 2013 | 39,525 | $ | 12.09 | 3.84 | $ | 285 | |||||||||||
Summary of the Status of Nonvested Shares | ' | ||||||||||||||||
A summary of the status of nonvested shares for the years ended December 31, 2013, 2012 and 2011, is presented below: | |||||||||||||||||
Shares | Weighted | ||||||||||||||||
Average | |||||||||||||||||
Grant-Date | |||||||||||||||||
Fair Value | |||||||||||||||||
Nonvested at January 1, 2011 | 708,781 | $ | 8.04 | ||||||||||||||
Granted | 256,317 | 31.54 | |||||||||||||||
Vested | (124,134 | ) | 9.93 | ||||||||||||||
Canceled | (50,842 | ) | 12.03 | ||||||||||||||
Nonvested at December 31, 2011 | 790,122 | 15.06 | |||||||||||||||
Granted | 316,279 | 32.94 | |||||||||||||||
Vested | (333,957 | ) | 14.57 | ||||||||||||||
Canceled | (19,365 | ) | 23.74 | ||||||||||||||
Nonvested at December 31, 2012 | 753,079 | 22.35 | |||||||||||||||
Granted | 377,379 | 22.77 | |||||||||||||||
Vested | (299,110 | ) | 18.79 | ||||||||||||||
Canceled | (132,117 | ) | 24.47 | ||||||||||||||
Nonvested at December 31, 2013 | 699,231 | $ | 23.7 | ||||||||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Income Tax Disclosure [Abstract] | ' | ||||||||||||
Schedule of Provision for Income Taxes | ' | ||||||||||||
Our provision for income taxes comprised the following (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Current: | |||||||||||||
Federal | $ | 429 | $ | — | $ | — | |||||||
State | — | — | — | ||||||||||
Total current provision for income taxes | $ | 429 | $ | — | $ | — | |||||||
Deferred: | |||||||||||||
Federal | $ | 41,175 | $ | 3,359 | $ | 3,199 | |||||||
State | 903 | (21 | ) | 289 | |||||||||
Total deferred provision for income taxes | $ | 42,078 | $ | 3,338 | $ | 3,488 | |||||||
Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income | ' | ||||||||||||
Total income tax expense differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Statutory tax at 35% | $ | 40,167 | $ | 3,306 | $ | 3,648 | |||||||
State taxes, net of federal impact | 709 | (21 | ) | 289 | |||||||||
Permanent differences(1) | 34 | 53 | (289 | ) | |||||||||
Other differences | 1,597 | — | (160 | ) | |||||||||
Total | $ | 42,507 | $ | 3,338 | $ | 3,488 | |||||||
-1 | Amounts primarily relate to share-based compensation expense. | ||||||||||||
Components of Deferred Tax Assets and Liabilities Computing Deferred Taxes, Net | ' | ||||||||||||
Significant components of net deferred tax assets and liabilities are (in thousands): | |||||||||||||
Years Ended December 31, | |||||||||||||
2013 | 2012 | ||||||||||||
Deferred tax assets: | |||||||||||||
Current portion of unrealized loss on commodity derivatives | $ | 681 | — | ||||||||||
Net operating loss carryforwards | 26,674 | $ | 27,353 | ||||||||||
Unrealized loss on commodity derivatives | 113 | — | |||||||||||
Other | 295 | 542 | |||||||||||
Total deferred tax assets | 27,763 | 27,895 | |||||||||||
Deferred tax liabilities: | |||||||||||||
Difference in depreciation, depletion and capitalization methods—oil and gas properties | (118,965 | ) | (76,170 | ) | |||||||||
Unrealized gain on commodity derivatives | — | (849 | ) | ||||||||||
Total deferred tax liabilities | (118,965 | ) | (77,019 | ) | |||||||||
Net deferred tax liability | $ | (91,202 | ) | $ | (49,124 | ) | |||||||
Net Operating Loss Carryforwards for Tax Purposes | ' | ||||||||||||
Net operating loss carryforwards for tax purposes have the following expiration dates (in thousands): | |||||||||||||
Expiration Dates | Amounts | Stock | Total | ||||||||||
Adjustments | |||||||||||||
2030 | $ | 4,083 | $ | 750 | $ | 4,833 | |||||||
2031 | 18,642 | 1,012 | 19,654 | ||||||||||
2032 | 51,931 | 2,724 | 54,655 | ||||||||||
2033 | — | 741 | 741 | ||||||||||
Total | $ | 74,656 | $ | 5,227 | $ | 79,883 | |||||||
Derivatives_Tables
Derivatives (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ' | ||||||||||||||||||||
Commodity Derivatives Volumes and Prices | ' | ||||||||||||||||||||
At December 31, 2013, we had the following commodity derivatives positions outstanding: | |||||||||||||||||||||
Commodity and Period | Contract | Volume Transacted | Contract Price | ||||||||||||||||||
Type | |||||||||||||||||||||
Crude Oil | |||||||||||||||||||||
2014 | Collar | 550 Bbls/d | $90.00/Bbl – $105.50/Bbl | ||||||||||||||||||
2014 | Collar | 950 Bbls/d | $85.05/Bbl – $95.05/Bbl | ||||||||||||||||||
2014 | Collar | 2,000 Bbls/d | $89.00/Bbl – $98.85/Bbl | ||||||||||||||||||
2015 | Collar | 2,600 Bbls/d | $84.00/Bbl – $91.00/Bbl | ||||||||||||||||||
Crude Oil Basis Differential (Midland/Cushing) | |||||||||||||||||||||
2014 | Swap | 1,500 Bbls/d | $0.55/Bbl | ||||||||||||||||||
Natural Gas Liquids | |||||||||||||||||||||
Propane 2014 | Swap | 500 Bbls/d | $41.16/Bbl | ||||||||||||||||||
Natural Gasoline 2014 | Swap | 175 Bbls/d | $83.37/Bbl | ||||||||||||||||||
Natural Gas | |||||||||||||||||||||
2014 | Swap | 360,000 MMBtu/month | $4.18/MMBtu | ||||||||||||||||||
2014(1) | Swap | 35,000 MMBtu/month | $4.29/MMBtu | ||||||||||||||||||
2015 | Swap | 200,000 MMBtu/month | $4.10/MMBtu | ||||||||||||||||||
2015 | Collar | 130,000 MMBtu/month | $4.00/MMBtu – $4.25/MMBtu | ||||||||||||||||||
-1 | February 2014 — December 2014. | ||||||||||||||||||||
Summary of Fair Value of Open Commodity Derivatives | ' | ||||||||||||||||||||
The following summarizes the fair value of our open commodity derivatives as of December 31, 2013 and 2012 (in thousands): | |||||||||||||||||||||
Asset Derivatives | Liability Derivatives | ||||||||||||||||||||
Fair Value | Fair Value | ||||||||||||||||||||
Balance Sheet | December 31, | December 31, | Balance Sheet | December 31, | December 31, | ||||||||||||||||
Location | 2013 | 2012 | Location | 2013 | 2012 | ||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||
Commodity derivatives | Unrealized gain on commodity derivatives | $ | 9,108 | $ | 2,433 | Unrealized loss on commodity derivatives | $ | 11,270 | $ | — | |||||||||||
Summary of Changes in Fair Value of Commodity Derivatives | ' | ||||||||||||||||||||
The following summarizes the change in the fair value of our commodity derivatives (in thousands): | |||||||||||||||||||||
Income Statement Location | |||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||||
Commodity derivatives | Unrealized (loss) gain on commodity derivatives | $ | (4,596 | ) | $ | 3,874 | $ | (347 | ) | ||||||||||||
Realized (loss) gain on commodity derivatives | (1,048 | ) | (108 | ) | 3,375 | ||||||||||||||||
$ | (5,644 | ) | $ | 3,766 | $ | 3,028 | |||||||||||||||
Fair Values of Financial Instruments that are Not Recorded at Fair Value on Our Financial Statements | ' | ||||||||||||||||||||
The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands). | |||||||||||||||||||||
December 31, 2013 | |||||||||||||||||||||
Carrying | Fair Value | ||||||||||||||||||||
Amount | |||||||||||||||||||||
Senior Notes | $ | 250,000 | $ | 256,875 | |||||||||||||||||
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 12 Months Ended | ||||
Dec. 31, 2013 | |||||
Commitments And Contingencies Disclosure [Abstract] | ' | ||||
Schedule of Years of Future Minimum Rental Payments Required Under Operating Lease Arrangements | ' | ||||
The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2013 (in thousands): | |||||
2014 | $ | 668 | |||
2015 — 2018 | 2,014 | ||||
Total | $ | 2,682 | |||
Oil_and_Gas_Producing_Activiti1
Oil and Gas Producing Activities (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Extractive Industries [Abstract] | ' | ||||||||||||
Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities | ' | ||||||||||||
Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities (in thousands): | |||||||||||||
For the Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Property acquisition costs: | |||||||||||||
Unproved properties | $ | 5,857 | $ | 2,335 | $ | 17,361 | |||||||
Proved properties | 1,000 | 5,407 | 5,063 | ||||||||||
Working Interest Acquisition | — | — | 70,827 | ||||||||||
Exploration costs | 2,238 | 4,550 | 9,991 | ||||||||||
Development costs(1) | 287,898 | 285,039 | 182,522 | ||||||||||
Total costs incurred | $ | 296,993 | $ | 297,331 | $ | 285,764 | |||||||
-1 | For the years ended December 31, 2013, 2012 and 2011, development costs include $584,000, $409,000 and $1.2 million in non-cash asset retirement obligations, respectively. | ||||||||||||
Schedule of Information Regarding Results of Operations for Oil and Gas Producing Activities | ' | ||||||||||||
Set forth below is certain information regarding the results of operations for oil and gas producing activities (in thousands): | |||||||||||||
For the Years Ended December 31, | |||||||||||||
2013 | 2012 | 2011 | |||||||||||
Revenues | $ | 181,302 | $ | 128,892 | $ | 108,387 | |||||||
Production costs | (31,992 | ) | (28,257 | ) | (19,134 | ) | |||||||
Exploration expense | (2,238 | ) | (4,550 | ) | (9,546 | ) | |||||||
Impairment | — | — | (18,476 | ) | |||||||||
Depletion | (76,956 | ) | (60,381 | ) | (31,858 | ) | |||||||
Income tax expense | (42,507 | ) | (12,139 | ) | (9,546 | ) | |||||||
Results of operations | $ | 27,609 | $ | 23,565 | $ | 19,827 | |||||||
Disclosures_About_Oil_and_Gas_1
Disclosures About Oil and Gas Producing Activities (unaudited) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Text Block [Abstract] | ' | ||||||||||||||||
Commodity Prices Inclusive of Adjustments for Quality and Location Used in Determining Future Net Revenues Related to Standardized Measure Calculation | ' | ||||||||||||||||
The following table summarizes the prices used in the reserve estimates for 2013, 2012 and 2011. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows: | |||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||
Oil (per Bbl) | $ | 97.28 | $ | 90.21 | $ | 89.65 | |||||||||||
Natural gas liquids (per Bbl) | $ | 30.16 | $ | 37.88 | $ | 49.63 | |||||||||||
Gas (per Mcf) | $ | 3.66 | $ | 2.62 | $ | 3.97 | |||||||||||
Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves | ' | ||||||||||||||||
The following table provides a summary of the changes of the total proved reserves for the years ended December 31, 2013, 2012 and 2011, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year. | |||||||||||||||||
Total Proved Reserves | Oil | NGLs | Natural Gas | Total | |||||||||||||
(MBbls) | (MBbls) | (MMcf) | (MBoe) | ||||||||||||||
Balance — December 31, 2010 | 4,951 | 20,699 | 150,389 | 50,715 | |||||||||||||
Extensions and discoveries | 11,847 | 7,010 | 40,146 | 25,548 | |||||||||||||
Purchases of minerals in place | 2,200 | 4,284 | 24,083 | 10,498 | |||||||||||||
Production | (482 | ) | (798 | ) | (6,345 | ) | (2,338 | ) | |||||||||
Revisions to previous estimates | (465 | ) | (2,072 | ) | (29,466 | ) | (7,448 | ) | |||||||||
Balance — December 31, 2011 | 18,051 | 29,123 | 178,807 | 76,975 | |||||||||||||
Extensions and discoveries | 21,993 | 8,639 | 49,372 | 38,861 | |||||||||||||
Production | (969 | ) | (904 | ) | (6,089 | ) | (2,888 | ) | |||||||||
Revisions to previous estimates | (1,823 | ) | (7,758 | ) | (47,330 | ) | (17,469 | ) | |||||||||
Balance — December 31, 2012 | 37,252 | 29,100 | 174,760 | 95,479 | |||||||||||||
Extensions and discoveries | 14,252 | 6,531 | 38,993 | 27,282 | |||||||||||||
Purchases of minerals in place | 62 | 14 | 197 | 109 | |||||||||||||
Production(1) | (1,444 | ) | (951 | ) | (6,737 | ) | (3,517 | ) | |||||||||
Revisions to previous estimates | (4,055 | ) | (2,102 | ) | (8,789 | ) | (4,692 | ) | |||||||||
Balance — December 31, 2013 | 46,067 | 32,593 | 216,002 | 114,661 | |||||||||||||
(1) Production includes 560 MMcf related to field fuel. | |||||||||||||||||
Proved Developed Reserves: | |||||||||||||||||
January 1, 2011 | 2,146 | 11,193 | 74,739 | 25,795 | |||||||||||||
December 31, 2011 | 5,542 | 13,945 | 84,743 | 33,611 | |||||||||||||
January 1, 2012 | 5,542 | 13,945 | 84,743 | 33,611 | |||||||||||||
December 31, 2012 | 8,816 | 11,761 | 73,178 | 32,774 | |||||||||||||
January 1, 2013 | 8,816 | 11,761 | 73,178 | 32,774 | |||||||||||||
December 31, 2013 | 13,646 | 14,919 | 99,742 | 45,189 | |||||||||||||
Proved Undeveloped Reserves: | |||||||||||||||||
January 1, 2011 | 2,805 | 9,506 | 75,650 | 24,920 | |||||||||||||
December 31, 2011 | 12,509 | 15,178 | 94,064 | 43,365 | |||||||||||||
January 1, 2012 | 12,509 | 15,178 | 94,064 | 43,365 | |||||||||||||
December 31, 2012 | 28,436 | 17,339 | 101,582 | 62,705 | |||||||||||||
January 1, 2013 | 28,436 | 17,339 | 101,582 | 62,705 | |||||||||||||
December 31, 2013 | 32,421 | 17,674 | 116,260 | 69,472 | |||||||||||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves | ' | ||||||||||||||||
The following table provides the Standardized Measure of discounted future net cash flows at December 31, 2013, 2012 and 2011: | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||
Future cash flows | $ | 5,953,060 | $ | 4,920,231 | $ | 3,772,633 | |||||||||||
Future production costs | (1,372,005 | ) | (1,220,403 | ) | (1,012,044 | ) | |||||||||||
Future development costs | (1,154,685 | ) | (1,025,193 | ) | (625,994 | ) | |||||||||||
Future income tax expense | (919,454 | ) | (692,528 | ) | (583,961 | ) | |||||||||||
Future net cash flows | 2,506,916 | 1,982,107 | 1,550,634 | ||||||||||||||
10% annual discount for estimated timing of cash flows | (1,830,639 | ) | (1,487,887 | ) | (1,136,253 | ) | |||||||||||
Standardized measure of discounted future net cash flows | $ | 676,277 | $ | 494,220 | $ | 414,381 | |||||||||||
Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves | ' | ||||||||||||||||
The changes in the Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): | |||||||||||||||||
Years Ended December 31, | |||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||
Balance, beginning of period | $ | 494,220 | $ | 414,381 | $ | 204,232 | |||||||||||
Net change in sales and transfer prices and in production (lifting) costs related to future production | 74,088 | 147,421 | 334,104 | ||||||||||||||
Changes in estimated future development costs | (301,132 | ) | (486,435 | ) | (395,037 | ) | |||||||||||
Sales and transfers of oil and gas produced during the period | (149,310 | ) | (100,634 | ) | (89,253 | ) | |||||||||||
Net change due to extensions, discoveries and improved recovery | 360,080 | 467,822 | 291,501 | ||||||||||||||
Net change due to purchase of minerals in place | 1,435 | — | 119,780 | ||||||||||||||
Net change due to revisions in quantity estimates | (61,931 | ) | (210,296 | ) | (84,988 | ) | |||||||||||
Previously estimated development costs incurred during the period | 287,898 | 285,039 | 182,522 | ||||||||||||||
Accretion of discount | 87,937 | 60,162 | 32,793 | ||||||||||||||
Other | 1,896 | (11,281 | ) | (38,107 | ) | ||||||||||||
Net change in income taxes | (118,904 | ) | (71,959 | ) | (143,166 | ) | |||||||||||
Standardized Measure of discounted future net cash flows | $ | 676,277 | $ | 494,220 | $ | 414,381 |
Supplementary_Data_Tables
Supplementary Data (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ' | ||||||||||||||||
Selected Quarterly Financial Data | ' | ||||||||||||||||
Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts): | |||||||||||||||||
2013 Quarters Ended | |||||||||||||||||
December 31 | September 30 | June 30 | March 31 | ||||||||||||||
Net revenue | $ | 58,565 | $ | 44,196 | $ | 42,272 | $ | 36,269 | |||||||||
Net operating expenses | (40,402 | ) | (34,314 | ) | (31,329 | ) | (31,665 | ) | |||||||||
Interest expense, net | (5,225 | ) | (5,179 | ) | (2,451 | ) | (1,229 | ) | |||||||||
Equity in (losses) earnings of investee | (4 | ) | 340 | (64 | ) | (116 | ) | ||||||||||
Gain on sale of Wildcat pipeline | 90,743 | — | — | — | |||||||||||||
Realized gain (loss) on commodity derivatives | 199 | (840 | ) | (714 | ) | 307 | |||||||||||
Unrealized (loss) gain on commodity derivatives | (1,348 | ) | (3,438 | ) | 4,290 | (4,100 | ) | ||||||||||
Income (loss) before income tax (benefit) | 102,528 | 765 | 12,004 | (534 | ) | ||||||||||||
Income tax provision (benefit) | 38,207 | 270 | 4,217 | (187 | ) | ||||||||||||
Net income (loss) | $ | 64,321 | $ | 495 | $ | 7,787 | $ | (347 | ) | ||||||||
Basic net income (loss) applicable to common stockholders per common share | $ | 1.65 | $ | 0.01 | $ | 0.2 | $ | (0.01 | ) | ||||||||
Diluted net income (loss) applicable to common stockholders per common share | $ | 1.65 | $ | 0.01 | $ | 0.2 | $ | (0.01 | ) | ||||||||
2012 Quarters Ended | |||||||||||||||||
December 31 | September 30 | June 30 | March 31 | ||||||||||||||
Net revenue | $ | 35,309 | $ | 33,038 | $ | 29,927 | $ | 30,618 | |||||||||
Net operating expenses | (36,777 | ) | (31,340 | ) | (26,095 | ) | (23,879 | ) | |||||||||
Interest expense, net | (926 | ) | (1,544 | ) | (1,380 | ) | (887 | ) | |||||||||
Equity in losses of investee | (108 | ) | — | — | — | ||||||||||||
Realized (loss) gain on commodity derivatives | (408 | ) | 423 | 361 | (484 | ) | |||||||||||
Unrealized gain (loss) on commodity derivatives | 1,292 | (4,185 | ) | 9,439 | (2,672 | ) | |||||||||||
(Loss) income before income tax (benefit) | (1,618 | ) | (3,608 | ) | 12,252 | 2,696 | |||||||||||
Income tax (benefit) provision | (781 | ) | (1,253 | ) | 4,390 | 982 | |||||||||||
Net (loss) income | $ | (837 | ) | $ | (2,355 | ) | $ | 7,862 | $ | 1,714 | |||||||
Basic net (loss) income applicable to common stockholders per common share | $ | (0.02 | ) | $ | (0.07 | ) | $ | 0.23 | $ | 0.05 | |||||||
Diluted net (loss) income applicable to common stockholders per common share | $ | (0.02 | ) | $ | (0.07 | ) | $ | 0.23 | $ | 0.05 | |||||||
2011 Quarters Ended | |||||||||||||||||
December 31 | September 30 | June 30 | March 31 | ||||||||||||||
Net revenue | $ | 31,123 | $ | 27,958 | $ | 29,123 | $ | 20,183 | |||||||||
Net operating expenses | (42,339 | ) | (19,092 | ) | (18,170 | ) | (17,930 | ) | |||||||||
Interest expense, net | (1,010 | ) | (1,016 | ) | (863 | ) | (513 | ) | |||||||||
Realized gain on commodity derivatives | 1,720 | 1,392 | 66 | 197 | |||||||||||||
Unrealized (loss) gain on commodity derivatives | (4,168 | ) | 1,739 | 2,231 | (149 | ) | |||||||||||
(Loss) gain on sale of oil and gas properties | (243 | ) | — | 3 | 488 | ||||||||||||
(Loss) income before income (benefit) tax | (14,917 | ) | 10,981 | 12,390 | 2,276 | ||||||||||||
Income tax (benefit) provision | (5,632 | ) | 3,908 | 4,400 | 812 | ||||||||||||
Net (loss) income | $ | (9,285 | ) | $ | 7,073 | $ | 7,990 | $ | 1,464 | ||||||||
Basic net (loss) income applicable to common stockholders per common share | $ | (0.30 | ) | $ | 0.25 | $ | 0.28 | $ | 0.05 | ||||||||
Diluted net (loss) income applicable to common stockholders per common share | $ | (0.30 | ) | $ | 0.25 | $ | 0.28 | $ | 0.05 | ||||||||
Summary_of_Significant_Account3
Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) | 12 Months Ended | 12 Months Ended | |||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 11, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2011 | |
Segment | Customer | Customer | Minimum [Member] | Maximum [Member] | Escrow [Member] | 7% Senior Notes due on 2021 [Member] | 7% Senior Notes due on 2021 [Member] | Wildcat Permian Services, LLC [Member] | DCP Midstream, LLC [Member] | JP Energy Permian, LLC [Member] | Oil and Gas [Member] | Oil and Gas [Member] | East Texas Basin [Member] | East Texas Basin [Member] | East Texas Basin [Member] | Unproved properties [Member] | |
Minimum [Member] | Maximum [Member] | ||||||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Restricted cash | $7,350,000 | ' | ' | ' | ' | $7,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Escrow termination date | ' | ' | ' | ' | ' | 1-Jun-14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of exploratory wells capitalized | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Capitalized interest cost | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation depletion and amortization for oil & gas | 76,500,000 | 60,000,000 | 32,100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Impairment expense for oil & gas | ' | ' | 18,476,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 15,200,000 | 3,300,000 |
Estimated fair value of oil and gas property | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,700,000 | ' |
Proceeds from sale of oil and gas properties | ' | ' | 360,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gain on the sale of working interest, net of foreign currency | ' | ' | 248,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated useful lives of furniture, fixtures and equipment | ' | ' | ' | '3 years | '10 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Depreciation expense for other property and equipment | 502,000 | 333,000 | 372,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Contribution to joint venture | 8,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Senior notes principle amounts | ' | ' | ' | ' | ' | ' | 250,000,000 | 250,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Tax benefit | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Uncertain tax positions | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Recognized translation loss, net of income tax | ' | ' | 20,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Recognized translation gains or losses | ' | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of days in which payment is to be made | '30 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '30 days | '60 days | ' | ' | ' | ' |
Number of customers for oil and gas | ' | 7 | 7 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Sales to customers | ' | ' | ' | ' | ' | ' | ' | ' | 30.00% | 27.00% | 23.00% | ' | ' | ' | ' | ' | ' |
Number of operating segment | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies - Summary of Oil and Gas Properties (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Mineral interests in properties: | ' | ' |
Unproved leasehold costs | $47,096 | $49,148 |
Proved leasehold costs | 40,620 | 32,252 |
Wells and related equipment and facilities | 1,195,556 | 908,456 |
Support equipment | 10,773 | 6,753 |
Uncompleted wells, equipment and facilities | 26,150 | 28,831 |
Total costs | 1,320,195 | 1,025,440 |
Less accumulated depreciation, depletion and amortization | -273,915 | -197,751 |
Net capitalized costs | $1,046,280 | $827,689 |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies - Summary of Accrued Liabilities (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Regulatory Assets [Abstract] | ' | ' |
Capital expenditures accrual | $30,606 | $25,526 |
Operating expenses and other | 7,312 | 4,314 |
Total | $37,918 | $29,840 |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies - Reconciliations of Numerators and Denominators of our Basic and Diluted Earnings Per Share (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2011 | Sep. 30, 2011 | Jun. 30, 2011 | Mar. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Income (numerator): | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net income - basic | $64,321 | $495 | $7,787 | ($347) | ($837) | ($2,355) | $7,862 | $1,714 | ($9,285) | $7,073 | $7,990 | $1,464 | $72,256 | $6,384 | $7,242 |
Weighted average shares (denominator): | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted average shares - basic | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 38,997,815 | 34,965,182 | 28,930,792 |
Dilution effect of share-based compensation, treasury method | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,334 | 65,141 | 227,806 |
Weighted average shares - diluted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 39,019,149 | 35,030,323 | 29,158,598 |
Basic | $1.65 | $0.01 | $0.20 | ($0.01) | ($0.02) | ($0.07) | $0.23 | $0.05 | ($0.30) | $0.25 | $0.28 | $0.05 | $1.85 | $0.18 | $0.25 |
Diluted | $1.65 | $0.01 | $0.20 | ($0.01) | ($0.02) | ($0.07) | $0.23 | $0.05 | ($0.30) | $0.25 | $0.28 | $0.05 | $1.85 | $0.18 | $0.25 |
Equity_Method_Investment_Addit
Equity Method Investment - Additional Information (Detail) (USD $) | 0 Months Ended | 3 Months Ended | 12 Months Ended | |
Oct. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Oct. 31, 2012 | |
Schedule Of Results Related To Equity Accounted Investees [Line Items] | ' | ' | ' | ' |
Contribution to joint venture | ' | ' | $8,300,000 | ' |
Initial contribution to joint venture-Pipeline and facilities construction | ' | ' | ' | 10,000,000 |
Proceeds from sale of joint venture | 109,100,000 | ' | ' | ' |
Pre-Tax Gain on sale of equity interest joint venture | 90,700,000 | 90,743,000 | 90,743,000 | ' |
Restricted cash | ' | 7,350,000 | 7,350,000 | ' |
Escrow [Member] | ' | ' | ' | ' |
Schedule Of Results Related To Equity Accounted Investees [Line Items] | ' | ' | ' | ' |
Restricted cash | ' | $7,400,000 | $7,400,000 | ' |
Escrow termination date | ' | ' | 1-Jun-14 | ' |
Public_Equity_Offerings_Additi
Public Equity Offerings - Additional Information (Detail) (USD $) | 0 Months Ended | |||||
In Millions, except Share data, unless otherwise specified | Sep. 19, 2012 | Nov. 15, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 03, 2012 | Nov. 16, 2011 |
Equity [Abstract] | ' | ' | ' | ' | ' | ' |
Common stock, issued | 5,000,000 | 4,000,000 | 39,047,699 | 38,829,368 | ' | ' |
Additional purchase of common stock | ' | ' | ' | ' | 325,000 | 600,000 |
Transaction costs | $8 | $6.60 | ' | ' | ' | ' |
Received net proceeds | $154.40 | $122.20 | ' | ' | ' | ' |
LongTerm_Debt_Schedule_of_Long
Long-Term Debt - Schedule of Long Term Debt (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Debt Disclosure [Abstract] | ' | ' |
Senior secured credit facility | ' | $106,000 |
Senior notes | 250,000 | ' |
Total long-term debt | $250,000 | $106,000 |
LongTerm_Debt_Additional_Infor
Long-Term Debt - Additional Information (Detail) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 5 Months Ended | 5 Months Ended | |||||||||||||||
Dec. 15, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Jan. 23, 2014 | Jan. 23, 2014 | Jan. 23, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 11, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | 1-May-13 | Nov. 06, 2013 | 1-May-13 | Nov. 06, 2013 | |
Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Debt Instrument Redemption Period [Member] | Credit Facility [Member] | Credit Facility [Member] | Credit Facility [Member] | Credit Facility [Member] | 7% Senior Notes due on 2021 [Member] | 7% Senior Notes due on 2021 [Member] | Covenants agreements one [Member] | Covenants agreements two [Member] | Interest rate calculation one [Member] | Interest rate calculation one [Member] | Interest rate calculation two [Member] | Interest rate calculation two [Member] | Scenario, Forecast [Member] | Scenario, Forecast [Member] | Scenario, Forecast [Member] | Scenario, Forecast [Member] | ||||
Two year derivatives contracts [Member] | Three year derivatives contracts [Member] | Four and five year derivatives contracts [Member] | Minimum [Member] | Maximum [Member] | Credit Facility [Member] | Credit Facility [Member] | Credit Facility [Member] | Credit Facility [Member] | Credit Facility [Member] | Credit Facility [Member] | Credit Facility [Member] | Credit Facility [Member] | |||||||||||
Seventeeth Amendment Credit Agreement [Member] | Seventeeth Amendment Credit Agreement [Member] | Seventeeth Amendment Credit Agreement [Member] | Minimum [Member] | Maximum [Member] | Minimum [Member] | Maximum [Member] | Minimum [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | |||||||||||||
Credit Facilities [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maturity period of revolving credit facility | ' | ' | ' | ' | ' | ' | ' | 31-Jul-16 | ' | ' | 31-Jul-16 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revolving credit facility, borrowing base | ' | ' | ' | ' | ' | ' | ' | $350,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $315,000,000 | ' | $350,000,000 |
Revolving credit facility, maximum borrowing capacity | ' | ' | ' | ' | ' | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revolving credit facility, interest rate description | ' | ' | ' | ' | ' | ' | ' | 'Borrowings bear interest based on the agent bank's prime rate plus an applicable margin ranging from 0.75% to 1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revolving credit facility, marginal percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.75% | 1.75% | 1.75% | 2.75% | ' | ' | ' | ' |
Annual commitment fee of unused borrowings | ' | ' | ' | ' | ' | ' | ' | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Increase in the borrowing base for line of credit facility | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 280,000,000 | ' | 315,000,000 | ' |
Increased lender's aggregate maximum commitment | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Projected production from oil and gas properties | ' | ' | ' | 85.00% | 100.00% | 85.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount outstanding under revolving credit facility | ' | ' | 106,000,000 | ' | ' | ' | ' | 0 | 106,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Interest rate applicable of revolving credit facility | ' | ' | ' | ' | ' | ' | ' | ' | 2.70% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unused letters of credit outstanding | ' | ' | ' | ' | ' | ' | ' | 325,000 | 325,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Consolidated current assets ratio | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Consolidated current liabilities ratio | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Covenant description | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'A consolidated modified current ratio covenant that requires us to maintain a ratio of not less than 1.0 to 1.0 at all times. | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Consolidated funded debt ratio | ' | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Consolidated earnings before interest taxes depreciation amortization and exploration expenses ratio | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ratio covenant description | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'A consolidated funded debt to consolidated EBITDAX ratio covenant that requires us to maintain a ratio of not more than 4.0 to 1.0 at the end of each fiscal quarter. | ' | ' | ' | ' | ' | ' | ' | ' |
Debt default description | ' | 'In addition, our Credit Facility contains customary events of default that would permit our lenders to accelerate the debt under our Credit Facility if not cured within applicable grace periods, including, among others, failure to make payments of principal or interest when due, materially incorrect representations and warranties, failure to make mandatory prepayments in the event of borrowing base deficiencies, breach of covenants, defaults upon other obligations in excess of $500,000, events of bankruptcy, the occurrence of one or more unstayed judgments in excess of $500,000 not covered by an acceptable policy of insurance, failure to pay any obligation in excess of $500,000 owed under any derivatives transaction or in any amount if the obligation under the derivatives transaction is secured by collateral under the Credit Facility, any event of default by the Company occurs under any agreement entered into in connection with a derivatives transaction, liens securing the loans under the credit agreement cease to be in place, a change in control (as defined under the Credit Facility) of the Company occurs, and dissolution of the Company. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt default amount | ' | 500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Senior Notes maturity date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15-Jun-21 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Senior notes | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 250,000,000 | 250,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stated interest rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Issuance of Senior Notes | ' | 242,824,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 243,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt instrument redemption description | ' | 'Before June 15, 2016, we may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. | ' | ' | ' | ' | 'Before June 15, 2016, we may redeem up to 35% of the Senior Notes at a redemption price of 107% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Semi-annual interest payment amount | $8,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt instrument, redemption percentage | ' | ' | ' | ' | ' | ' | 35.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt instrument, redemption of principal amount percentage | ' | 100.00% | ' | ' | ' | ' | 107.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
ShareBased_Compensation_Additi
Share-Based Compensation - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
The maximum number of common stock | 2,100,000 | ' | ' |
Maximum term of stock option | '10 years | ' | ' |
Amendment effective date | 'May 31, 2012 | ' | ' |
Share-based compensation expense | $5,900,000 | $7,500,000 | $4,700,000 |
Intrinsic value of the options exercised | 35,000 | 7,000,000 | 1,100,000 |
Tax benefit recognized related to the stock option exercises | 0 | 0 | ' |
Subsequent Restricted Share Award | 245,157 | ' | ' |
Fair Market Value of Shares subject to Performance Conditions | 3,400,000 | ' | ' |
Service period | '3 years | ' | ' |
Non Employee Director [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Share-based compensation expense | 630,000 | 535,000 | 420,000 |
Performance Condition Awards [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Subsequent Restricted Share Award | 163,438 | ' | ' |
Total Shareholder Return Performance Stock Awards [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Subsequent Restricted Share Award | 81,719 | ' | ' |
Forfeiture Benefit Adjustments Member [Member] | Executive Officers [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Forfeited stock awards | 1,000,000 | ' | ' |
Nonvested Shares [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Shares grant | 377,379 | 316,279 | 256,317 |
Average grant date fair value | 8,600,000 | 10,400,000 | 8,100,000 |
Unrecognized compensation expense related to nonvested shares | 16,600,000 | ' | ' |
Nonvested outstanding weighted average remaining service period | '3 years | ' | ' |
Nonvested Shares [Member] | Executive Officers [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Additional shares grant | 183,672 | 129,890 | 204,000 |
Additional share grant fair value | $4,400,000 | $4,800,000 | $6,500,000 |
ShareBased_Compensation_Summar
Share-Based Compensation - Summary of Stock Options Outstanding and Activity (Detail) (USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | ' | ' | ' |
Share Subject to Stock Options, Beginning Balance | 43,275 | 260,097 | 334,338 |
Weighted Average Exercise Price, Outstanding, Beginning Balance | $12.38 | $5.13 | $7.01 |
Share Subject to Stock Options, Granted | ' | ' | ' |
Shares Subject to Stock Options, Exercised | -3,750 | -216,822 | -74,241 |
Shares Subject to Stock Options, Canceled | ' | ' | ' |
Share Subject to Stock Options, Ending Balance | 39,525 | 43,275 | 260,097 |
Shares Subject to Stock Options, Shares Exercisable, Ending Balance | 39,525 | ' | ' |
Weighted Average Exercise Price, Outstanding, Granted | ' | ' | ' |
Weighted Average Exercise Price, Outstanding, Exercised | $15.42 | $3.68 | $13.59 |
Weighted Average Exercise Price, Outstanding, Canceled | ' | ' | ' |
Weighted Average Exercise Price, Outstanding, Ending Balance | $12.09 | $12.38 | $5.13 |
Weighted Average Exercise Price, Exercisable, Ending Balance | $12.09 | ' | ' |
Weighted Average Remaining Contractual Term, Outstanding, Beginning Balance | '4 years 10 months 17 days | '1 year 11 months 9 days | '3 years 10 months 6 days |
Weighted Average Remaining Contractual Term, Outstanding, Ending Balance | '3 years 10 months 2 days | '4 years 10 months 17 days | '1 year 11 months 9 days |
Outstanding, Aggregate Intrinsic Value, Beginning Value | $547 | $6,315 | $4,567 |
Weighted Average Remaining Contractual Term, Exercisable, Ending Balance | '3 years 10 months 2 days | ' | ' |
Outstanding, Aggregate Intrinsic Value, Ending Balance | 285 | 547 | 6,315 |
Outstanding, Exercisable, Aggregate Intrinsic Value | $285 | ' | ' |
ShareBased_Compensation_Summar1
Share-Based Compensation - Summary of the Status of Nonvested Shares (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | ' | ' | ' |
Nonvested Shares, Beginning Balance | 753,079 | 790,122 | 708,781 |
Nonvested Shares, Granted | 377,379 | 316,279 | 256,317 |
Nonvested Shares, Vested | -299,110 | -333,957 | -124,134 |
Nonvested Shares, Canceled | -132,117 | -19,365 | -50,842 |
Nonvested Shares, Ending Balance | 699,231 | 753,079 | 790,122 |
Weighted Average Grant-Date Fair Value, Nonvested, Beginning Balance | $22.35 | $15.06 | $8.04 |
Weighted Average Grant-Date Fair Value, Nonvested, Granted | $22.77 | $32.94 | $31.54 |
Weighted Average Grant-Date Fair Value, Nonvested, Vested | $18.79 | $14.57 | $9.93 |
Weighted Average Grant-Date Fair Value, Nonvested, Canceled | $24.47 | $23.74 | $12.03 |
Weighted Average Grant-Date Fair Value, Nonvested | $23.70 | $22.35 | $15.06 |
Income_Taxes_Schedule_of_Provi
Income Taxes - Schedule of Provision for Income Taxes (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Current: | ' | ' | ' |
Federal | $429 | ' | ' |
State | ' | ' | ' |
Total current provision for income taxes | 429 | ' | ' |
Deferred: | ' | ' | ' |
Federal | 41,175 | 3,359 | 3,199 |
State | 903 | -21 | 289 |
Total deferred provision for income taxes | $42,078 | $3,338 | $3,488 |
Income_Taxes_Total_Income_Tax_
Income Taxes - Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2011 | Sep. 30, 2011 | Jun. 30, 2011 | Mar. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Income Tax Disclosure [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Statutory tax at 35% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $40,167 | $3,306 | $3,648 |
State taxes, net of federal impact | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 709 | -21 | 289 |
Permanent differences | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34 | 53 | -289 |
Other differences | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,597 | ' | -160 |
Total | $38,207 | $270 | $4,217 | ($187) | ($781) | ($1,253) | $4,390 | $982 | ($5,632) | $3,908 | $4,400 | $812 | $42,507 | $3,338 | $3,488 |
Income_Taxes_Total_Income_Tax_1
Income Taxes - Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income (Parenthetical) (Detail) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Income Tax Disclosure [Abstract] | ' | ' | ' |
Statutory tax rate | 35.00% | 35.00% | 35.00% |
Income_Taxes_Additional_Inform
Income Taxes - Additional Information (Detail) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Income Tax Disclosure [Abstract] | ' | ' |
Net deferred tax assets and liabilities recorded as long-term liability | $91.90 | $48.60 |
Deferred taxes expected to be realized within one year | 0.7 | -0.5 |
Net operating loss carryforwards | 79.9 | ' |
Benefit of stock options | $5.20 | ' |
Income_Taxes_Significant_Compo
Income Taxes - Significant Components of Net Deferred Tax Assets and Liabilities (Detail) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Income Tax Disclosure [Abstract] | ' | ' |
Current portion of unrealized loss on commodity derivatives | $681 | ' |
Net operating loss carry forwards | 26,674 | 27,353 |
Unrealized loss on commodity derivatives | 113 | ' |
Other | 295 | 542 |
Total deferred tax assets | 27,763 | 27,895 |
Deferred tax liabilities: | ' | ' |
Difference in depreciation, depletion and capitalization methods-oil and gas properties | -118,965 | -76,170 |
Unrealized gain on commodity derivatives | ' | -849 |
Total deferred tax liabilities | -118,965 | -77,019 |
Net deferred tax liability | ($91,202) | ($49,124) |
Income_Taxes_Net_Operating_Los
Income Taxes - Net Operating Loss Carryforwards for Tax Purposes (Detail) (USD $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Operating Loss Carryforwards [Line Items] | ' |
Amounts | $74,656 |
Stock Adjustments | 5,227 |
Total | 79,883 |
Expiration Dates 2030 [Member] | ' |
Operating Loss Carryforwards [Line Items] | ' |
Amounts | 4,083 |
Stock Adjustments | 750 |
Total | 4,833 |
Expiration Dates | '2030 |
Expiration Dates 2031 [Member] | ' |
Operating Loss Carryforwards [Line Items] | ' |
Amounts | 18,642 |
Stock Adjustments | 1,012 |
Total | 19,654 |
Expiration Dates | '2031 |
Expiration Date 2032 [Member] | ' |
Operating Loss Carryforwards [Line Items] | ' |
Amounts | 51,931 |
Stock Adjustments | 2,724 |
Total | 54,655 |
Expiration Dates | '2032 |
Expiration Date 2033 [Member] | ' |
Operating Loss Carryforwards [Line Items] | ' |
Amounts | ' |
Stock Adjustments | 741 |
Total | $741 |
Expiration Dates | '2033 |
Derivatives_Commodity_Derivati
Derivatives - Commodity Derivatives Volumes and Prices (Detail) | 12 Months Ended |
Dec. 31, 2013 | |
Natural Gas - 2014 Contract [Member] | Swap [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 360,000 |
Contract Price | 4.18 |
Natural Gas Two Zero One Four Contract February To December [Member] | Swap [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 35,000 |
Contract Price | 4.29 |
Natural Gas - 2015 Contract [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 130,000 |
Natural Gas - 2015 Contract [Member] | Swap [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 200,000 |
Contract Price | 4.1 |
Crude Oil - 2014 Contract One [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 550 |
Crude Oil - 2014 Contract Two [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 950 |
Crude Oil - 2014 Contract Three [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 2,000 |
Crude Oil -2015 [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 2,600 |
Crude Oil Basis Differential -2014 [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 1,500 |
Contract Price | 0.55 |
Propane - 2014 [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 500 |
Contract Price | 41.16 |
Natural Gasoline -2014 [Member] | ' |
Derivative [Line Items] | ' |
Volume Transacted | 175 |
Contract Price | 83.37 |
Minimum [Member] | Natural Gas - 2015 Contract [Member] | ' |
Derivative [Line Items] | ' |
Contract Price | 4 |
Minimum [Member] | Crude Oil - 2014 Contract One [Member] | ' |
Derivative [Line Items] | ' |
Contract Price | 90 |
Minimum [Member] | Crude Oil - 2014 Contract Two [Member] | ' |
Derivative [Line Items] | ' |
Contract Price | 85.05 |
Minimum [Member] | Crude Oil - 2014 Contract Three [Member] | ' |
Derivative [Line Items] | ' |
Contract Price | 89 |
Minimum [Member] | Crude Oil -2015 [Member] | ' |
Derivative [Line Items] | ' |
Contract Price | 84 |
Maximum [Member] | Natural Gas - 2015 Contract [Member] | ' |
Derivative [Line Items] | ' |
Contract Price | 4.25 |
Maximum [Member] | Crude Oil - 2014 Contract One [Member] | ' |
Derivative [Line Items] | ' |
Contract Price | 105.5 |
Maximum [Member] | Crude Oil - 2014 Contract Two [Member] | ' |
Derivative [Line Items] | ' |
Contract Price | 95.05 |
Maximum [Member] | Crude Oil - 2014 Contract Three [Member] | ' |
Derivative [Line Items] | ' |
Contract Price | 98.85 |
Maximum [Member] | Crude Oil -2015 [Member] | ' |
Derivative [Line Items] | ' |
Contract Price | 91 |
Derivatives_Additional_Informa
Derivatives - Additional Information (Detail) (Subsequent Event [Member], USD $) | Jan. 31, 2014 | Feb. 25, 2014 | Feb. 25, 2014 | Feb. 25, 2014 | Feb. 25, 2014 |
In Millions, unless otherwise specified | Crude Oil Collar [Member] | April 2014 through March 2015 [Member] | Natural Gas Swap [Member] | Natural Gas Swap [Member] | Natural Gas Collars [Member] |
Crude Oil Collar [Member] | Contract | March through December 2014 [Member] | September 2014 through June 2015 [Member] | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ' | ' | ' | ' | ' |
Number of contracts | ' | ' | 1 | ' | ' |
Volume Transacted | ' | 1,500 | ' | 160,000 | 80,000 |
Contract Price | ' | ' | ' | 4.4 | ' |
Floor Price | ' | 85 | ' | ' | 4 |
Ceiling Price | ' | 95.3 | ' | ' | 4.74 |
Early settlement of crude oil basis differential swap | $0.70 | ' | ' | ' | ' |
Derivatives_Summary_of_Fair_Va
Derivatives - Summary of Fair Value of Open Commodity Derivatives (Detail) (Commodity derivatives [Member], USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Derivative not designated as hedging instruments, fair value of liability derivative [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Unrealized loss on commodity derivatives | $11,270 | ' |
Derivative not designated as hedging instruments, fair value of assets derivative [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Unrealized gain on commodity derivatives | $9,108 | $2,433 |
Derivatives_Summary_of_Changes
Derivatives - Summary of Changes in Fair Value of Commodity Derivatives (Detail) (Commodity derivatives [Member], USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Commodity derivatives [Member] | ' | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' | ' |
Unrealized (loss) gain on commodity derivatives | ($4,596) | $3,874 | ($347) |
Realized (loss) gain on commodity derivatives | -1,048 | -108 | 3,375 |
Derivatives not designated as hedging instruments, total (loss) gain | ($5,644) | $3,766 | $3,028 |
Derivatives_Fair_Value_of_Fina
Derivatives - Fair Value of Financial Instruments Not Recorded in Financial Statements (Detail) (USD $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Offsetting [Abstract] | ' |
Senior Notes, Carrying Amount | $250,000 |
Senior Notes, Fair Value | $256,875 |
Commitments_and_Contingencies_1
Commitments and Contingencies - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Commitment And Contingencies [Line Items] | ' | ' | ' |
Non-Cancelable operating lease expiration date | '2017 | ' | ' |
Non-Cancelable lease agreement for office space, expiration date | 'December 31, 2017 | ' | ' |
Rent expense under lease arrangements | $734,000 | $716,000 | $630,000 |
Drilling contracts [Member] | ' | ' | ' |
Commitment And Contingencies [Line Items] | ' | ' | ' |
Commitment under contracts | 1,900,000 | ' | ' |
Employment agreements [Member] | ' | ' | ' |
Commitment And Contingencies [Line Items] | ' | ' | ' |
Commitment under contracts | 1,300,000 | ' | ' |
Employment agreements [Member] | Executive Vice President and Chief Financial Officer [Member] | ' | ' | ' |
Commitment And Contingencies [Line Items] | ' | ' | ' |
Commitment under contracts | $4,500,000 | ' | ' |
Commitments_and_Contingencies_2
Commitments and Contingencies - Schedule of Years of Future Minimum Rental Payments Required Under Operating Lease Arrangements (Detail) (USD $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Commitments And Contingencies Disclosure [Abstract] | ' |
2014 | $668 |
2015 - 2018 | 2,014 |
Total | $2,682 |
Oil_and_Gas_Producing_Activiti2
Oil and Gas Producing Activities - Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Extractive Industries [Abstract] | ' | ' | ' |
Unproved properties | $5,857 | $2,335 | $17,361 |
Proved properties | 1,000 | 5,407 | 5,063 |
Working Interest Acquisition | ' | ' | 70,827 |
Exploration costs | 2,238 | 4,550 | 9,991 |
Development costs | 287,898 | 285,039 | 182,522 |
Total costs incurred | $296,993 | $297,331 | $285,764 |
Oil_and_Gas_Producing_Activiti3
Oil and Gas Producing Activities - Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities (Parenthetical) (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ' |
Development costs | $287,898 | $285,039 | $182,522 |
Non-cash asset retirement obligations [Member] | ' | ' | ' |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ' | ' | ' |
Development costs | $584 | $409 | $1,200 |
Oil_and_Gas_Producing_Activiti4
Oil and Gas Producing Activities - Schedule of Information Regarding Results of Operations for Oil and Gas Producing Activities (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Extractive Industries [Abstract] | ' | ' | ' |
Revenues | $181,302 | $128,892 | $108,387 |
Production costs | -31,992 | -28,257 | -19,134 |
Exploration expense | -2,238 | -4,550 | -9,546 |
Impairment | ' | ' | -18,476 |
Depletion | -76,956 | -60,381 | -31,858 |
Income tax expense | -42,507 | -12,139 | -9,546 |
Results of operations | $27,609 | $23,565 | $19,827 |
Disclosures_About_Oil_and_Gas_2
Disclosures About Oil and Gas Producing Activities - Commodity Prices Inclusive of Adjustments for Quality and Location Used in Determining Future Net Revenues Related to Standardized Measure Calculation (Detail) (Reserve Estimate [Member]) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Oil (MBbls) [Member] | ' | ' | ' |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ' | ' | ' |
Commodity Prices | 97.28 | 90.21 | 89.65 |
NGLs (MBbls) [Member] | ' | ' | ' |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ' | ' | ' |
Commodity Prices | 30.16 | 37.88 | 49.63 |
Natural Gas (MMcf) [Member] | ' | ' | ' |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ' | ' | ' |
Commodity Prices | 3.66 | 2.62 | 3.97 |
Disclosures_About_Oil_and_Gas_3
Disclosures About Oil and Gas Producing Activities - Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves (Detail) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
MBoe | MBoe | MBoe | |
Reserve Quantities [Line Items] | ' | ' | ' |
Proved Developed and Proved Undeveloped Reserves, Mboe Beginning Balance | 95,479 | 76,975 | 50,715 |
Extensions and discoveries, Mboe | 27,282 | 38,861 | 25,548 |
Purchases of minerals in place, Mboe | 109 | ' | 10,498 |
Production, Mboe | -3,517 | -2,888 | -2,338 |
Revisions to previous estimates, Mboe | -4,692 | -17,469 | -7,448 |
Proved Developed and Proved Undeveloped Reserves, Mboe Ending Balance | 114,661 | 95,479 | 76,975 |
Beginning Balance, Proved Developed Reserves, Mboe | 32,774 | 33,611 | 25,795 |
Ending Balance, Proved Developed Reserves, Mboe | 45,189 | 32,774 | 33,611 |
Beginning Balance, Proved Undeveloped Reserves, Mboe | 62,705 | 43,365 | 24,920 |
Ending Balance, Proved undeveloped Reserves, Mboe | 69,472 | 62,705 | 43,365 |
Natural Gas (MMcf) [Member] | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' |
Proved Developed and Proved Undeveloped Reserves, Beginning Balance | 174,760 | 178,807 | 150,389 |
Extensions and discoveries | 38,993 | 49,372 | 40,146 |
Purchases of minerals in place | 197 | ' | 24,083 |
Production | -6,737 | -6,089 | -6,345 |
Revisions to previous estimates | -8,789 | -47,330 | -29,466 |
Proved Developed and Proved Undeveloped Reserves, Ending Balance | 216,002 | 174,760 | 178,807 |
Beginning Balance, Proved Developed Reserve, MMcf | 73,178 | 84,743 | 74,739 |
Ending Balance, Proved Developed Reserve, MMcf | 99,742 | 73,178 | 84,743 |
Beginning Balance, Proved Undeveloped Reserves, MMcf | 101,582 | 94,064 | 75,650 |
Ending Balance, Proved Undeveloped Reserves, MMcf | 116,260 | 101,582 | 94,064 |
NGLs (MBbls) [Member] | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' |
Proved Developed and Proved Undeveloped Reserves, Beginning Balance | 29,100 | 29,123 | 20,699 |
Extensions and discoveries | 6,531 | 8,639 | 7,010 |
Purchases of minerals in place | 14 | ' | 4,284 |
Production | -951 | -904 | -798 |
Revisions to previous estimates | -2,102 | -7,758 | -2,072 |
Proved Developed and Proved Undeveloped Reserves, Ending Balance | 32,593 | 29,100 | 29,123 |
Beginning Balance, Proved Developed Reserves, MBbls | 11,761 | 13,945 | 11,193 |
Ending Balance, Proved Developed Reserves, MBbls | 14,919 | 11,761 | 13,945 |
Beginning Balance, Proved Undeveloped Reserves, MBbls | 17,339 | 15,178 | 9,506 |
Ending Balance, Proved Undeveloped Reserves, MBbls | 17,674 | 17,339 | 15,178 |
Oil (MBbls) [Member] | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' |
Proved Developed and Proved Undeveloped Reserves, Beginning Balance | 37,252 | 18,051 | 4,951 |
Beginning Balance, Proved Developed Oil Reserves, MBbls | 8,816 | 5,542 | 2,146 |
Ending Balance, Proved Developed Oil Reserves, MBbls | 13,646 | 8,816 | 5,542 |
Beginning Balance, Proved Undeveloped Oil Reserves, MBbls | 28,436 | 12,509 | 2,805 |
Ending Balance, Proved Undeveloped Oil Reserves, MBbls | 32,421 | 28,436 | 12,509 |
Extensions and discoveries | 14,252 | 21,993 | 11,847 |
Purchases of minerals in place | 62 | ' | 2,200 |
Production | -1,444 | -969 | -482 |
Revisions to previous estimates | -4,055 | -1,823 | -465 |
Proved Developed and Proved Undeveloped Reserves, Ending Balance | 46,067 | 37,252 | 18,051 |
Disclosures_About_Oil_and_Gas_4
Disclosures About Oil and Gas Producing Activities - Additional Information (Detail) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | |
MBoe | MBoe | MBoe | MBoe | |
MMcf | ||||
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Production | 3,500 | 2,900 | 2,400 | ' |
Field fuel | 560 | ' | ' | ' |
Extensions and discoveries | 27,300 | 38,900 | 25,500 | ' |
Downward revisions | 4,700 | 17,500 | 7,500 | ' |
Positive revisions | -4,692 | -17,469 | -7,448 | ' |
Percentage of production attributable to assets | ' | 99.40% | 99.00% | ' |
Extensions and discoveries attributable to Wolfcamp oil shale resource play | ' | ' | 24,200 | ' |
MMBoe of proved reserves | 114,661 | 95,479 | 76,975 | 50,715 |
Upward performance revisions to proved reserves | ' | ' | 300 | ' |
Southeast Project Pangea [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Economic revisions | 7,800 | 8,900 | ' | ' |
Positive revisions | 3,100 | ' | ' | ' |
Working Interest Acquisition [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
MMBoe of proved reserves | ' | ' | 10,500 | ' |
Permian Basin [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Economic revisions | ' | ' | 5,600 | ' |
East Texas Basin [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Economic revisions | ' | ' | 2,200 | ' |
Project Pangea [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Downward revisions | ' | 3,300 | ' | ' |
Natural Gas [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Downward revisions | ' | 2,400 | ' | ' |
Technical Evaluations [Member] | ' | ' | ' | ' |
Reserve Quantities [Line Items] | ' | ' | ' | ' |
Downward revisions | ' | 2,900 | ' | ' |
Disclosures_About_Oil_and_Gas_5
Disclosures About Oil and Gas Producing Activities - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Extractive Industries [Abstract] | ' | ' | ' |
Future cash flows | $5,953,060 | $4,920,231 | $3,772,633 |
Future production costs | -1,372,005 | -1,220,403 | -1,012,044 |
Future development costs | -1,154,685 | -1,025,193 | -625,994 |
Future income tax expense | -919,454 | -692,528 | -583,961 |
Future net cash flows | 2,506,916 | 1,982,107 | 1,550,634 |
10% annual discount for estimated timing of cash flows | -1,830,639 | -1,487,887 | -1,136,253 |
Standardized measure of discounted future net cash flows | $676,227 | $494,220 | $414,381 |
Disclosures_About_Oil_and_Gas_6
Disclosures About Oil and Gas Producing Activities - Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Extractive Industries [Abstract] | ' | ' | ' |
Standardized measure of discounted future net cash flows, Beginning balance | $494,220 | $414,381 | $204,232 |
Net change in sales and transfer prices and in production (lifting) costs related to future production | 74,088 | 147,421 | 334,104 |
Changes in estimated future development costs | -301,132 | -486,435 | -395,037 |
Sales and transfers of oil and gas produced during the period | -149,310 | -100,634 | -89,253 |
Net change due to extensions, discoveries and improved recovery | 360,080 | 467,822 | 291,501 |
Net change due to purchase of minerals in place | 1,435 | ' | 119,780 |
Net change due to revisions in quantity estimates | -61,931 | -210,296 | -84,988 |
Previously estimated development costs incurred during the period | 287,898 | 285,039 | 182,522 |
Accretion of discount | 87,937 | 60,162 | 32,793 |
Other | 1,896 | -11,281 | -38,107 |
Net change in income taxes | -118,904 | -71,959 | -143,166 |
Standardized Measure of discounted future net cash flows | $676,277 | $494,220 | $414,381 |
Supplementary_Data_Selected_Qu
Supplementary Data - Selected Quarterly Financial Data (Detail) (USD $) | 0 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Oct. 31, 2013 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2011 | Sep. 30, 2011 | Jun. 30, 2011 | Mar. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Quarterly Financial Information Disclosure [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net revenue | ' | $58,565 | $44,196 | $42,272 | $36,269 | $35,309 | $33,038 | $29,927 | $30,618 | $31,123 | $27,958 | $29,123 | $20,183 | $181,302 | $128,892 | $108,387 |
Net operating expenses | ' | -40,402 | -34,314 | -31,329 | -31,665 | -36,777 | -31,340 | -26,095 | -23,879 | -42,339 | -19,092 | -18,170 | -17,930 | -137,710 | -118,091 | -97,531 |
Interest expense, net | ' | -5,225 | -5,179 | -2,451 | -1,229 | -926 | -1,544 | -1,380 | -887 | -1,010 | -1,016 | -863 | -513 | -14,084 | -4,737 | -3,402 |
Equity in (losses) earnings of investee | ' | -4 | 340 | -64 | -116 | -108 | ' | ' | ' | ' | ' | ' | ' | 156 | -108 | ' |
Gain on sale of Wildcat pipeline | 90,700 | 90,743 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 90,743 | ' | ' |
Realized gain (loss) on commodity derivatives | ' | 199 | -840 | -714 | 307 | -408 | 423 | 361 | -484 | 1,720 | 1,392 | 66 | 197 | -1,048 | -108 | 3,375 |
Unrealized (loss) gain on commodity derivatives | ' | -1,348 | -3,438 | 4,290 | -4,100 | 1,292 | -4,185 | 9,439 | -2,672 | -4,168 | 1,739 | 2,231 | -149 | -4,596 | 3,874 | -347 |
(Loss) gain on sale of oil and gas properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | -243 | ' | 3 | 488 | ' | ' | 248 |
INCOME BEFORE INCOME TAX PROVISION | ' | 102,528 | 765 | 12,004 | -534 | -1,618 | -3,608 | 12,252 | 2,696 | -14,917 | 10,981 | 12,390 | 2,276 | 114,763 | 9,722 | 10,730 |
Income tax (benefit) provision | ' | 38,207 | 270 | 4,217 | -187 | -781 | -1,253 | 4,390 | 982 | -5,632 | 3,908 | 4,400 | 812 | 42,507 | 3,338 | 3,488 |
NET INCOME | ' | $64,321 | $495 | $7,787 | ($347) | ($837) | ($2,355) | $7,862 | $1,714 | ($9,285) | $7,073 | $7,990 | $1,464 | $72,256 | $6,384 | $7,242 |
Basic net (loss) income applicable to common stockholders per common share | ' | $1.65 | $0.01 | $0.20 | ($0.01) | ($0.02) | ($0.07) | $0.23 | $0.05 | ($0.30) | $0.25 | $0.28 | $0.05 | $1.85 | $0.18 | $0.25 |
Diluted net (loss) income applicable to common stockholders per common share | ' | $1.65 | $0.01 | $0.20 | ($0.01) | ($0.02) | ($0.07) | $0.23 | $0.05 | ($0.30) | $0.25 | $0.28 | $0.05 | $1.85 | $0.18 | $0.25 |