Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Mar. 22, 2016 | Jun. 30, 2015 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | CLAYTON WILLIAMS ENERGY INC /DE | ||
Entity Central Index Key | 880,115 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2015 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $ 387,835,514 | ||
Entity Common Stock, Shares Outstanding | 12,169,536 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 7,780 | $ 28,016 |
Accounts receivable: | ||
Oil and gas sales | 16,660 | 36,526 |
Joint interest and other, net of allowance for doubtful accounts of $2,447 at December 31, 2015 and $1,204 at December 31, 2014 | 3,661 | 14,550 |
Affiliates | 260 | 322 |
Inventory | 31,455 | 42,087 |
Deferred income taxes | 6,526 | 6,911 |
Prepaids and other | 2,463 | 4,208 |
TOTAL CURRENT ASSETS | 68,805 | 132,620 |
PROPERTY AND EQUIPMENT | ||
Oil and gas properties, successful efforts method | 2,585,502 | 2,684,913 |
Pipelines and other midstream facilities | 60,120 | 59,542 |
Contract drilling equipment | 123,876 | 122,751 |
Other | 19,371 | 20,915 |
PROPERTY AND EQUIPMENT, GROSS | 2,788,869 | 2,888,121 |
Less accumulated depreciation, depletion and amortization | (1,587,585) | (1,539,237) |
Property and equipment, net | 1,201,284 | 1,348,884 |
OTHER ASSETS | ||
Debt issue costs, net | 9,629 | 12,712 |
Investments and other | 15,051 | 16,669 |
TOTAL OTHER ASSETS | 24,680 | 29,381 |
Total assets | 1,294,769 | 1,510,885 |
Accounts payable: | ||
Trade | 29,197 | 93,650 |
Oil and gas sales | 19,490 | 41,328 |
Affiliates | 383 | 717 |
Accrued liabilities and other | 16,669 | 20,658 |
TOTAL CURRENT LIABILITIES | 65,739 | 156,353 |
NON-CURRENT LIABILITIES | ||
Long-term debt | 749,759 | 704,696 |
Deferred income taxes | 108,996 | 164,599 |
Asset retirement obligations | 48,728 | 45,697 |
Deferred revenue from volumetric production payment | 5,470 | 23,129 |
Accrued compensation under non-equity award plans | 16,254 | 17,866 |
Other | 225 | 751 |
TOTAL NON-CURRENT LIABILITIES | $ 929,432 | $ 956,738 |
COMMITMENTS AND CONTINGENCIES | ||
STOCKHOLDERS’ EQUITY | ||
Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; none issued | $ 0 | $ 0 |
Common stock, par value $.10 per share, authorized — 30,000,000 shares; issued and outstanding — 12,169,536 shares at December 31, 2015 and December 31, 2014 | 1,216 | 1,216 |
Additional paid-in capital | 152,686 | 152,686 |
Retained earnings | 145,696 | 243,892 |
TOTAL STOCKHOLDERS' EQUITY | 299,598 | 397,794 |
Total liabilities and equity | $ 1,294,769 | $ 1,510,885 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value (in dollars per share) | $ 0.10 | $ 0.10 |
Preferred stock, authorized shares | 3,000,000 | 3,000,000 |
Preferred stock, issued shares | 0 | 0 |
Common stock, par value (in dollars per share) | $ 0.10 | $ 0.10 |
Common stock, authorized shares | 30,000,000 | 30,000,000 |
Common stock, issued shares | 12,169,536 | 12,169,536 |
Common stock, outstanding shares | 12,169,536 | 12,169,536 |
Allowance for doubtful accounts | $ 2,447 | $ 1,204 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
REVENUES | |||
Oil and gas sales | $ 217,485 | $ 418,330 | $ 399,950 |
Midstream services | 6,122 | 6,705 | 4,965 |
Drilling rig services | 23 | 28,028 | 17,812 |
Other operating revenues | 8,742 | 15,393 | 6,488 |
Total revenues | 232,372 | 468,456 | 429,215 |
COSTS AND EXPENSES | |||
Production | 87,557 | 105,296 | 108,405 |
Exploration: | |||
Abandonments and impairments | 6,509 | 20,647 | 5,887 |
Seismic and other | 1,318 | 2,314 | 3,906 |
Midstream services | 1,688 | 2,212 | 1,816 |
Drilling rig services | 5,238 | 19,232 | 16,290 |
Depreciation, depletion and amortization | 162,262 | 154,356 | 150,902 |
Impairment of property and equipment | 41,917 | 12,027 | 89,811 |
Accretion of asset retirement obligations | 3,945 | 3,662 | 4,203 |
General and administrative | 22,788 | 34,524 | 33,279 |
Other operating expenses | 12,585 | 2,547 | 2,101 |
Total costs and expenses | 345,807 | 356,817 | 416,600 |
Operating income (loss) | (113,435) | 111,639 | 12,615 |
OTHER INCOME (EXPENSE) | |||
Interest expense | (54,422) | (50,907) | (43,079) |
Gain (loss) on derivatives | 12,519 | 4,789 | (8,731) |
Other | 2,003 | 3,047 | 1,905 |
Total other income (expense) | (39,900) | (43,071) | (49,905) |
Income (loss) before income taxes | (153,335) | 68,568 | (37,290) |
Income tax (expense) benefit | 55,139 | (24,687) | 12,428 |
NET INCOME (LOSS) | $ (98,196) | $ 43,881 | $ (24,862) |
Net income (loss) per common share: | |||
Basic (in dollars per share) | $ (8.07) | $ 3.61 | $ (2.04) |
Diluted (in dollars per share) | $ (8.07) | $ 3.61 | $ (2.04) |
Weighted average common shares outstanding: | |||
Basic (in shares) | 12,170 | 12,167 | 12,165 |
Diluted (in shares) | 12,170 | 12,167 | 12,165 |
CONSOLIDATED STATEMENT OF STOCK
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock | Additional Paid-In Capital | Retained Earnings |
BALANCE at Dec. 31, 2012 | $ 378,616 | $ 1,216 | $ 152,527 | $ 224,873 |
BALANCE (in shares) at Dec. 31, 2012 | 12,165 | |||
Increase (Decrease) in Stockholders' Equity | ||||
Net income (loss) | (24,862) | $ 0 | 0 | (24,862) |
Issuance of stock through compensation plans, including income tax benefits, shares | 1 | |||
Issuance of stock through compensation plans, including income tax benefits, Value | 29 | $ 0 | 29 | 0 |
BALANCE at Dec. 31, 2013 | 353,783 | $ 1,216 | 152,556 | 200,011 |
BALANCE (in shares) at Dec. 31, 2013 | 12,166 | |||
Increase (Decrease) in Stockholders' Equity | ||||
Net income (loss) | 43,881 | $ 0 | 0 | 43,881 |
Issuance of stock through compensation plans, including income tax benefits, shares | 4 | |||
Issuance of stock through compensation plans, including income tax benefits, Value | 130 | $ 0 | 130 | 0 |
BALANCE at Dec. 31, 2014 | 397,794 | $ 1,216 | 152,686 | 243,892 |
BALANCE (in shares) at Dec. 31, 2014 | 12,170 | |||
Increase (Decrease) in Stockholders' Equity | ||||
Net income (loss) | (98,196) | $ 0 | 0 | (98,196) |
BALANCE at Dec. 31, 2015 | $ 299,598 | $ 1,216 | $ 152,686 | $ 145,696 |
BALANCE (in shares) at Dec. 31, 2015 | 12,170 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net income (loss) | $ (98,196) | $ 43,881 | $ (24,862) |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | |||
Depreciation, depletion and amortization | 162,262 | 154,356 | 150,902 |
Impairment of property and equipment | 41,917 | 12,027 | 89,811 |
Abandonments and impairments | 6,509 | 20,647 | 5,887 |
(Gain) loss on sales of assets and impairment of inventory, net | 3,018 | (9,138) | (3,024) |
Deferred income tax expense (benefit) | (55,218) | 24,460 | (14,042) |
Non-cash employee compensation | (2,674) | 1,397 | (3,493) |
(Gain) loss on derivatives | (12,519) | (4,789) | 8,731 |
Cash settlements of derivatives | 12,519 | 7,099 | 690 |
Accretion of asset retirement obligations | 3,945 | 3,662 | 4,203 |
Amortization of debt issue costs and original issue discount | 3,246 | 3,030 | 3,266 |
Amortization of deferred revenue from volumetric production payment | (6,822) | (7,708) | (8,746) |
Other | 1,542 | 0 | 0 |
Changes in operating working capital: | |||
Accounts receivable | 30,817 | 5,255 | (7,163) |
Accounts payable | (35,860) | 4,561 | 12,740 |
Other | (2,327) | (619) | 5,676 |
Net cash provided by operating activities | 52,159 | 258,121 | 220,576 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Additions to property and equipment | (179,827) | (422,473) | (288,133) |
Proceeds from volumetric production payment | 2,866 | 1,067 | 1,332 |
Termination of volumetric production payment | (13,703) | 0 | 0 |
Proceeds from sales of assets | 71,460 | 104,529 | 259,799 |
(Increase) decrease in equipment inventory | 1,733 | (1,886) | (726) |
Other | 76 | (234) | (1,315) |
Net cash used in investing activities | (117,395) | (318,997) | (29,043) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Proceeds from long-term debt | 45,000 | 102,139 | 268,335 |
Repayments of long-term debt | 0 | (40,000) | (444,000) |
Proceeds from exercise of stock options | 0 | 130 | 29 |
Net cash provided by (used in) financing activities | 45,000 | 62,269 | (175,636) |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (20,236) | 1,393 | 15,897 |
CASH AND CASH EQUIVALENTS | |||
Beginning of period | 28,016 | 26,623 | 10,726 |
End of period | 7,780 | 28,016 | 26,623 |
SUPPLEMENTAL DISCLOSURES | |||
Cash paid for interest, net of amounts capitalized | 51,293 | 47,817 | 35,219 |
Cash paid for income taxes | $ 0 | $ 1,600 | $ 0 |
Nature of Operations
Nature of Operations | 12 Months Ended |
Dec. 31, 2015 | |
Nature of Operations Disclosures [Abstract] | |
Nature of Operations | Nature of Operations Clayton Williams Energy, Inc. a Delaware corporation, is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas and New Mexico. Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to “the Company,” “we,” “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries. Approximately 25.5% of CWEI’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners, and Mel G. Riggs, our President, is the sole general partner. Substantially all of our oil and gas production is sold under short-term contracts which are market-sensitive. Accordingly, our results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global supply and demand for oil and natural gas, market uncertainties, weather conditions, domestic governmental regulations and taxes, political and economic conditions in oil producing countries, price and availability of alternative fuels and overall domestic and foreign economic conditions. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Estimates and Assumptions The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows: • Provisions for depreciation, depletion and amortization and estimates of non-equity plans are based on estimates of proved reserves; • Impairments of long-lived assets are based on estimates of future net cash flows and, when applicable, the estimated fair values of impaired assets; • Exploration expenses related to impairments of unproved acreage are based on estimates of fair values of the underlying leases; • Asset retirement obligations (“ARO”) are based on estimates regarding the timing and cost of future asset retirements; • Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory; and • Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells. Principles of Consolidation The consolidated financial statements include the accounts of CWEI and its wholly owned subsidiaries. We account for our undivided interests in oil and gas limited partnerships using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of such limited partnerships. Less than 5% of our consolidated total assets and total revenues are derived from oil and gas limited partnerships. Substantially all intercompany transactions and balances associated with the consolidated operations have been eliminated. Oil and Gas Properties We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned. Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties. Pipelines and Other Midstream Facilities and Other Property and Equipment Pipelines and other midstream facilities consist of pipelines to transport oil, natural gas and water, natural gas processing facilities and compressors. Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles. Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred. The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income (loss) in the accompanying consolidated statements of operations and comprehensive income (loss). Depreciation of pipelines and other midstream facilities and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 30 years. Contract Drilling We conduct contract drilling operations through Desta Drilling, a wholly owned subsidiary of CWEI. Desta Drilling recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable. Property and equipment, including buildings, major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 40 years. Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized. Valuation of Property and Equipment Our long-lived assets, including proved oil and gas properties and contract drilling equipment, are assessed for potential impairment in their carrying values, based on depletable groupings, whenever events or changes in circumstances indicate such impairment may have occurred. An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the difference in the carrying value and estimated fair value of the impaired asset. Unproved oil and gas properties are periodically assessed, and any impairment in value is charged to exploration costs. The amount of impairment recognized on unproved properties which are not individually significant is determined by impairing the costs of such properties within appropriate groups based on our historical experience, acquisition dates and average lease terms. The valuation of unproved properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. Asset Retirement Obligations We recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost associated with the asset retirement obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization. Income Taxes We utilize the asset and liability method to account for income taxes. Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the consolidated statements of operations and comprehensive income (loss) in the period that includes the enactment date. We also record any financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense. Hedging Transactions From time to time, we utilize derivative instruments, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. All of our derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a derivative depends on both the intended purpose and the formal designation of the derivative. Designation is established at the inception of a derivative, but subsequent changes to the designation are permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines under applicable accounting standards, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in fair value of derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines are recorded in earnings as the changes occur. If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production is sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period. Actual gains or losses from derivatives not designated as cash flow hedges are recorded in other income (expense) as gain (loss) on derivatives. Inventory Inventory consists primarily of tubular goods and other well equipment which we plan to utilize in our exploration and development activities and is stated at the lower of average cost or estimated market value. Capitalization of Interest Interest costs associated with our inventory of unproved oil and gas property lease acquisition costs are capitalized during the periods for which exploration activities are in progress. During the years ended December 31, 2015 , 2014 and 2013 , we capitalized interest totaling approximately $0.3 million , $1 million and $1.4 million , respectively. Cash and Cash Equivalents We consider all cash and highly liquid investments with original maturities of three months or less to be cash equivalents. Net Income (Loss) Per Common Share Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of Common Shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted net income (loss) per share calculations for 2015 , 2014 and 2013 include changes in potential shares attributable to dilutive stock options. Fair Value Measurements We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows: Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 3 - Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Revenue Recognition and Gas Balancing We utilize the sales method of accounting for oil, natural gas and natural gas liquids (“NGL”) revenues whereby revenues, net of royalties, are recognized as the production is sold to purchasers. The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties. We did not have any significant gas imbalance positions at December 31, 2015 , 2014 or 2013 . Revenues from midstream services and drilling rig services are recognized as services are provided. Comprehensive Income (Loss) There were no differences between net income (loss) and comprehensive income (loss) in 2015 , 2014 and 2013 . Concentration Risks We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. When management deems appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. Allowances for doubtful accounts at December 31, 2015 and 2014 relate to amounts due from joint interest owners. Recent Accounting Pronouncements In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842).” The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases). Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted. ASU 2016-02 must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transaction will require application of the new guidance at the beginning of the earliest comparative period presented. We are evaluating the impact that this new guidance will have on our consolidated financial statements. In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes.” This ASU requires that deferred tax assets and liabilities be classified as noncurrent on the balance sheet. The standard will be effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption will be permitted as of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. Adoption of the new guidance will affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements. In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively, with early adoption permitted. The adoption of this standard will not have a material impact on our consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items (that is, debt issuance cost asset and the debt liability). We currently present debt issuance costs on the balance sheet as an asset. As of December 31, 2015 , we had $9.6 million of debt issuance costs, which under this standard would be reclassified from an asset to a direct deduction to the related debt liability. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Long-term debt consists of the following: December 31, December 31, (In thousands) 7.75% Senior Notes due 2019, net of unamortized original issue discount of $241 at December 31, 2015 and $304 at December 31, 2014 $ 599,759 $ 599,696 Revolving credit facility, due April 2019 (a) 150,000 105,000 $ 749,759 $ 704,696 ______ (a) Renewed and extended in April 2014. Senior Notes In March 2011, we issued $300 million of aggregate principal amount of 7.75% Senior Notes due 2019 (the “2019 Senior Notes”). The 2019 Senior Notes, which are unsecured, were issued at par and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year. In April 2011, we issued an additional $50 million aggregate principal amount of the 2019 Senior Notes with an original issue discount of 1% or $0.5 million . In October 2013, we issued an additional $250 million of aggregate principal amount of the 2019 Senior Notes at par to yield 7.75% to maturity. All of the 2019 Senior Notes are treated as a single class of debt securities under the same indenture. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 101.938% beginning on April 1, 2016 and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest. The Indenture contains covenants that restrict our ability to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business. One such covenant provides that, with certain exceptions, we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) exceeds 2.25 times. While we met this ratio as of December 31, 2015 , if we do not meet this ratio in the future, in order to borrow under our revolving credit facility or make other borrowings, we expect to rely primarily on a covenant provision permitting the incurrence of indebtedness under a Credit Facility (as defined in the Indenture) in an aggregate principal amount at any time outstanding not to exceed the greater of (a) $500 million and (b) 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture). These covenants are subject to a number of additional important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at December 31, 2015 and December 31, 2014 . Revolving Credit Facility We currently borrow money under a revolving credit facility with a syndicate of 16 banks led by JP Morgan Chase Bank, N.A. On March 8, 2016 , we entered into an amendment to the revolving credit facility in connection with the Refinancing (see “ — Term Loan Credit Facility” ). The amendment, among other things, reduced the borrowing base and aggregate commitments of the lenders from $450 million to $100 million . The aggregate commitments may be increased to $150 million if we meet a minimum ratio of the discounted present value of our proved developed producing reserves to our debt under the revolving credit facility of 1.2 to 1.0 . Increases in aggregate lender commitments require the consent of each lender. The amendment also increased the applicable interest rates under our revolving credit facility by 0.75% at every borrowing base utilization level. At our election, interest under the revolving credit facility is determined by reference to (1) LIBOR plus an applicable margin between 2.5% and 3.5% per year or (2) the greatest of (A) the prime rate, (B) the federal funds rate plus 0.5% or (C) one-month LIBOR plus 1% plus, in any of (A), (B) or (C), an applicable margin between 1.5% and 2.5% per year. We are also required to pay a commitment fee on the unused portion of the commitments under the revolving credit facility of 0.5% per year. The applicable margin is determined based on the utilization of the borrowing base. Interest and fees are payable quarterly, except that interest on LIBOR-based tranches is due at maturity of each tranche but no less frequently than quarterly. The revolving credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1 . The March 2016 amendment replaced a requirement that we maintain certain ratios of consolidated funded indebtedness to consolidated EBITDAX with a less restrictive ratio of debt outstanding solely under the revolving credit facility to consolidated EBITDAX of 2.0 to 1.0 . The revolving credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the revolving credit facility prior to October 1, 2018 . The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency, (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest, or (4) take any combination of options (1) through (3). The revolving credit facility is collateralized by a first lien on substantially all of our assets, including at least 90% of the adjusted engineered value (as defined in the revolving credit facility) attributed to our proved oil and gas interests evaluated in determining the borrowing base. The obligations under the revolving credit facility are guaranteed by each of CWEI’s material restricted domestic subsidiaries. At December 31, 2015 , we had $150 million of borrowings outstanding on the revolving credit facility, leaving $298.1 million available after allowing for outstanding letters of credit totaling $1.9 million . The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2015 was 2.2% . We were in compliance with all financial and non-financial covenants at December 31, 2015 and December 31, 2014 . The failure to comply with the foregoing covenants will constitute an event of default (subject, in the case of certain covenants, to applicable notice and/or cure periods) under the revolving credit facility. Other events of default under the revolving credit facility include, among other things, (1) the failure to timely pay principal, interest, fees or other amounts due and owing, (2) the inaccuracy of representations or warranties in any material respect, (3) the occurrence of certain bankruptcy or insolvency events, and (4) the loss of lien perfection or priority. The occurrence and continuance of an event of default could result in, among other things, acceleration of all amounts outstanding. Term Loan Credit Facility On March 8, 2016 , we entered into the term loan credit facility with funds managed by Ares Management, LLC (“Ares”) providing for the lenders to make secured term loans to us in the principal amount of $350 million (the “Refinancing”). The Refinancing also provided for us to issue to the lenders warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share and required certain amendments to the revolving credit facility. The Refinancing closed on March 15, 2016. Aggregate cash proceeds from the Refinancing of approximately $340 million , net of transaction costs, were used to fully repay the then-outstanding balance on the revolving credit facility of $160 million , plus accrued interest and fees, and added approximately $180 million of cash to our balance sheet to provide a dedicated source of liquidity to fund our operations and development. The term loans were issued at an original issue discount of $16.8 million , which amount equaled the cash value received by us for the issuance of the related warrants and shares of special voting preferred stock. Interest on the term loans is payable quarterly in cash at 12.5% per year; however, during the period from March 15, 2016 through March 31, 2018 , we may elect to pay interest for any quarter in kind at 15% per year. We have agreed in advance to pay interest for the period commencing from March 15, 2016 and ending March 31, 2016 in cash, and have elected to pay interest for the quarterly period ending June 30, 2016 in kind. The term loan credit facility matures on March 15, 2021 , but is subject to an earlier maturity on December 31, 2018 , if we do not extend or refinance our existing 2019 Senior Notes on or prior to that date. The term loan credit facility is collateralized by a second lien on substantially all of our assets, including at least 90% of the adjusted engineered value (as defined in the term loan credit facility) attributed to our proved oil and gas interests. The obligations under the term loan credit facility are guaranteed by each of CWEI’s material restricted domestic subsidiaries. Optional and mandatory prepayments made prior to September 15, 2020 are subject to make-whole or prepayment premiums. The term loan credit facility also contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain an asset-to-secured debt coverage ratio as of each December 31 and June 30 of each year, beginning with December 31, 2018 , of at least 1.2 to 1.0 . The failure to comply with these covenants will constitute an event of default (subject, in the case of certain covenants, to applicable notice and/or cure periods) under the term loan credit facility. Other events of default under the term loan credit facility include, among other things, (1) the failure to timely pay principal, interest, fees or other amounts due and owing, (2) the inaccuracy of representations or warranties in any material respect, (3) the occurrence of certain bankruptcy or insolvency events, and (4) the loss of lien perfection or priority. The occurrence and continuance of an event of default could result in, among other things, acceleration of all amounts outstanding. |
Sales of Assets
Sales of Assets | 12 Months Ended |
Dec. 31, 2015 | |
Sale Of Assets [Abstract] | |
Sales of Assets | Sales of Assets In December 2015, we sold certain acreage in Burleson County, Texas for cash consideration of $21.8 million . This acreage, located east of our contiguous acreage block, was sold under a three -year term assignment that may be extended beyond the stated term as long as the buyer maintains a 180-day continuous development program on the acreage. We retained our rights to all depths and formations other than the Eagle Ford formation and also retained our interest in acreage and production in all wells currently situated on the acreage. We also reserved an overriding royalty interest to the extent the net revenue interest of any assigned lease exceeds 75% . Prior to December 2015, we successfully closed several asset sales. In September 2015, we sold our interests in selected leases and wells in South Louisiana for $11.8 million subject to customary closing adjustments. In June 2015, we sold certain acreage in Burleson County, Texas for cash consideration of $22.1 million . We retained our rights to all depths and formations other than the Eagle Ford formation and also retained our interest in acreage and production associated with the Porter E Unit #1, our only Eagle Ford well situated on this acreage, a reversionary interest in acreage if the buyer fails to maintain a continuous development program and an overriding royalty interest in leases to the extent the net revenue interest exceeds 75% . During the first half of 2015, we sold our interests in selected leases in Oklahoma and sold our interests in certain wells in Martin and Yoakum Counties, Texas for proceeds totaling $7.3 million . In September 2014, we sold our interests in approximately 7,500 net acres in the Delaware Basin in Ward and Winkler Counties, Texas to an unaffiliated third party for $29.3 million . In March 2014, we closed a transaction to sell our interests in selected wells and leases in Wilson, Brazos, La Salle, Frio and Robertson Counties, Texas for $71 million , subject to customary closing adjustments. At closing, $6.8 million of the total proceeds was placed in escrow pending resolution of certain title requirements. In May 2015, the title requirements were satisfied and the remaining proceeds were released. In February 2014, we sold a property in Ward County, Texas for $5.1 million , subject to customary closing adjustments. Net proceeds from each of these transactions were applied to reduce indebtedness outstanding under the revolving credit facility. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations We record the ARO associated with the retirement of our long-lived assets in the period in which they are incurred and become determinable. Under this method, we record a liability for the expected future cash outflows discounted at our credit-adjusted risk-free interest rate for the dismantlement and abandonment costs, excluding salvage values, of each oil and gas property. We also record an asset retirement cost to the oil and gas properties equal to the ARO liability. The fair value of the asset retirement cost and the ARO liability is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset. The following table reflects the changes in ARO for the years ended December 31, 2015 and December 31, 2014 : 2015 2014 (In thousands) Beginning of year $ 45,697 $ 49,981 Additional ARO from new properties 469 1,209 Sales or abandonments of properties (4,435 ) (5,246 ) Accretion expense 3,945 3,662 Revisions of previous estimates 3,052 (3,909 ) End of year $ 48,728 $ 45,697 |
Deferred Revenue from Volumetri
Deferred Revenue from Volumetric Production Payment | 12 Months Ended |
Dec. 31, 2015 | |
Deferred Revenue Disclosure [Abstract] | |
Deferred Revenue from Volumetric Production Payment | Deferred Revenue from Volumetric Production Payment In March 2012, Southwest Royalties, Inc. (“SWR”), a wholly owned subsidiary of CWEI, completed the mergers of each of the 24 limited partnerships of which SWR was the general partner, into SWR, with SWR continuing as the surviving entity in the mergers. To obtain the funds to finance the aggregate merger consideration, SWR entered into a volumetric production payment (“VPP”) with a third party for upfront cash proceeds of $44.4 million and deferred future advances aggregating $4.7 million . Under the terms of the VPP, SWR conveyed to the third party a term overriding royalty interest covering approximately 725 MBOE of estimated future oil and gas production from certain properties derived from the mergers. The scheduled volumes under the VPP relate to production months from March 2012 through December 2019 and were to be delivered to, or sold on behalf of, the third party free of all costs associated with the production and development of the underlying properties. Once the scheduled volumes were delivered to the third party, the term overriding royalty interest would terminate. SWR retained the obligation to prudently operate and produce the properties during the term of the VPP, and the third party assumed all risks associated with product prices. As a result, the VPP was accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes were produced. The net proceeds from the VPP were recorded as a non-current liability in the consolidated balance sheets. Deferred revenue from the VPP was amortized over the life of the VPP and recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). In August 2015, we terminated the VPP covering 277 MBOE of oil and gas production from August 2015 through December 2019 for $13.7 million . The termination of the VPP was accounted for as a repurchase of reserves, with the repurchase price offsetting the non-current liability and the balance of the remaining non-current liability amortized over the original term of the VPP and recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). As of December 31, 2015 , we have no further obligations under the VPP. The following table reflects the changes in deferred revenue during the years ended December 31, 2015 and December 31, 2014 : 2015 2014 (In thousands) Beginning of year $ 23,129 $ 29,770 Deferred revenue from VPP 2,866 1,067 Amortization of deferred revenue from VPP (6,822 ) (7,708 ) Termination of VPP (13,703 ) — End of year $ 5,470 $ 23,129 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Deferred tax assets and liabilities are the result of temporary differences between the consolidated financial statement carrying values and the tax basis of assets and liabilities. Significant components of net deferred tax liabilities at December 31, 2015 and 2014 are as follows: 2015 2014 (In thousands) Deferred tax assets: Net operating loss carryforwards $ 106,992 $ 84,587 Statutory depletion carryforwards 9,809 9,581 Asset retirement obligations and other 21,249 19,061 138,050 113,229 Deferred tax liabilities: Property and equipment (240,520 ) (270,917 ) Net deferred tax liabilities $ (102,470 ) $ (157,688 ) Components of net deferred tax liabilities: Current assets $ 6,526 $ 6,911 Non-current liabilities (108,996 ) (164,599 ) Net deferred tax liabilities $ (102,470 ) $ (157,688 ) For the years ended December 31, 2015 , 2014 and 2013 , effective income tax rates were different than the statutory federal income tax rates for the following reasons: 2015 2014 2013 (In thousands) Income tax expense (benefit) at statutory rate of 35% $ (53,667 ) $ 23,999 $ (13,052 ) Tax depletion in excess of basis (282 ) (729 ) (518 ) Revision of previous tax estimates 30 (155 ) 373 State income tax expense (benefit), net of federal tax effect (1,472 ) 1,008 76 Other 252 564 693 Income tax expense (benefit) $ (55,139 ) $ 24,687 $ (12,428 ) Current $ 79 $ 227 $ 1,614 Deferred (55,218 ) 24,460 (14,042 ) Income tax expense (benefit) $ (55,139 ) $ 24,687 $ (12,428 ) We derive a tax deduction when options are exercised under our stock option plans. To the extent these tax deductions are used to reduce currently payable taxes in any period, we record a tax benefit for the excess of the tax deduction over cumulative book compensation expense as additional paid-in capital and as a financing cash flow in the accompanying consolidated financial statements. At December 31, 2015 , our cumulative tax loss carryforwards were approximately $327.2 million , of which $22 million relates to excess tax benefits from exercise of stock options. The cumulative tax loss carryforwards are scheduled to expire if not utilized between 2026 and 2030 . In assessing the ability to realize deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. If it is more likely than not that some portion or all of the assets will not be realized, the assets are reduced by a valuation allowance. Based on our analysis of future taxable income, no valuation allowance is required. CWEI and its subsidiaries file federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions. As a general rule, the Company’s tax returns for fiscal years after 2011 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time. We do not have any uncertain tax positions as of December 31, 2015 and 2014 . |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | Derivatives Commodity Derivatives From time to time, we utilize commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. When using swaps to hedge oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract, generally New York Mercantile Exchange (“NYMEX”) futures prices, resulting in a net amount due to or from the counterparty. In floor transactions, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract production periods mature. The following summarizes information concerning our net positions in open commodity derivatives, all of which were entered into in January 2016 and March 2016 , applicable to periods subsequent to December 31, 2015 . In addition, we granted an option on an additional 739 MBbls of oil production from July 2016 through December 2016 at $40.25 per barrel exercisable by the counterparty by June 30, 2016 . Settlement prices of commodity derivatives are based on NYMEX futures prices. Current Swaps: Oil MBbls Price Production Period: 1st Quarter 2016 421 $ 40.25 2nd Quarter 2016 518 $ 40.47 3rd Quarter 2016 176 $ 42.70 4th Quarter 2016 167 $ 42.70 2017 315 $ 44.30 1,597 Swaps Subject to Optional Extension: Oil MBbls Price Production Period: 3rd Quarter 2016 378 $ 40.25 4th Quarter 2016 361 $ 40.25 739 Accounting for Derivatives We did not designate any of our commodity derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, were recorded as other income (expense) in our consolidated statements of operations and comprehensive income (loss). Effect of Derivative Instruments on the Consolidated Balance Sheets We had no outstanding derivative positions at December 31, 2015 and December 31, 2014 . Our derivative contracts entered into in January 2016 and March 2016 are with JPMorgan Chase Bank, N.A. Effect of Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Income (Loss) Amount of Gain or (Loss) Recognized in Earnings Year Ended December 31, Location of Gain or (Loss) Recognized in Earnings 2015 2014 2013 (In thousands) Derivatives not designated as hedging instruments: Commodity derivatives: Other income (expense) - Gain (loss) on derivatives $ 12,519 $ 4,789 $ (8,731 ) Total $ 12,519 $ 4,789 $ (8,731 ) |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | Fair Value of Financial Instruments Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under the credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive. Fair Value of Other Financial Instruments We estimate the fair value of the 2019 Senior Notes using quoted market prices (Level 1 inputs). Fair value is compared to the carrying value in the table below: December 31, 2015 December 31, 2014 Carrying Estimated Carrying Estimated Description Amount Fair Value Amount Fair Value (In thousands) 7.75% Senior Notes due 2019 $ 599,759 $ 462,750 $ 599,696 $ 510,000 |
Compensation Plans
Compensation Plans | 12 Months Ended |
Dec. 31, 2015 | |
Compensation Plans [Abstract] | |
Compensation Plans | Compensation Plans Stock-Based Compensation Initially, we reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (the “Directors Plan”). Since the inception of the Directors Plan, CWEI issued options covering 52,000 shares of common stock at option prices ranging from $3.25 to $41.74 per share. All options expired ten years from the grant date, were fully exercisable upon issuance and were all exercised as of December 2014. In December 2009, the Board reduced the number of shares available for issuance under the Directors Plan to a level sufficient to cover only the remaining outstanding shares at that time. The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2015 , 2014 and 2013 . 2015 2014 2013 (In thousands, except per share) Weighted average grant date fair value of options granted per share $ — $ — $ — Intrinsic value of options exercised $ — $ 263 $ 53 Non-Equity Award Plans The Compensation Committee of the Board has adopted an after-payout (“APO”) incentive plan (the “APO Incentive Plan”) for officers, key employees and consultants who promote our drilling and acquisition programs. The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO interest in the production developed, directly or indirectly, through the efforts of the participants. The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes (the “APO Partnerships”), between us and the participants, to which we contribute a portion of our economic interest in wells drilled or acquired within certain areas. Generally, we pay all costs to acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest (“payout”). At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the economic interests that are subject to the APO Partnerships. Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO Incentive Plan. We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements. Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan. The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”) which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations. The wells subject to an APO Reward Plan are not included in the APO Incentive Plan. Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan. To date, we have granted awards under the APO Reward Plan in 15 specified areas, each of which established a quarterly bonus amount equal to 7% or 10% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each plan, which dates range from January 1, 2007 to June 11, 2014. Of these 15 awards, 12 awards are fully vested and three will fully vest on June 23, 2016. In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the APO cash flow from a 22.50% working interest in one well. The plan is fully vested and 100% of subsequent quarterly bonus amounts are payable to participants. To continue as a participant in the APO Reward Plan or the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date established for each award. The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents. We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and the SWR Reward Plan is recognized over the applicable vesting periods, which range from two years to five years . Compensation expense related to non-equity award plans was $(0.03) million in 2015 , $4.6 million in 2014 and $2.1 million in 2013 . Accrued compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule: December 31, December 31, (In thousands) Current liabilities: Accrued liabilities and other $ 1,251 $ 2,317 Non-current liabilities: Accrued compensation under non-equity award plans 16,254 17,866 Total accrued compensation under non-equity award plans $ 17,505 $ 20,183 |
Transactions with Affiliates
Transactions with Affiliates | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Transactions with Affiliates | Transactions with Affiliates The Company and other entities (the “Williams Entities”) controlled by Mr. Williams are parties to an agreement (the “Service Agreement”) pursuant to which the Company furnishes services to, and receives services from, such entities. Under the Service Agreement, as amended from time to time, CWEI provides legal, computer, payroll and benefits administration, insurance administration, tax preparation services, tax planning services, and financial and accounting services to the Williams Entities, as well as technical services with respect to certain oil and gas properties owned by the Williams Entities. The Williams Entities provide business entertainment to or for the benefit of CWEI. The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2015 , 2014 and 2013 . 2015 2014 2013 (In thousands) Amounts received from the Williams Entities: Service Agreement: Services $ 622 $ 663 $ 715 Insurance premiums and benefits 922 960 837 Reimbursed expenses 500 296 427 $ 2,044 $ 1,919 $ 1,979 Amounts paid to the Williams Entities: Rent (a) $ 1,741 $ 1,614 $ 1,560 Service Agreement: Business entertainment (b) 155 205 344 Reimbursed expenses 226 204 216 $ 2,122 $ 2,023 $ 2,120 ______ (a) Rent amounts were paid to a partnership within the Williams Entities. The Company owns 31.9% of the partnership and affiliates of the Company own 25.8% . (b) Consists primarily of hunting and fishing recreation for business associates and employees of the Company on land owned by affiliates of Mr. Williams. Accounts receivable from affiliates and accounts payable to affiliates include, among other things, amounts for customary charges by the Company as operator of certain wells in which affiliates own an interest. |
Other Operating Revenues and Ex
Other Operating Revenues and Expenses | 12 Months Ended |
Dec. 31, 2015 | |
Other Income and Expenses [Abstract] | |
Other Operating Revenues and Expenses | Other Operating Revenues and Expenses Other operating revenues and expenses for the years ended December 31, 2015 , 2014 and 2013 are as follows: 2015 2014 2013 (In thousands) Other operating revenues: Gain on sales of assets $ 8,718 $ 11,685 $ 4,467 Marketing revenue 24 3,708 2,021 Total other operating revenues $ 8,742 $ 15,393 $ 6,488 Other operating expenses: Loss on sales of assets $ 1,355 $ 2,511 $ 1,233 Marketing expense 849 — 658 Impairment of inventory 10,381 36 210 Total other operating expenses $ 12,585 $ 2,547 $ 2,101 Gain on sales of assets for the year ended December 31, 2015 included the sale of selected leases and wells in South Louisiana in September 2015, the release of sales proceeds previously held in escrow pending resolution of title requirements associated with the sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014, the sale of leases in Oklahoma in May and June 2015 and the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015 (see Note 4). Gain on sales of assets for the year ended December 31, 2014 included the sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014, the sale of a property in Ward County, Texas in February 2014, and the sale of a portion of our Andrews County Wolfberry assets in April 2013 (see Note 4). We maintain an inventory of tubular goods and other well equipment for use in our exploration and development drilling activities. Inventory is carried at the lower of average cost or estimated fair market value. We categorize the measurement of fair value of inventory as Level 2 under applicable accounting standards. To determine estimated fair value of inventory, we subscribe to market surveys and obtain quotes from equipment dealers for similar equipment. We then correlate the data as needed to estimate the fair value of the specific items (or groups of similar items) in our inventory. If the estimated fair values for those specific items (or groups of similar items) in our inventory are less than the related average cost, a provision for impairment is made. |
Investment in Dalea Investment
Investment in Dalea Investment Group, LLC | 12 Months Ended |
Dec. 31, 2015 | |
Investments, All Other Investments [Abstract] | |
Investment in Dalea Investment Group, LLC | Investment in Dalea Investment Group, LLC In June 2012, we cancelled an $11 million note receivable in exchange for a 7.66% non-controlling membership interest in Dalea Investment Group, LLC (“Dalea”), an international oilfield services company formed in March 2012. Since the membership interests in Dalea are privately-held and are not traded in an active market, our investment in Dalea was carried at cost of $11 million . As of December 31, 2015 , we have performed a qualitative assessment based on the difference between the carrying value and the estimated fair value of our investment. We estimated the fair value of our investment by comparing our interest of the equity in Dalea to our carrying value at December 31, 2015 and December 31, 2014 . In comparing the estimated fair value to our carrying value at December 31, 2015 , we recorded a $2.6 million impairment on our investment in Dalea for the year ended December 31, 2015 and none for the years ended December 31, 2014 and 2013 . As of December 31, 2015 , our investment in Dalea was carried at $8.4 million compared to $11 million at December 31, 2014 . We categorize the measurement of fair value of this investment as a Level 3 input. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Leases We lease office space from affiliates and nonaffiliates under noncancelable operating leases. Rental expense pursuant to the office leases amounted to $1.9 million , $1.8 million and $1.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Future minimum payments under noncancelable leases at December 31, 2015 are as follows: Leases Capital (a) Operating (b) Total (In thousands) 2016 $ 601 $ 3,744 $ 4,345 2017 180 924 1,104 2018 18 676 694 Thereafter — 740 740 Total minimum lease payments $ 799 $ 6,084 $ 6,883 ______ (a) Relates to vehicle leases. (b) Includes leases for two drilling rigs. Legal Proceedings SWR is a defendant in a suit filed in April 2011 in the Circuit Court of Union County, Arkansas where the plaintiffs initially sought in excess of $8 million for the costs of environmental remediation to a lease on which operations were commenced in the 1930s. In June 2013, the plaintiffs, SWR and the remaining defendants agreed to a settlement of $0.8 million , of which SWR would pay $0.7 million . To accomplish the settlement, the case was converted to a class action, and each member of the class was offered the right to either participate or opt out of the class and continue a separate action for damages. One plaintiff opted out and will be subject to all previous rulings of the court, including an order dismissing certain claims on the basis that such claims were time barred. A loss on settlement of $0.7 million was recorded for the year ended December 31, 2013 in connection with this proposed settlement. The settlement was entered by the Court on December 19, 2014, and all settlement funds were paid to plaintiffs’ counsel in January 2015. The case by the single remaining plaintiff continues. In February 2012, BMT O&G TX, L.P. filed a suit in the 143rd Judicial District in Reeves County, Texas to terminate a lease under our farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”). Plaintiffs are the lessors and claim a breach of the lease which they allege gives rise to termination of the lease. CWEI denies a breach and argues in the alternative that (i) any breach was cured in accordance with the lease and (ii) a breach will not give rise to lease termination. In October 2013, a judge ruled that CWEI and Chesapeake are jointly and severally liable for damages to plaintiffs in the amount of approximately $2.9 million and attorney fees of $0.8 million . A loss of $1.4 million was recorded for the year ended December 31, 2013 in connection with the judgment. CWEI appealed the judgment and on July 8, 2015, the El Paso Court of Appeals reversed the trial court judgment in its entirety and rendered judgment that Plaintiffs take nothing on all claims against CWEI and Chesapeake. Plaintiffs have appealed the decision of the Court of Appeals to the Texas Supreme Court. We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations. |
Impairment of Property and Equi
Impairment of Property and Equipment | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment Impairment or Disposal [Abstract] | |
Impairment of Property and Equipment | Impairment of Property and Equipment We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value. The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset. We categorize the measurement of fair value of these assets as Level 3 inputs. We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: (1) discounted cash flow method; (2) flowing daily production method; and (3) proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances. We utilize all three methods when that information is available, or if not will utilize the discounted cash flow method. We recorded provisions for impairment of property and equipment aggregating $41.9 million in 2015 , $12 million in 2014 and $89.8 million in 2013 to reduce the carrying value of those properties to their estimated fair values. The 2015 provision of $41.9 million included $37.9 million related primarily to the write-down of certain non-core properties in the Permian Basin and Oklahoma and $4 million related to the write-down of certain drilling rigs and related equipment to reduce the carrying value of these properties to their estimated fair values. The 2014 provision of $12 million related to the write-down of certain non-core properties in the Permian Basin and North Dakota. The 2013 provision of $89.8 million related to the write-down of our Andrews County Wolfberry assets and certain non-core properties in the Permian Basin. Unproved properties are nonproducing and do not have estimable cash flow streams. Therefore, we estimate the fair value of individually significant prospects by obtaining, when available, information about recent market transactions in the vicinity of the prospects and adjust the market data as needed to give consideration to the proximity of the prospects to known fields and reservoirs, the extent of geological and geophysical data on the prospects, the remaining terms of leases holding the acreage in the prospects, recent drilling results in the vicinity of the prospects, and other risk-related factors such as drilling and completion costs, estimated product prices and other economic factors. Individually insignificant prospects are grouped and impaired based on remaining lease terms and our historical experience with similar prospects. Based on the assessments previously discussed, we will impair our unproved oil and gas properties when we determine that a prospect’s carrying value exceeds its estimated fair value. We categorize the measurement of fair value of unproved properties as Level 3 inputs. We recorded provisions for impairment of unproved properties aggregating $2.8 million , $15.4 million and $3.4 million in 2015 , 2014 and 2013 , respectively, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss). |
Costs of Oil and Gas Properties
Costs of Oil and Gas Properties | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Property, Successful Effort Method, Gross [Abstract] | |
Costs of Oil and Gas Properties | Costs of Oil and Gas Properties The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2015 , 2014 and 2013 . 2015 2014 2013 (In thousands) Property acquisitions: Proved $ — $ — $ — Unproved 29,711 56,327 50,104 Developmental costs 81,466 342,716 218,341 Exploratory costs 14,342 4,350 3,932 Total $ 125,519 $ 403,393 $ 272,377 The following table sets forth the net capitalized costs for oil and gas properties as of December 31, 2015 and 2014 . 2015 2014 (In thousands) Proved properties $ 2,539,480 $ 2,585,279 Unproved properties 46,022 99,634 Total capitalized costs 2,585,502 2,684,913 Accumulated depletion (1,460,404 ) (1,430,699 ) Net capitalized costs $ 1,125,098 $ 1,254,214 |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information We have two reportable operating segments, which are (1) oil and gas exploration and production and (2) contract drilling services. The following tables present selected financial information regarding our operating segments for the years ended December 31, 2015 , 2014 and 2013 . Contract Intercompany Consolidated For the Year Ended December 31, 2015 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 232,279 $ 2,837 $ (2,744 ) $ 232,372 Depreciation, depletion and amortization (a) 187,913 16,832 (566 ) 204,179 Other operating expenses (b) 135,177 9,178 (2,727 ) 141,628 Interest expense 54,422 — — 54,422 Other (income) expense (c) (17,091 ) 2,569 — (14,522 ) Income (loss) before income taxes (128,142 ) (25,742 ) 549 (153,335 ) Income tax (expense) benefit 46,129 9,010 — 55,139 Net income (loss) $ (82,013 ) $ (16,732 ) $ 549 $ (98,196 ) Total assets $ 1,290,998 $ 48,943 $ (45,172 ) $ 1,294,769 Additions to property and equipment $ 124,996 $ 1,202 $ 549 $ 126,747 Contract Intercompany Consolidated For the Year Ended December 31, 2014 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 440,428 $ 59,107 $ (31,079 ) $ 468,456 Depreciation, depletion and amortization (a) 157,164 13,307 (4,088 ) 166,383 Other operating expenses (b) 170,878 41,912 (22,356 ) 190,434 Interest expense 50,907 — — 50,907 Other (income) expense (8,001 ) 165 — (7,836 ) Income (loss) before income taxes 69,480 3,723 (4,635 ) 68,568 Income tax (expense) benefit (23,384 ) (1,303 ) — (24,687 ) Net income (loss) $ 46,096 $ 2,420 $ (4,635 ) $ 43,881 Total assets $ 1,482,863 $ 70,051 $ (42,029 ) $ 1,510,885 Additions to property and equipment $ 412,951 $ 27,128 $ (4,635 ) $ 435,444 Contract Intercompany Consolidated For the Year Ended December 31, 2013 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 411,403 $ 37,255 $ (19,443 ) $ 429,215 Depreciation, depletion and amortization (a) 229,460 13,844 (2,591 ) 240,713 Other operating expenses (b) 159,294 32,817 (16,224 ) 175,887 Interest expense 43,079 — — 43,079 Other (income) expense 6,826 — — 6,826 Income (loss) before income taxes (27,256 ) (9,406 ) (628 ) (37,290 ) Income tax (expense) benefit 9,136 3,292 — 12,428 Net income (loss) $ (18,120 ) $ (6,114 ) $ (628 ) $ (24,862 ) Total assets $ 1,339,920 $ 54,697 $ (27,880 ) $ 1,366,737 Additions to property and equipment $ 280,173 $ 5,107 $ (628 ) $ 284,652 _______ (a) Includes impairment of property and equipment. (b) Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, general and administrative expenses and other operating expenses. (c) Includes impairment of our investment in Dalea. |
Guarantor Financial Information
Guarantor Financial Information | 12 Months Ended |
Dec. 31, 2015 | |
Guarantor Financial Information Disclosure [Abstract] | |
Guarantor Financial Information | Guarantor Financial Information In March and April 2011, we issued $350 million of aggregate principal amount of 2019 Senior Notes. In October 2013 , we issued $250 million of aggregate principal amount of the 2019 Senior Notes. The 2019 Senior Notes issued in October 2013 and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the same indenture (see Note 3). Presented below is condensed consolidated financial information of CWEI (the “Issuer”) and the Issuer’s material wholly owned subsidiaries. Other than CWEI Andrews Properties, GP, LLC, the general partner of CWEI Andrews Properties, L.P., an affiliated limited partnership formed in April 2013 , all of the Issuer’s wholly owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the 2019 Senior Notes. The guarantee by a Guarantor Subsidiary of the 2019 Senior Notes may be released under certain customary circumstances as set forth in the Indenture. CWEI Andrews Properties, GP, LLC, is not a guarantor of the 2019 Senior Notes and its accounts are reflected in the “Non-Guarantor Subsidiary” column in this Note 18. The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated. Condensed Consolidating Balance Sheet December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Current assets $ 112,861 $ 272,310 $ 1,441 $ (317,807 ) $ 68,805 Property and equipment, net 887,313 308,738 5,233 — 1,201,284 Investments in subsidiaries 328,794 — — (328,794 ) — Other assets 12,878 11,802 — — 24,680 Total assets $ 1,341,846 $ 592,850 $ 6,674 $ (646,601 ) $ 1,294,769 Current liabilities $ 276,354 $ 102,267 $ 117 $ (312,999 ) $ 65,739 Non-current liabilities: Long-term debt 749,759 — — — 749,759 Deferred income taxes 88,067 132,204 (649 ) (110,626 ) 108,996 Other 33,886 36,539 252 — 70,677 871,712 168,743 (397 ) (110,626 ) 929,432 Equity 193,780 321,840 6,954 (222,976 ) 299,598 Total liabilities and equity $ 1,341,846 $ 592,850 $ 6,674 $ (646,601 ) $ 1,294,769 Condensed Consolidating Balance Sheet December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Current assets $ 153,373 $ 293,613 $ 546 $ (314,912 ) $ 132,620 Property and equipment, net 986,110 344,174 18,600 — 1,348,884 Investments in subsidiaries 359,777 — — (359,777 ) — Other assets 16,077 13,304 — — 29,381 Total assets $ 1,515,337 $ 651,091 $ 19,146 $ (674,689 ) $ 1,510,885 Current liabilities $ 352,889 $ 113,746 $ 586 $ (310,868 ) $ 156,353 Non-current liabilities: Long-term debt 704,696 — — — 704,696 Deferred income taxes 129,105 141,130 4,227 (109,863 ) 164,599 Other 36,671 50,591 181 — 87,443 870,472 191,721 4,408 (109,863 ) 956,738 Equity 291,976 345,624 14,152 (253,958 ) 397,794 Total liabilities and equity $ 1,515,337 $ 651,091 $ 19,146 $ (674,689 ) $ 1,510,885 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 169,705 $ 61,224 $ 1,443 $ — $ 232,372 Costs and expenses 244,187 87,008 14,612 — 345,807 Operating income (loss) (74,482 ) (25,784 ) (13,169 ) — (113,435 ) Other income (expense) (41,187 ) (808 ) 2,095 — (39,900 ) Equity in earnings of subsidiaries (24,483 ) — — 24,483 — Income tax (expense) benefit 41,956 9,307 3,876 — 55,139 Net income (loss) $ (98,196 ) $ (17,285 ) $ (7,198 ) $ 24,483 $ (98,196 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 324,055 $ 140,857 $ 3,544 $ — $ 468,456 Costs and expenses 242,658 111,750 2,409 — 356,817 Operating income (loss) 81,397 29,107 1,135 — 111,639 Other income (expense) (45,538 ) 919 1,548 — (43,071 ) Equity in earnings of subsidiaries 21,261 — — (21,261 ) — Income tax (expense) benefit (13,239 ) (10,509 ) (939 ) — (24,687 ) Net income (loss) $ 43,881 $ 19,517 $ 1,744 $ (21,261 ) $ 43,881 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2013 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 280,423 $ 146,556 $ 2,236 $ — $ 429,215 Costs and expenses 302,898 112,441 1,261 — 416,600 Operating income (loss) (22,475 ) 34,115 975 — 12,615 Other income (expense) (50,601 ) (25 ) 721 — (49,905 ) Equity in earnings of subsidiaries 23,261 — — (23,261 ) — Income tax (expense) benefit 24,953 (11,931 ) (594 ) — 12,428 Net income (loss) $ (24,862 ) $ 22,159 $ 1,102 $ (23,261 ) $ (24,862 ) Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 61,138 $ 836 $ (10,381 ) $ 566 $ 52,159 Investing activities (113,543 ) (15,143 ) 11,857 (566 ) (117,395 ) Financing activities 35,851 9,469 (320 ) — 45,000 Net increase (decrease) in cash and cash equivalents (16,554 ) (4,838 ) 1,156 — (20,236 ) Cash at the beginning of the period 21,217 6,693 106 — 28,016 Cash at end of the period $ 4,663 $ 1,855 $ 1,262 $ — $ 7,780 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 178,769 $ 69,543 $ 5,842 $ 3,967 $ 258,121 Investing activities (274,629 ) (34,749 ) (5,652 ) (3,967 ) (318,997 ) Financing activities 97,384 (34,987 ) (128 ) — 62,269 Net increase (decrease) in cash and cash equivalents 1,524 (193 ) 62 — 1,393 Cash at the beginning of the period 19,693 6,886 44 — 26,623 Cash at end of the period $ 21,217 $ 6,693 $ 106 $ — $ 28,016 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2013 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 128,146 $ 87,433 $ 2,406 $ 2,591 $ 220,576 Investing activities 10,544 (34,121 ) (2,875 ) (2,591 ) (29,043 ) Financing activities (125,027 ) (51,122 ) 513 — (175,636 ) Net increase (decrease) in cash and cash equivalents 13,663 2,190 44 — 15,897 Cash at the beginning of the period 6,030 4,696 — — 10,726 Cash at end of the period $ 19,693 $ 6,886 $ 44 $ — $ 26,623 |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events On March 8, 2016 , we entered into a second lien term loan credit facility with Ares in the principal amount of $350 million to us, net of original issue discount of $16.8 million , for cash proceeds of $333.2 million (see Note 3). On March 15, 2016, we issued to the lenders warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share for cash proceeds equal to the original issue discount from the issuance on the loans. The warrants represent approximately 18.5% of our currently outstanding shares of common stock, or approximately 15.6% of our common shares on a fully exercised basis. In connection with the issuance of the warrants, we designated and issued to the initial warrant holders 3,500 shares of special voting preferred stock, $0.10 par value per share, granting them certain rights to elect two members of our board of directors. We have evaluated events and transactions that occurred after the balance sheet date of December 31, 2015 and have determined that no other events or transactions have occurred that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements. |
Supplemental Quarterly Financia
Supplemental Quarterly Financial Information | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Supplemental Quarterly Financial Information | Supplemental Quarterly Financial Data The following table summarizes results for each of the four quarters in the years ended December 31, 2015 and 2014 . First Quarter Second Quarter Third Quarter Fourth Quarter Year (In thousands, except per share) Year Ended December 31, 2015: Total revenues $ 64,142 $ 73,231 $ 54,581 $ 40,418 $ 232,372 Operating income (loss) $ (20,182 ) $ (11,058 ) $ (19,739 ) $ (62,456 ) $ (113,435 ) Net income (loss) $ (18,232 ) $ (23,332 ) $ (9,423 ) $ (47,209 ) $ (98,196 ) Net income (loss) per common share (a) : Basic $ (1.50 ) $ (1.92 ) $ (0.77 ) $ (3.88 ) $ (8.07 ) Diluted $ (1.50 ) $ (1.92 ) $ (0.77 ) $ (3.88 ) $ (8.07 ) Weighted average common shares outstanding: Basic 12,170 12,170 12,170 12,170 12,170 Diluted 12,170 12,170 12,170 12,170 12,170 Year Ended December 31, 2014: Total revenues $ 124,605 $ 129,895 $ 119,283 $ 94,673 $ 468,456 Operating income (loss) $ 34,579 $ 34,739 $ 45,565 $ (3,244 ) $ 111,639 Net income (loss) $ 11,392 $ 9,327 $ 27,429 $ (4,267 ) $ 43,881 Net income (loss) per common share (a) : Basic $ 0.94 $ 0.77 $ 2.25 $ (0.35 ) $ 3.61 Diluted $ 0.94 $ 0.77 $ 2.25 $ (0.35 ) $ 3.61 Weighted average common shares outstanding: Basic 12,166 12,166 12,166 12,170 12,167 Diluted 12,166 12,166 12,166 12,170 12,167 ______ (a) The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period. |
Supplemental Oil and Gas Reserv
Supplemental Oil and Gas Reserve Information | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Supplemental Oil and Gas Reserve Information | Supplemental Oil and Gas Reserve Information The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the Securities and Exchange Commission and the FASB. All of our reserves are located in the United States. For information about our results of operations from oil and gas activities, see the accompanying consolidated statements of operations and comprehensive income (loss). We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced. We did not have any capital costs relating to exploratory wells pending the determination of proved reserves for the years ended December 31, 2015 , 2014 and 2013 . The following table sets forth estimated proved reserves together with the changes therein (oil and NGL in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended December 31, 2015 , 2014 and 2013 . Oil Natural Gas Liquids Natural Gas MBOE Proved reserves: December 31, 2012 49,119 9,182 102,336 75,357 Extensions and discoveries 20,540 3,562 21,389 27,666 Revisions 85 1,806 (16,753 ) (901 ) Sales of minerals-in-place (17,387 ) (5,531 ) (23,605 ) (26,852 ) Production (3,692 ) (532 ) (6,188 ) (5,255 ) December 31, 2013 48,665 8,487 77,179 70,015 Extensions and discoveries 19,032 2,298 12,034 23,336 Revisions (7,786 ) (1,160 ) (6,934 ) (10,101 ) Sales of minerals-in-place (1,850 ) (73 ) (803 ) (2,057 ) Production (4,194 ) (585 ) (5,901 ) (5,763 ) December 31, 2014 53,867 8,967 75,575 75,430 Extensions and discoveries 2,669 407 2,796 3,542 Revisions (18,912 ) (3,344 ) (23,414 ) (26,158 ) Sales of minerals-in-place (291 ) (12 ) (1,016 ) (472 ) Production (4,257 ) (550 ) (5,794 ) (5,773 ) December 31, 2015 33,076 5,468 48,147 46,569 Proved developed reserves: December 31, 2013 25,989 4,293 47,839 38,255 December 31, 2014 29,059 4,668 51,072 42,239 December 31, 2015 25,349 4,266 39,987 36,280 CLAYTON WILLIAMS ENERGY, INC. SUPPLEMENTAL INFORMATION (Continued) (UNAUDITED) The 26,158 MBOE of net downward revisions in proved reserves for 2015 resulted from a combination of (1) reclassifications of 9,561 MBOE of proved undeveloped reserves to probable reserves due solely to the SEC five-year development rule, (2) net upward revisions of 11,963 MBOE related primarily to performance in our Delaware Basin program, and (3) downward revisions of 28,560 MBOE related to the effects of lower commodity prices on the estimated quantities of proved reserves. The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2015 , 2014 and 2013 was as follows: 2015 2014 2013 (In thousands) Future cash inflows $ 1,721,207 $ 5,479,211 $ 5,162,702 Future costs: Production (711,887 ) (1,719,989 ) (1,724,560 ) Abandonment (120,737 ) (149,112 ) (131,747 ) Development (147,189 ) (695,180 ) (592,695 ) Income taxes (38,306 ) (833,601 ) (786,196 ) Future net cash flows 703,088 2,081,329 1,927,504 10% discount factor (312,445 ) (1,148,416 ) (1,000,581 ) Standardized measure of discounted net cash flows $ 390,643 $ 932,913 $ 926,923 Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended December 31, 2015 , 2014 and 2013 were as follows: 2015 2014 2013 (In thousands) Standardized measure, beginning of period $ 932,913 $ 926,923 $ 939,831 Net changes in sales prices, net of production costs (965,126 ) (94,104 ) 13,292 Revisions of quantity estimates (245,035 ) (234,612 ) (10,680 ) Accretion of discount 137,998 138,095 130,736 Changes in future development costs, including development costs incurred that reduced future development costs 308,261 146,392 46,068 Changes in timing and other (69,160 ) (70,774 ) (10,249 ) Net change in income taxes 395,888 2,893 (84,673 ) Future abandonment cost, net of salvage (2,968 ) 4,066 232 Extensions and discoveries 48,367 431,895 502,619 Sales, net of production costs (126,455 ) (309,758 ) (289,035 ) Sales of minerals-in-place (24,040 ) (8,103 ) (311,218 ) Standardized measure, end of period $ 390,643 $ 932,913 $ 926,923 CLAYTON WILLIAMS ENERGY, INC. SUPPLEMENTAL INFORMATION (Continued) (UNAUDITED) The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period. Average prices for December 31, 2015 , 2014 and 2013 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from January through December during each respective calendar year. These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties. The average prices used for each commodity for the years ended December 31, 2015 , 2014 and 2013 were as follows: Average Price Oil Natural Gas Liquids Natural Gas ($/Bbl) ($/Bbl) ($/Mcf) As of December 31: 2015 $ 45.75 $ 15.84 $ 2.52 2014 $ 90.48 $ 31.54 $ 4.27 2013 $ 94.88 $ 31.63 $ 3.59 |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Estimates and Assumptions | The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows: • Provisions for depreciation, depletion and amortization and estimates of non-equity plans are based on estimates of proved reserves; • Impairments of long-lived assets are based on estimates of future net cash flows and, when applicable, the estimated fair values of impaired assets; • Exploration expenses related to impairments of unproved acreage are based on estimates of fair values of the underlying leases; • Asset retirement obligations (“ARO”) are based on estimates regarding the timing and cost of future asset retirements; • Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory; and • Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells. |
Principles of Consolidation | The consolidated financial statements include the accounts of CWEI and its wholly owned subsidiaries. We account for our undivided interests in oil and gas limited partnerships using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of such limited partnerships. Less than 5% of our consolidated total assets and total revenues are derived from oil and gas limited partnerships. Substantially all intercompany transactions and balances associated with the consolidated operations have been eliminated. |
Oil and Gas Properties | We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned. Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties. |
Pipelines and Other Midstream Facilities and Other Property and Equipment | Pipelines and other midstream facilities consist of pipelines to transport oil, natural gas and water, natural gas processing facilities and compressors. Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles. Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred. The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income (loss) in the accompanying consolidated statements of operations and comprehensive income (loss). Depreciation of pipelines and other midstream facilities and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 30 years. |
Contract Drilling | We conduct contract drilling operations through Desta Drilling, a wholly owned subsidiary of CWEI. Desta Drilling recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable. Property and equipment, including buildings, major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 40 years. Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized. |
Valuation of Property and Equipment | Our long-lived assets, including proved oil and gas properties and contract drilling equipment, are assessed for potential impairment in their carrying values, based on depletable groupings, whenever events or changes in circumstances indicate such impairment may have occurred. An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the difference in the carrying value and estimated fair value of the impaired asset. Unproved oil and gas properties are periodically assessed, and any impairment in value is charged to exploration costs. The amount of impairment recognized on unproved properties which are not individually significant is determined by impairing the costs of such properties within appropriate groups based on our historical experience, acquisition dates and average lease terms. The valuation of unproved properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. |
Asset Retirement Obligations | We recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost associated with the asset retirement obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization. |
Income Taxes | We utilize the asset and liability method to account for income taxes. Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the consolidated statements of operations and comprehensive income (loss) in the period that includes the enactment date. We also record any financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense. |
Hedging Transactions | From time to time, we utilize derivative instruments, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. All of our derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a derivative depends on both the intended purpose and the formal designation of the derivative. Designation is established at the inception of a derivative, but subsequent changes to the designation are permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines under applicable accounting standards, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in fair value of derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines are recorded in earnings as the changes occur. If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production is sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period. Actual gains or losses from derivatives not designated as cash flow hedges are recorded in other income (expense) as gain (loss) on derivatives. |
Inventory | Inventory consists primarily of tubular goods and other well equipment which we plan to utilize in our exploration and development activities and is stated at the lower of average cost or estimated market value. |
Capitalization of Interest | Interest costs associated with our inventory of unproved oil and gas property lease acquisition costs are capitalized during the periods for which exploration activities are in progress. |
Cash and Cash Equivalents | We consider all cash and highly liquid investments with original maturities of three months or less to be cash equivalents. |
Net Income (Loss) Per Common Share | Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of Common Shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted net income (loss) per share calculations for 2015 , 2014 and 2013 include changes in potential shares attributable to dilutive stock options. |
Fair Value Measurements | We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows: Level 1 - Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 3 - Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. |
Revenue Recognition and Gas Balancing | We utilize the sales method of accounting for oil, natural gas and natural gas liquids (“NGL”) revenues whereby revenues, net of royalties, are recognized as the production is sold to purchasers. The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties. We did not have any significant gas imbalance positions at December 31, 2015 , 2014 or 2013 . Revenues from midstream services and drilling rig services are recognized as services are provided. |
Comprehensive Income (Loss) | There were no differences between net income (loss) and comprehensive income (loss) in 2015 , 2014 and 2013 . |
Concentration Risks | We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. When management deems appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. Allowances for doubtful accounts at December 31, 2015 and 2014 relate to amounts due from joint interest owners. |
Recent Accounting Pronouncements | In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842).” The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases). Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted. ASU 2016-02 must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transaction will require application of the new guidance at the beginning of the earliest comparative period presented. We are evaluating the impact that this new guidance will have on our consolidated financial statements. In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes.” This ASU requires that deferred tax assets and liabilities be classified as noncurrent on the balance sheet. The standard will be effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption will be permitted as of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. Adoption of the new guidance will affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements. In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively, with early adoption permitted. The adoption of this standard will not have a material impact on our consolidated financial statements. In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items (that is, debt issuance cost asset and the debt liability). We currently present debt issuance costs on the balance sheet as an asset. As of December 31, 2015 , we had $9.6 million of debt issuance costs, which under this standard would be reclassified from an asset to a direct deduction to the related debt liability. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements. |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Schedule of long-term debt | Long-term debt consists of the following: December 31, December 31, (In thousands) 7.75% Senior Notes due 2019, net of unamortized original issue discount of $241 at December 31, 2015 and $304 at December 31, 2014 $ 599,759 $ 599,696 Revolving credit facility, due April 2019 (a) 150,000 105,000 $ 749,759 $ 704,696 ______ (a) Renewed and extended in April 2014. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of changes in asset retirement obligations | The following table reflects the changes in ARO for the years ended December 31, 2015 and December 31, 2014 : 2015 2014 (In thousands) Beginning of year $ 45,697 $ 49,981 Additional ARO from new properties 469 1,209 Sales or abandonments of properties (4,435 ) (5,246 ) Accretion expense 3,945 3,662 Revisions of previous estimates 3,052 (3,909 ) End of year $ 48,728 $ 45,697 |
Deferred Revenue from Volumet31
Deferred Revenue from Volumetric Production Payment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Deferred Revenue Disclosure [Abstract] | |
Schedule of changes in deferred revenue from the VPP | The following table reflects the changes in deferred revenue during the years ended December 31, 2015 and December 31, 2014 : 2015 2014 (In thousands) Beginning of year $ 23,129 $ 29,770 Deferred revenue from VPP 2,866 1,067 Amortization of deferred revenue from VPP (6,822 ) (7,708 ) Termination of VPP (13,703 ) — End of year $ 5,470 $ 23,129 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule of deferred tax assets and liabilities | Significant components of net deferred tax liabilities at December 31, 2015 and 2014 are as follows: 2015 2014 (In thousands) Deferred tax assets: Net operating loss carryforwards $ 106,992 $ 84,587 Statutory depletion carryforwards 9,809 9,581 Asset retirement obligations and other 21,249 19,061 138,050 113,229 Deferred tax liabilities: Property and equipment (240,520 ) (270,917 ) Net deferred tax liabilities $ (102,470 ) $ (157,688 ) Components of net deferred tax liabilities: Current assets $ 6,526 $ 6,911 Non-current liabilities (108,996 ) (164,599 ) Net deferred tax liabilities $ (102,470 ) $ (157,688 ) |
Schedule of effective income tax rate reconciliation | For the years ended December 31, 2015 , 2014 and 2013 , effective income tax rates were different than the statutory federal income tax rates for the following reasons: 2015 2014 2013 (In thousands) Income tax expense (benefit) at statutory rate of 35% $ (53,667 ) $ 23,999 $ (13,052 ) Tax depletion in excess of basis (282 ) (729 ) (518 ) Revision of previous tax estimates 30 (155 ) 373 State income tax expense (benefit), net of federal tax effect (1,472 ) 1,008 76 Other 252 564 693 Income tax expense (benefit) $ (55,139 ) $ 24,687 $ (12,428 ) Current $ 79 $ 227 $ 1,614 Deferred (55,218 ) 24,460 (14,042 ) Income tax expense (benefit) $ (55,139 ) $ 24,687 $ (12,428 ) |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of price risk derivatives | The following summarizes information concerning our net positions in open commodity derivatives, all of which were entered into in January 2016 and March 2016 , applicable to periods subsequent to December 31, 2015 . In addition, we granted an option on an additional 739 MBbls of oil production from July 2016 through December 2016 at $40.25 per barrel exercisable by the counterparty by June 30, 2016 . Settlement prices of commodity derivatives are based on NYMEX futures prices. Current Swaps: Oil MBbls Price Production Period: 1st Quarter 2016 421 $ 40.25 2nd Quarter 2016 518 $ 40.47 3rd Quarter 2016 176 $ 42.70 4th Quarter 2016 167 $ 42.70 2017 315 $ 44.30 1,597 Swaps Subject to Optional Extension: Oil MBbls Price Production Period: 3rd Quarter 2016 378 $ 40.25 4th Quarter 2016 361 $ 40.25 739 |
Schedule of effect of derivative instruments on the consolidated statement of operations and Comprehensive Income (Loss) | Amount of Gain or (Loss) Recognized in Earnings Year Ended December 31, Location of Gain or (Loss) Recognized in Earnings 2015 2014 2013 (In thousands) Derivatives not designated as hedging instruments: Commodity derivatives: Other income (expense) - Gain (loss) on derivatives $ 12,519 $ 4,789 $ (8,731 ) Total $ 12,519 $ 4,789 $ (8,731 ) |
Fair Value of Financial Instr34
Fair Value of Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Schedule of comparison of fair value to the carrying value of the 2019 Senior Notes | Fair value is compared to the carrying value in the table below: December 31, 2015 December 31, 2014 Carrying Estimated Carrying Estimated Description Amount Fair Value Amount Fair Value (In thousands) 7.75% Senior Notes due 2019 $ 599,759 $ 462,750 $ 599,696 $ 510,000 |
Compensation Plans (Tables)
Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Compensation Plans [Abstract] | |
Disclosure of share-based compensation arrangements by share-based payment award | The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2015 , 2014 and 2013 . 2015 2014 2013 (In thousands, except per share) Weighted average grant date fair value of options granted per share $ — $ — $ — Intrinsic value of options exercised $ — $ 263 $ 53 |
Schedule of aggregate compensation under non-equity award plans reflected on the balance sheet | Accrued compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule: December 31, December 31, (In thousands) Current liabilities: Accrued liabilities and other $ 1,251 $ 2,317 Non-current liabilities: Accrued compensation under non-equity award plans 16,254 17,866 Total accrued compensation under non-equity award plans $ 17,505 $ 20,183 |
Transactions with Affiliates (T
Transactions with Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Summary of charges to and from Williams Entities | The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2015 , 2014 and 2013 . 2015 2014 2013 (In thousands) Amounts received from the Williams Entities: Service Agreement: Services $ 622 $ 663 $ 715 Insurance premiums and benefits 922 960 837 Reimbursed expenses 500 296 427 $ 2,044 $ 1,919 $ 1,979 Amounts paid to the Williams Entities: Rent (a) $ 1,741 $ 1,614 $ 1,560 Service Agreement: Business entertainment (b) 155 205 344 Reimbursed expenses 226 204 216 $ 2,122 $ 2,023 $ 2,120 ______ (a) Rent amounts were paid to a partnership within the Williams Entities. The Company owns 31.9% of the partnership and affiliates of the Company own 25.8% . (b) Consists primarily of hunting and fishing recreation for business associates and employees of the Company on land owned by affiliates of Mr. Williams. |
Other Operating Revenues and 37
Other Operating Revenues and Expenses (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Other Income and Expenses [Abstract] | |
Schedule of net gain on sales of assets and impairment of inventory | Other operating revenues and expenses for the years ended December 31, 2015 , 2014 and 2013 are as follows: 2015 2014 2013 (In thousands) Other operating revenues: Gain on sales of assets $ 8,718 $ 11,685 $ 4,467 Marketing revenue 24 3,708 2,021 Total other operating revenues $ 8,742 $ 15,393 $ 6,488 Other operating expenses: Loss on sales of assets $ 1,355 $ 2,511 $ 1,233 Marketing expense 849 — 658 Impairment of inventory 10,381 36 210 Total other operating expenses $ 12,585 $ 2,547 $ 2,101 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule Future minimum payments under noncancelable leases | Future minimum payments under noncancelable leases at December 31, 2015 are as follows: Leases Capital (a) Operating (b) Total (In thousands) 2016 $ 601 $ 3,744 $ 4,345 2017 180 924 1,104 2018 18 676 694 Thereafter — 740 740 Total minimum lease payments $ 799 $ 6,084 $ 6,883 ______ (a) Relates to vehicle leases. (b) Includes leases for two drilling rigs. |
Costs of Oil and Gas Properti39
Costs of Oil and Gas Properties (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Property, Successful Effort Method, Gross [Abstract] | |
Costs incurred in connection with the company's oil and gas producing activities | The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2015 , 2014 and 2013 . 2015 2014 2013 (In thousands) Property acquisitions: Proved $ — $ — $ — Unproved 29,711 56,327 50,104 Developmental costs 81,466 342,716 218,341 Exploratory costs 14,342 4,350 3,932 Total $ 125,519 $ 403,393 $ 272,377 |
Schedule of net capitalized costs for oil and gas properties | The following table sets forth the net capitalized costs for oil and gas properties as of December 31, 2015 and 2014 . 2015 2014 (In thousands) Proved properties $ 2,539,480 $ 2,585,279 Unproved properties 46,022 99,634 Total capitalized costs 2,585,502 2,684,913 Accumulated depletion (1,460,404 ) (1,430,699 ) Net capitalized costs $ 1,125,098 $ 1,254,214 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Schedule of selected financial information regarding operating segments | The following tables present selected financial information regarding our operating segments for the years ended December 31, 2015 , 2014 and 2013 . Contract Intercompany Consolidated For the Year Ended December 31, 2015 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 232,279 $ 2,837 $ (2,744 ) $ 232,372 Depreciation, depletion and amortization (a) 187,913 16,832 (566 ) 204,179 Other operating expenses (b) 135,177 9,178 (2,727 ) 141,628 Interest expense 54,422 — — 54,422 Other (income) expense (c) (17,091 ) 2,569 — (14,522 ) Income (loss) before income taxes (128,142 ) (25,742 ) 549 (153,335 ) Income tax (expense) benefit 46,129 9,010 — 55,139 Net income (loss) $ (82,013 ) $ (16,732 ) $ 549 $ (98,196 ) Total assets $ 1,290,998 $ 48,943 $ (45,172 ) $ 1,294,769 Additions to property and equipment $ 124,996 $ 1,202 $ 549 $ 126,747 Contract Intercompany Consolidated For the Year Ended December 31, 2014 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 440,428 $ 59,107 $ (31,079 ) $ 468,456 Depreciation, depletion and amortization (a) 157,164 13,307 (4,088 ) 166,383 Other operating expenses (b) 170,878 41,912 (22,356 ) 190,434 Interest expense 50,907 — — 50,907 Other (income) expense (8,001 ) 165 — (7,836 ) Income (loss) before income taxes 69,480 3,723 (4,635 ) 68,568 Income tax (expense) benefit (23,384 ) (1,303 ) — (24,687 ) Net income (loss) $ 46,096 $ 2,420 $ (4,635 ) $ 43,881 Total assets $ 1,482,863 $ 70,051 $ (42,029 ) $ 1,510,885 Additions to property and equipment $ 412,951 $ 27,128 $ (4,635 ) $ 435,444 Contract Intercompany Consolidated For the Year Ended December 31, 2013 Oil and Gas Drilling Eliminations Total (In thousands) Revenues $ 411,403 $ 37,255 $ (19,443 ) $ 429,215 Depreciation, depletion and amortization (a) 229,460 13,844 (2,591 ) 240,713 Other operating expenses (b) 159,294 32,817 (16,224 ) 175,887 Interest expense 43,079 — — 43,079 Other (income) expense 6,826 — — 6,826 Income (loss) before income taxes (27,256 ) (9,406 ) (628 ) (37,290 ) Income tax (expense) benefit 9,136 3,292 — 12,428 Net income (loss) $ (18,120 ) $ (6,114 ) $ (628 ) $ (24,862 ) Total assets $ 1,339,920 $ 54,697 $ (27,880 ) $ 1,366,737 Additions to property and equipment $ 280,173 $ 5,107 $ (628 ) $ 284,652 _______ (a) Includes impairment of property and equipment. (b) Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, general and administrative expenses and other operating expenses. (c) Includes impairment of our investment in Dalea. |
Guarantor Financial Informati41
Guarantor Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Guarantor Financial Information Disclosure [Abstract] | |
Schedule of Condensed Consolidating Balance Sheet | Condensed Consolidating Balance Sheet December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Subsidiary Adjustments/ Eliminations Consolidated Current assets $ 112,861 $ 272,310 $ 1,441 $ (317,807 ) $ 68,805 Property and equipment, net 887,313 308,738 5,233 — 1,201,284 Investments in subsidiaries 328,794 — — (328,794 ) — Other assets 12,878 11,802 — — 24,680 Total assets $ 1,341,846 $ 592,850 $ 6,674 $ (646,601 ) $ 1,294,769 Current liabilities $ 276,354 $ 102,267 $ 117 $ (312,999 ) $ 65,739 Non-current liabilities: Long-term debt 749,759 — — — 749,759 Deferred income taxes 88,067 132,204 (649 ) (110,626 ) 108,996 Other 33,886 36,539 252 — 70,677 871,712 168,743 (397 ) (110,626 ) 929,432 Equity 193,780 321,840 6,954 (222,976 ) 299,598 Total liabilities and equity $ 1,341,846 $ 592,850 $ 6,674 $ (646,601 ) $ 1,294,769 Condensed Consolidating Balance Sheet December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Current assets $ 153,373 $ 293,613 $ 546 $ (314,912 ) $ 132,620 Property and equipment, net 986,110 344,174 18,600 — 1,348,884 Investments in subsidiaries 359,777 — — (359,777 ) — Other assets 16,077 13,304 — — 29,381 Total assets $ 1,515,337 $ 651,091 $ 19,146 $ (674,689 ) $ 1,510,885 Current liabilities $ 352,889 $ 113,746 $ 586 $ (310,868 ) $ 156,353 Non-current liabilities: Long-term debt 704,696 — — — 704,696 Deferred income taxes 129,105 141,130 4,227 (109,863 ) 164,599 Other 36,671 50,591 181 — 87,443 870,472 191,721 4,408 (109,863 ) 956,738 Equity 291,976 345,624 14,152 (253,958 ) 397,794 Total liabilities and equity $ 1,515,337 $ 651,091 $ 19,146 $ (674,689 ) $ 1,510,885 |
Schedule of Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) | Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 169,705 $ 61,224 $ 1,443 $ — $ 232,372 Costs and expenses 244,187 87,008 14,612 — 345,807 Operating income (loss) (74,482 ) (25,784 ) (13,169 ) — (113,435 ) Other income (expense) (41,187 ) (808 ) 2,095 — (39,900 ) Equity in earnings of subsidiaries (24,483 ) — — 24,483 — Income tax (expense) benefit 41,956 9,307 3,876 — 55,139 Net income (loss) $ (98,196 ) $ (17,285 ) $ (7,198 ) $ 24,483 $ (98,196 ) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 324,055 $ 140,857 $ 3,544 $ — $ 468,456 Costs and expenses 242,658 111,750 2,409 — 356,817 Operating income (loss) 81,397 29,107 1,135 — 111,639 Other income (expense) (45,538 ) 919 1,548 — (43,071 ) Equity in earnings of subsidiaries 21,261 — — (21,261 ) — Income tax (expense) benefit (13,239 ) (10,509 ) (939 ) — (24,687 ) Net income (loss) $ 43,881 $ 19,517 $ 1,744 $ (21,261 ) $ 43,881 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2013 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Total revenue $ 280,423 $ 146,556 $ 2,236 $ — $ 429,215 Costs and expenses 302,898 112,441 1,261 — 416,600 Operating income (loss) (22,475 ) 34,115 975 — 12,615 Other income (expense) (50,601 ) (25 ) 721 — (49,905 ) Equity in earnings of subsidiaries 23,261 — — (23,261 ) — Income tax (expense) benefit 24,953 (11,931 ) (594 ) — 12,428 Net income (loss) $ (24,862 ) $ 22,159 $ 1,102 $ (23,261 ) $ (24,862 ) |
Schedule of Condensed Consolidating Statement of Cash Flows | Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 61,138 $ 836 $ (10,381 ) $ 566 $ 52,159 Investing activities (113,543 ) (15,143 ) 11,857 (566 ) (117,395 ) Financing activities 35,851 9,469 (320 ) — 45,000 Net increase (decrease) in cash and cash equivalents (16,554 ) (4,838 ) 1,156 — (20,236 ) Cash at the beginning of the period 21,217 6,693 106 — 28,016 Cash at end of the period $ 4,663 $ 1,855 $ 1,262 $ — $ 7,780 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2014 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 178,769 $ 69,543 $ 5,842 $ 3,967 $ 258,121 Investing activities (274,629 ) (34,749 ) (5,652 ) (3,967 ) (318,997 ) Financing activities 97,384 (34,987 ) (128 ) — 62,269 Net increase (decrease) in cash and cash equivalents 1,524 (193 ) 62 — 1,393 Cash at the beginning of the period 19,693 6,886 44 — 26,623 Cash at end of the period $ 21,217 $ 6,693 $ 106 $ — $ 28,016 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2013 (Dollars in thousands) Issuer Guarantor Subsidiaries Non-Guarantor Adjustments/ Eliminations Consolidated Operating activities $ 128,146 $ 87,433 $ 2,406 $ 2,591 $ 220,576 Investing activities 10,544 (34,121 ) (2,875 ) (2,591 ) (29,043 ) Financing activities (125,027 ) (51,122 ) 513 — (175,636 ) Net increase (decrease) in cash and cash equivalents 13,663 2,190 44 — 15,897 Cash at the beginning of the period 6,030 4,696 — — 10,726 Cash at end of the period $ 19,693 $ 6,886 $ 44 $ — $ 26,623 |
Supplemental Quarterly Financ42
Supplemental Quarterly Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | The following table summarizes results for each of the four quarters in the years ended December 31, 2015 and 2014 . First Quarter Second Quarter Third Quarter Fourth Quarter Year (In thousands, except per share) Year Ended December 31, 2015: Total revenues $ 64,142 $ 73,231 $ 54,581 $ 40,418 $ 232,372 Operating income (loss) $ (20,182 ) $ (11,058 ) $ (19,739 ) $ (62,456 ) $ (113,435 ) Net income (loss) $ (18,232 ) $ (23,332 ) $ (9,423 ) $ (47,209 ) $ (98,196 ) Net income (loss) per common share (a) : Basic $ (1.50 ) $ (1.92 ) $ (0.77 ) $ (3.88 ) $ (8.07 ) Diluted $ (1.50 ) $ (1.92 ) $ (0.77 ) $ (3.88 ) $ (8.07 ) Weighted average common shares outstanding: Basic 12,170 12,170 12,170 12,170 12,170 Diluted 12,170 12,170 12,170 12,170 12,170 Year Ended December 31, 2014: Total revenues $ 124,605 $ 129,895 $ 119,283 $ 94,673 $ 468,456 Operating income (loss) $ 34,579 $ 34,739 $ 45,565 $ (3,244 ) $ 111,639 Net income (loss) $ 11,392 $ 9,327 $ 27,429 $ (4,267 ) $ 43,881 Net income (loss) per common share (a) : Basic $ 0.94 $ 0.77 $ 2.25 $ (0.35 ) $ 3.61 Diluted $ 0.94 $ 0.77 $ 2.25 $ (0.35 ) $ 3.61 Weighted average common shares outstanding: Basic 12,166 12,166 12,166 12,170 12,167 Diluted 12,166 12,166 12,166 12,170 12,167 ______ (a) The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period. |
Supplemental Oil and Gas Rese43
Supplemental Oil and Gas Reserve Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Schedule of estimated proved oil and gas reserves | The following table sets forth estimated proved reserves together with the changes therein (oil and NGL in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended December 31, 2015 , 2014 and 2013 . Oil Natural Gas Liquids Natural Gas MBOE Proved reserves: December 31, 2012 49,119 9,182 102,336 75,357 Extensions and discoveries 20,540 3,562 21,389 27,666 Revisions 85 1,806 (16,753 ) (901 ) Sales of minerals-in-place (17,387 ) (5,531 ) (23,605 ) (26,852 ) Production (3,692 ) (532 ) (6,188 ) (5,255 ) December 31, 2013 48,665 8,487 77,179 70,015 Extensions and discoveries 19,032 2,298 12,034 23,336 Revisions (7,786 ) (1,160 ) (6,934 ) (10,101 ) Sales of minerals-in-place (1,850 ) (73 ) (803 ) (2,057 ) Production (4,194 ) (585 ) (5,901 ) (5,763 ) December 31, 2014 53,867 8,967 75,575 75,430 Extensions and discoveries 2,669 407 2,796 3,542 Revisions (18,912 ) (3,344 ) (23,414 ) (26,158 ) Sales of minerals-in-place (291 ) (12 ) (1,016 ) (472 ) Production (4,257 ) (550 ) (5,794 ) (5,773 ) December 31, 2015 33,076 5,468 48,147 46,569 Proved developed reserves: December 31, 2013 25,989 4,293 47,839 38,255 December 31, 2014 29,059 4,668 51,072 42,239 December 31, 2015 25,349 4,266 39,987 36,280 |
Standardized measure of discounted future net cash flows relating to estimated proved reserves | The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2015 , 2014 and 2013 was as follows: 2015 2014 2013 (In thousands) Future cash inflows $ 1,721,207 $ 5,479,211 $ 5,162,702 Future costs: Production (711,887 ) (1,719,989 ) (1,724,560 ) Abandonment (120,737 ) (149,112 ) (131,747 ) Development (147,189 ) (695,180 ) (592,695 ) Income taxes (38,306 ) (833,601 ) (786,196 ) Future net cash flows 703,088 2,081,329 1,927,504 10% discount factor (312,445 ) (1,148,416 ) (1,000,581 ) Standardized measure of discounted net cash flows $ 390,643 $ 932,913 $ 926,923 |
Schedule of changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves | Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended December 31, 2015 , 2014 and 2013 were as follows: 2015 2014 2013 (In thousands) Standardized measure, beginning of period $ 932,913 $ 926,923 $ 939,831 Net changes in sales prices, net of production costs (965,126 ) (94,104 ) 13,292 Revisions of quantity estimates (245,035 ) (234,612 ) (10,680 ) Accretion of discount 137,998 138,095 130,736 Changes in future development costs, including development costs incurred that reduced future development costs 308,261 146,392 46,068 Changes in timing and other (69,160 ) (70,774 ) (10,249 ) Net change in income taxes 395,888 2,893 (84,673 ) Future abandonment cost, net of salvage (2,968 ) 4,066 232 Extensions and discoveries 48,367 431,895 502,619 Sales, net of production costs (126,455 ) (309,758 ) (289,035 ) Sales of minerals-in-place (24,040 ) (8,103 ) (311,218 ) Standardized measure, end of period $ 390,643 $ 932,913 $ 926,923 |
Schedule of average prices used for each commodity | The average prices used for each commodity for the years ended December 31, 2015 , 2014 and 2013 were as follows: Average Price Oil Natural Gas Liquids Natural Gas ($/Bbl) ($/Bbl) ($/Mcf) As of December 31: 2015 $ 45.75 $ 15.84 $ 2.52 2014 $ 90.48 $ 31.54 $ 4.27 2013 $ 94.88 $ 31.63 $ 3.59 |
Nature of Operations (Details)
Nature of Operations (Details) | Dec. 31, 2015 |
Nature of Operations Disclosures [Abstract] | |
Percentage of outstanding common stock beneficially owned by Mr.Williams | 25.50% |
Percentage of outstanding common stock owned by a partnership in which Mr. Williams' adult children are limited partners | 25.00% |
Summary of Significant Accoun45
Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Concentration Risk [Line Items] | |||
Debt issue costs, net | $ 9,629 | $ 12,712 | |
Capitalized interest costs | $ 300 | $ 1,000 | $ 1,400 |
Maximum | Assets, Total | Partnership Concentration Risk | |||
Concentration Risk [Line Items] | |||
The percentage of consolidated total assets and total revenues derived from oil and gas partnerships is less than | 5.00% |
Summary of Significant Accoun46
Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Pipelines and other midstream facilities | Minimum | |
Property, Plant and Equipment [Line Items] | |
Useful life | 3 years |
Pipelines and other midstream facilities | Maximum | |
Property, Plant and Equipment [Line Items] | |
Useful life | 30 years |
Building and Building Improvements | Minimum | |
Property, Plant and Equipment [Line Items] | |
Useful life | 3 years |
Building and Building Improvements | Maximum | |
Property, Plant and Equipment [Line Items] | |
Useful life | 40 years |
Long-Term Debt (Details)
Long-Term Debt (Details) | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2011USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Oct. 31, 2013USD ($) | Apr. 30, 2011USD ($) | |
Debt Instrument [Line Items] | |||||
Long-term debt | $ 749,759,000 | $ 704,696,000 | |||
7.75% Senior Notes due 2019 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | 599,759,000 | 599,696,000 | |||
Debt instrument, face amount | $ 300,000,000 | $ 250,000,000 | $ 50,000,000 | ||
Unamortized original issue discount | $ 241,000 | $ 304,000 | $ 500,000 | ||
Interest rate (as a percent) | 7.75% | 7.75% | 7.75% | ||
Original issue discount (as a percent) | 1.00% | ||||
Minimum ratio of EBITDA to consolidated interest expense | 2.25 | ||||
Aggregate commitment amount | $ 500,000,000 | ||||
Maximum borrowing capacity, percent of adjusted consolidated net tangible assets | 0.3 | ||||
Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | $ 150,000,000 | $ 105,000,000 | |||
Redemption Period Beginning April 2016 | 7.75% Senior Notes due 2019 | |||||
Debt Instrument [Line Items] | |||||
Redemption price of debt instrument (as a percent) | 101.938% | ||||
Redemption Period Beginning April 2017 | 7.75% Senior Notes due 2019 | |||||
Debt Instrument [Line Items] | |||||
Redemption price of debt instrument (as a percent) | 100.00% |
Long-Term Debt Credit Facility
Long-Term Debt Credit Facility (Details) | Mar. 08, 2016USD ($) | Apr. 30, 2014installment | Dec. 31, 2015USD ($)Bank | Mar. 09, 2016USD ($) | Dec. 31, 2014USD ($) |
Debt Instrument [Line Items] | |||||
Long-term debt | $ 749,759,000 | $ 704,696,000 | |||
Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Number of banks syndicated to provide for line of credit | Bank | 16 | ||||
Long-term debt | $ 150,000,000 | $ 105,000,000 | |||
Remaining borrowing capacity | 298,100,000 | ||||
Letters of credit outstanding, amount | $ 1,900,000 | ||||
Effective interest rate | 2.20% | ||||
Maximum | Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Deficiency prepayment, number of equal periodic installments | installment | 5 | ||||
Subsequent Event | Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Aggregate commitment amount | $ 450,000,000 | $ 100,000,000 | |||
Unused capacity, commitment fee percentage | 0.50% | ||||
Subsequent Event | Term Loan Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Current borrowing capacity | $ 350,000,000 | ||||
Subsequent Event | Minimum | Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Minimum ratio of discounted present value to debt | 1.2 | ||||
Basis spread on variable rate, additional spread | 1.50% | ||||
Covenant current ratio | 1 | ||||
Percentage of adjusted engineered value of oil and gas interests serving as collateral | 90.00% | ||||
Subsequent Event | Minimum | Term Loan Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Percentage of adjusted engineered value of oil and gas interests serving as collateral | 90.00% | ||||
Subsequent Event | Maximum | Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Higher borrowing capacity option | $ 150,000,000 | ||||
Basis spread on variable rate, additional spread | 2.50% | ||||
Covenant consolidated funded indebtedness to EBI TDA ratio | 2 | ||||
Subsequent Event | LIBOR | Minimum | Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 2.50% | ||||
Subsequent Event | LIBOR | Maximum | Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 3.50% | ||||
Subsequent Event | Federal funds rate | Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 0.50% | ||||
Subsequent Event | One-month LIBOR | Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 1.00% | ||||
Subsequent Event | Base rate | Revolving credit facility, due April 2019 | |||||
Debt Instrument [Line Items] | |||||
Interest rate, stated percentage | 0.75% |
Long-Term Debt Term Loan Credit
Long-Term Debt Term Loan Credit Facility (Details) | Mar. 15, 2016USD ($)$ / sharesshares | Mar. 08, 2016USD ($)$ / sharesshares | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Debt Instrument [Line Items] | ||||
Long-term debt | $ 749,759,000 | $ 704,696,000 | ||
Revolving Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | $ 150,000,000 | $ 105,000,000 | ||
Subsequent Event | Term Loan Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Current borrowing capacity | $ 350,000,000 | |||
Proceeds from line of credit | $ 340,000,000 | 333,200,000 | ||
Cash | 180,000,000 | |||
Unamortized original issue discount | $ 16,800,000 | |||
Interest rate, stated percentage | 12.50% | |||
Interest rate, stated percentage, in-kind | 15.00% | |||
Subsequent Event | Revolving Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Outstanding balance repaid, plus interest and fees | $ 160,000,000 | |||
Minimum | Subsequent Event | Term Loan Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Percentage of adjusted engineered value of oil and gas interests serving as collateral | 90.00% | |||
Asset to secured debt coverage ratio | 1.2 | |||
Minimum | Subsequent Event | Revolving Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Percentage of adjusted engineered value of oil and gas interests serving as collateral | 90.00% | |||
Common Stock | Subsequent Event | ||||
Debt Instrument [Line Items] | ||||
Warrants issued, in shares | shares | 2,251,364 | 2,251,364 | ||
Exercise price of warrant | $ / shares | $ 22 | $ 22 |
Sales of Assets (Details)
Sales of Assets (Details) $ in Thousands | 1 Months Ended | 6 Months Ended | 12 Months Ended | |||||||
Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Sep. 30, 2014USD ($)a | Mar. 31, 2014USD ($) | Feb. 28, 2014USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Sale Of Assets [Line Items] | ||||||||||
Sale of oil and gas, term assignment | 3 years | |||||||||
Overriding Royalty Interest Threshold, Percent of Net Revenue | 75.00% | 75.00% | ||||||||
Proceeds from sale of assets | $ 71,460 | $ 104,529 | $ 259,799 | |||||||
Gas and oil area sold | a | 7,500 | |||||||||
Net proceeds from sale of interest in wells and related leasehold interest | $ 29,300 | $ 71,000 | ||||||||
Escrow deposits related to property sales | $ 6,800 | |||||||||
Proceeds from sale of property | $ 5,100 | |||||||||
Burleson County, TX | ||||||||||
Sale Of Assets [Line Items] | ||||||||||
Net proceeds from sale of interest in wells and related leasehold interest | $ 21,800 | $ 22,100 | ||||||||
South Louisiana | ||||||||||
Sale Of Assets [Line Items] | ||||||||||
Proceeds from sale of assets | $ 11,800 | |||||||||
Wells and Related Equipment and Facilities | ||||||||||
Sale Of Assets [Line Items] | ||||||||||
Net proceeds from sale of interest in wells and related leasehold interest | $ 7,300 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Changes in asset retirement obligations | |||
Beginning of period | $ 45,697 | $ 49,981 | |
Additional ARO from new properties | 469 | 1,209 | |
Sales or abandonments of properties | (4,435) | (5,246) | |
Accretion of asset retirement obligations | 3,945 | 3,662 | $ 4,203 |
Revisions of previous estimates | 3,052 | (3,909) | |
End of period | $ 48,728 | $ 45,697 | $ 49,981 |
Deferred Revenue from Volumet52
Deferred Revenue from Volumetric Production Payment (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||
Aug. 31, 2015USD ($)MBoe | Mar. 31, 2012USD ($)MBoepartnership | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Changes in deferred revenue from the VPP | |||||
Beginning of year | $ 23,129 | $ 29,770 | |||
Proceeds from volumetric production payment | 2,866 | 1,067 | $ 1,332 | ||
Amortization of deferred revenue from VPP | (6,822) | (7,708) | (8,746) | ||
Termination of VPP | (13,703) | 0 | 0 | ||
End of year | $ 5,470 | $ 23,129 | $ 29,770 | ||
Number of limited partnerships involved in the mergers | partnership | 24 | ||||
Southwest Royalties, Inc. | Limited partnerships | |||||
Changes in deferred revenue from the VPP | |||||
Termination of VPP | $ (13,700) | ||||
Upfront cash proceeds under VPP | $ 44,400 | ||||
Deferred future advances under VPP | $ 4,700 | ||||
Barrels of oil equivalents of future oil and gas production covered by a term overriding royalty interest conveyed to a third party under the terms of the VPP (in BOE) | MBoe | 725 | ||||
Volumetric production payment terminated during period (in MBOE) | MBoe | 277 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Deferred tax assets: | ||
Net operating loss carryforwards | $ 106,992 | $ 84,587 |
Statutory depletion carryforwards | 9,809 | 9,581 |
Asset retirement obligations and other | 21,249 | 19,061 |
Deferred tax assets, gross | 138,050 | 113,229 |
Deferred tax liabilities: | ||
Property and equipment | (240,520) | (270,917) |
Net deferred tax liabilities | (102,470) | (157,688) |
Components of net deferred tax liabilities: | ||
Current assets | 6,526 | 6,911 |
Non-current liabilities | (108,996) | (164,599) |
Net deferred tax liabilities | $ (102,470) | $ (157,688) |
Income Taxes Income Taxes (Deta
Income Taxes Income Taxes (Details 2) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract] | |||
Income tax expense (benefit) at statutory rate of 35% | $ (53,667) | $ 23,999 | $ (13,052) |
Tax depletion in excess of basis | (282) | (729) | (518) |
Revision of previous tax estimates | 30 | (155) | 373 |
State income tax expense (benefit), net of federal tax effect | (1,472) | 1,008 | 76 |
Other | 252 | 564 | 693 |
Income tax expense (benefit) | (55,139) | 24,687 | (12,428) |
Current | 79 | 227 | 1,614 |
Deferred | (55,218) | 24,460 | (14,042) |
Income tax expense (benefit) | $ (55,139) | $ 24,687 | $ (12,428) |
Statutory tax rate | 35.00% | 35.00% | 35.00% |
Income Taxes Income Taxes (De55
Income Taxes Income Taxes (Details - Textuals) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Operating Loss Carryforwards [Line Items] | ||
Tax carryforward amount | $ 327,200 | |
Income tax, uncertain tax positions | 0 | $ 0 |
Stock Option Exercise Tax Benefit | ||
Operating Loss Carryforwards [Line Items] | ||
Tax carryforward amount | $ 22,000 |
Derivatives (Commodities) (Deta
Derivatives (Commodities) (Details) - Subsequent Event | Mar. 23, 2016MBbls$ / bbl | Jan. 31, 2016MBbls$ / bbl |
Derivative [Line Items] | ||
Notional Amount | 1,597 | |
Optional Extension Swap | ||
Derivative [Line Items] | ||
Notional Amount | 739 | |
Oil | Current Swap, First Quarter | Commodity Derivatives | ||
Derivative [Line Items] | ||
Notional Amount | 421 | |
Fixed Price | $ / bbl | 40.25 | |
Oil | Current Swap, Second Quarter | Commodity Derivatives | ||
Derivative [Line Items] | ||
Notional Amount | 518 | |
Fixed Price | $ / bbl | 40.47 | |
Oil | Current Swap, Third Quarter | Commodity Derivatives | ||
Derivative [Line Items] | ||
Notional Amount | 176 | |
Fixed Price | $ / bbl | 42.70 | |
Oil | Current Swap, Fourth Quarter | Commodity Derivatives | ||
Derivative [Line Items] | ||
Notional Amount | 167 | |
Fixed Price | $ / bbl | 42.70 | |
Oil | Current Swap, 2017 | Commodity Derivatives | ||
Derivative [Line Items] | ||
Notional Amount | 315 | |
Fixed Price | $ / bbl | 44.30 | |
Oil | Optional Extension Swap, Third Quarter | Commodity Derivatives | ||
Derivative [Line Items] | ||
Notional Amount | 378 | |
Fixed Price | $ / bbl | 40.25 | |
Oil | Optional Extension Swap, Fourth Quarter | Commodity Derivatives | ||
Derivative [Line Items] | ||
Notional Amount | 361 | |
Fixed Price | $ / bbl | 40.25 | |
Oil | Optional Extension Swap | Commodity Derivatives | ||
Derivative [Line Items] | ||
Notional Amount | 739 | |
Fixed Price | $ / bbl | 40.25 |
Derivatives (Details 2)
Derivatives (Details 2) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Amount of Gain or (Loss) Recognized in Earnings | |||
Gain (loss) on derivatives | $ 12,519 | $ 4,789 | $ (8,731) |
Commodity Derivatives | Nondesignated | |||
Amount of Gain or (Loss) Recognized in Earnings | |||
Gain (loss) on derivatives | $ 12,519 | $ 4,789 | $ (8,731) |
Fair Value of Financial Instr58
Fair Value of Financial Instruments (Details) - Fair Value, Inputs, Level 1 - 7.75% Senior Notes due 2019 - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Estimate of Fair Value Measurement [Member] | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ||
Long-term Debt, Fair Value | $ 462,750 | $ 510,000 |
Reported Value Measurement [Member] | ||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items] | ||
Long-term Debt, Fair Value | $ 599,759 | $ 599,696 |
Compensation Plans (Details 2)
Compensation Plans (Details 2) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | |||
Weighted average grant date fair value of options granted per share | $ 0 | $ 0 | $ 0 |
Intrinsic value of options exercised | $ 0 | $ 263 | $ 53 |
Compensation Plans (Details 3)
Compensation Plans (Details 3) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Intrinsic value of options exercised | $ 0 | $ 263 | $ 53 |
Directors Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares authorized | 86,300 | ||
Shares issued in period | 52,000 | ||
Options outstanding, expiry term | 10 years | ||
Directors Plan | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares issue price | $ 3.25 | ||
Directors Plan | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares issue price | $ 41.74 |
Compensation Plans (Details 4)
Compensation Plans (Details 4) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Jan. 31, 2007well | Dec. 31, 2015USD ($)areaaward | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Non-Equity Award Plans | ||||
Compensation expense recorded | $ (30) | $ (4,600) | $ (2,100) | |
Current liabilities: | ||||
Accrued liabilities and other | 1,251 | 2,317 | ||
Non-current liabilities: | ||||
Accrued compensation under non-equity award plans | 16,254 | 17,866 | ||
Total accrued compensation under non-equity award plans | $ 17,505 | $ 20,183 | ||
Minimum | ||||
Non-Equity Award Plans | ||||
Vesting period | 2 years | |||
Maximum | ||||
Non-Equity Award Plans | ||||
Vesting period | 5 years | |||
APO Incentive Plan | Minimum | ||||
Non-Equity Award Plans | ||||
Subsequent revenues received by participants (as a percent) | 99.00% | |||
Subsequent expenses paid by participants (as a percent) | 99.00% | |||
Economic interests in specified wells drilled or acquired as part of the plan (as a percent) | 5.00% | |||
APO Incentive Plan | Maximum | ||||
Non-Equity Award Plans | ||||
Subsequent revenues received by participants (as a percent) | 100.00% | |||
Subsequent expenses paid by participants (as a percent) | 100.00% | |||
Economic interests in specified wells drilled or acquired as part of the plan (as a percent) | 7.50% | |||
APO Reward Plan | ||||
Non-Equity Award Plans | ||||
Number of specified areas in which awards granted | area | 15 | |||
Quarterly bonus amount, percentage of after-payout cash flow from wells drilled or recompleted, one | 7.00% | |||
Quarterly bonus amount, percentage of after-payout cash flow from wells drilled or recompleted, two | 10.00% | |||
Number of award fully vested | award | 12 | |||
Quarterly Bonus Amount, Percentage Payable To Participants | 100.00% | |||
APO Reward Plan | Full vesting date, June 23, 2016 | ||||
Non-Equity Award Plans | ||||
Number of Awards Expected To Vest | award | 3 | |||
SWR Reward Plan | ||||
Non-Equity Award Plans | ||||
Percentage of working interest in well | 22.50% | |||
Number of wells, working interest | well | 1 |
Transactions with Affiliates (D
Transactions with Affiliates (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Amounts paid to the Williams Entities: | |||
Percentage of ownership of affiliates of the company in the partnership | 31.90% | ||
Percentage of owner of company in affiliated partnership | 25.80% | ||
Affiliated Entity | |||
Amounts received from the Williams Entities: | |||
Services | $ 622 | $ 663 | $ 715 |
Insurance premiums and benefits | 922 | 960 | 837 |
Reimbursed expenses | 500 | 296 | 427 |
Amount received from Williams Entities | 2,044 | 1,919 | 1,979 |
Amounts paid to the Williams Entities: | |||
Rent | 1,741 | 1,614 | 1,560 |
Business entertainment | 155 | 205 | 344 |
Reimbursed expenses | 226 | 204 | 216 |
Amounts paid to the Williams Entities | $ 2,122 | $ 2,023 | $ 2,120 |
Other Operating Revenues and 63
Other Operating Revenues and Expenses (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other operating revenues: | |||
Gain on sales of assets | $ 8,718 | $ 11,685 | $ 4,467 |
Marketing revenue | 24 | 3,708 | 2,021 |
Total other operating revenues | 8,742 | 15,393 | 6,488 |
Other operating expenses: | |||
Loss on sales of assets | 1,355 | 2,511 | 1,233 |
Marketing expense | 849 | 0 | 658 |
Impairment of inventory | 10,381 | 36 | 210 |
Other operating expenses | $ 12,585 | $ 2,547 | $ 2,101 |
Investment in Dalea Investmen64
Investment in Dalea Investment Group, LLC (Details) - Dalea Investment Group, LLC - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Jun. 30, 2012 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Investment in Dalea Investment Group, LLC | ||||
Note receivable cancelled | $ 11 | |||
Non-controlling Membership interest (as a percent) | 7.66% | |||
Recorded investment | $ 8.4 | $ 11 | ||
Cost-method Investments, Other than Temporary Impairment | $ 2.6 | $ 0 | $ 0 |
Commitments and Contingencies65
Commitments and Contingencies (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||||
Dec. 31, 2013USD ($) | Oct. 31, 2013USD ($) | Jun. 30, 2013USD ($) | Apr. 30, 2011USD ($) | Dec. 31, 2015USD ($)Drillingrigplaintiff | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||||||
2,016 | $ 601 | ||||||
2,017 | 180 | ||||||
2,018 | 18 | ||||||
Thereafter | 0 | ||||||
Total minimum lease payments | 799 | ||||||
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||||||
2,016 | 3,744 | ||||||
2,017 | 924 | ||||||
2,018 | 676 | ||||||
Thereafter | 740 | ||||||
Total minimum lease payments | 6,084 | ||||||
Non-Cancelable Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||||||
2,016 | 4,345 | ||||||
2,017 | 1,104 | ||||||
2,018 | 694 | ||||||
Thereafter | 740 | ||||||
Total minimum lease payments | 6,883 | ||||||
Operating Leases, Rent Expense | $ 1,900 | $ 1,800 | $ 1,800 | ||||
Drilling Rigs | |||||||
Non-Cancelable Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||||||
Number of drilling rigs subject to operating leases | Drillingrig | 2 | ||||||
BMT O&G TX, L.P. | |||||||
Non-Cancelable Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||||||
Loss contingency, settlement amount | $ 2,900 | ||||||
Attorney fees | $ 800 | ||||||
Loss related to litigation settlement | $ 1,400 | ||||||
Environmental Remediation Case 2001 | |||||||
Non-Cancelable Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||||||
Plaintiffs contend of cost to remediate the surface | $ 8,000 | ||||||
Loss contingency, settlement amount | $ 800 | ||||||
Loss contingency, settlement amount paid | $ 700 | $ 700 | |||||
Loss Contingency, Number of Plaintiffs | plaintiff | 1 |
Impairment of Property and Eq66
Impairment of Property and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of property and equipment | $ 41,917 | $ 12,027 | $ 89,811 |
Provisions for impairment of unproved properties | 2,800 | 15,400 | 3,400 |
Non Core Properties | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of property and equipment | 37,900 | $ 12,000 | $ 89,800 |
Drilling Rigs | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of property and equipment | $ 4,000 |
Costs of Oil and Gas Properti67
Costs of Oil and Gas Properties (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Oil and Gas Property, Successful Effort Method, Gross [Abstract] | |||
Property acquisitions, Proved | $ 0 | $ 0 | $ 0 |
Property acquisitions, Unproved | 29,711 | 56,327 | 50,104 |
Developmental costs | 81,466 | 342,716 | 218,341 |
Exploratory costs | 14,342 | 4,350 | 3,932 |
Total | $ 125,519 | $ 403,393 | $ 272,377 |
Costs of Oil and Gas Properti68
Costs of Oil and Gas Properties (Details 2) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Oil and Gas Property, Successful Effort Method, Gross [Abstract] | ||
Proved properties | $ 2,539,480 | $ 2,585,279 |
Unproved properties | 46,022 | 99,634 |
Total capitalized costs | 2,585,502 | 2,684,913 |
Accumulated depletion | (1,460,404) | (1,430,699) |
Net capitalized costs | $ 1,125,098 | $ 1,254,214 |
Segment Information (Details)
Segment Information (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)segment | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Segment Reporting [Abstract] | |||||||||||
Number of reportable operating segments | segment | 2 | ||||||||||
Segment Information | |||||||||||
Revenues | $ 40,418 | $ 54,581 | $ 73,231 | $ 64,142 | $ 94,673 | $ 119,283 | $ 129,895 | $ 124,605 | $ 232,372 | $ 468,456 | $ 429,215 |
Depreciation, depletion and amortization | 204,179 | 166,383 | 240,713 | ||||||||
Other operating expenses | 141,628 | 190,434 | 175,887 | ||||||||
Interest expense | 54,422 | 50,907 | 43,079 | ||||||||
Other (income) expense(c) | (14,522) | (7,836) | 6,826 | ||||||||
Income (loss) before income taxes | (153,335) | 68,568 | (37,290) | ||||||||
Income tax (expense) benefit | 55,139 | (24,687) | 12,428 | ||||||||
Net income (loss) | (47,209) | $ (9,423) | $ (23,332) | $ (18,232) | (4,267) | $ 27,429 | $ 9,327 | $ 11,392 | (98,196) | 43,881 | (24,862) |
Total assets | 1,294,769 | 1,510,885 | 1,294,769 | 1,510,885 | 1,366,737 | ||||||
Additions to property and equipment | 126,747 | 435,444 | 284,652 | ||||||||
Operating Segments | Oil and Gas | |||||||||||
Segment Information | |||||||||||
Revenues | 232,279 | 440,428 | 411,403 | ||||||||
Depreciation, depletion and amortization | 187,913 | 157,164 | 229,460 | ||||||||
Other operating expenses | 135,177 | 170,878 | 159,294 | ||||||||
Interest expense | 54,422 | 50,907 | 43,079 | ||||||||
Other (income) expense(c) | (17,091) | (8,001) | 6,826 | ||||||||
Income (loss) before income taxes | (128,142) | 69,480 | (27,256) | ||||||||
Income tax (expense) benefit | 46,129 | (23,384) | 9,136 | ||||||||
Net income (loss) | (82,013) | 46,096 | (18,120) | ||||||||
Total assets | 1,290,998 | 1,482,863 | 1,290,998 | 1,482,863 | 1,339,920 | ||||||
Additions to property and equipment | 124,996 | 412,951 | 280,173 | ||||||||
Operating Segments | Contract Drilling | |||||||||||
Segment Information | |||||||||||
Revenues | 2,837 | 59,107 | 37,255 | ||||||||
Depreciation, depletion and amortization | 16,832 | 13,307 | 13,844 | ||||||||
Other operating expenses | 9,178 | 41,912 | 32,817 | ||||||||
Interest expense | 0 | 0 | 0 | ||||||||
Other (income) expense(c) | 2,569 | 165 | 0 | ||||||||
Income (loss) before income taxes | (25,742) | 3,723 | (9,406) | ||||||||
Income tax (expense) benefit | 9,010 | (1,303) | 3,292 | ||||||||
Net income (loss) | (16,732) | 2,420 | (6,114) | ||||||||
Total assets | 48,943 | 70,051 | 48,943 | 70,051 | 54,697 | ||||||
Additions to property and equipment | 1,202 | 27,128 | 5,107 | ||||||||
Intercompany Eliminations | |||||||||||
Segment Information | |||||||||||
Revenues | (2,744) | (31,079) | (19,443) | ||||||||
Depreciation, depletion and amortization | (566) | (4,088) | (2,591) | ||||||||
Other operating expenses | (2,727) | (22,356) | (16,224) | ||||||||
Interest expense | 0 | 0 | 0 | ||||||||
Other (income) expense(c) | 0 | 0 | 0 | ||||||||
Income (loss) before income taxes | 549 | (4,635) | (628) | ||||||||
Income tax (expense) benefit | 0 | 0 | 0 | ||||||||
Net income (loss) | 549 | (4,635) | (628) | ||||||||
Total assets | $ (45,172) | $ (42,029) | (45,172) | (42,029) | (27,880) | ||||||
Additions to property and equipment | $ 549 | $ (4,635) | $ (628) |
Guarantor Financial Informati70
Guarantor Financial Information (Details) - 2019 Senior Notes - USD ($) | Oct. 31, 2013 | Apr. 30, 2011 | Mar. 31, 2011 |
Performance and payment guaranteed | |||
Aggregate principal amount of notes issued | $ 250,000,000 | $ 50,000,000 | $ 300,000,000 |
Guarantor Subsidiaries | Guarantee on senior notes | |||
Performance and payment guaranteed | |||
Aggregate principal amount of notes issued | $ 250,000,000 | $ 350,000,000 |
Guarantor Financial Informati71
Guarantor Financial Information (Details 2) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Condensed consolidating financial statements | ||||
Current assets | $ 68,805 | $ 132,620 | ||
Property and equipment, net | 1,201,284 | 1,348,884 | ||
Investments in subsidiaries | 0 | 0 | ||
Other Assets | 24,680 | 29,381 | ||
Total assets | 1,294,769 | 1,510,885 | $ 1,366,737 | |
Current liabilities | 65,739 | 156,353 | ||
Non-current liabilities: | ||||
Long-term debt | 749,759 | 704,696 | ||
Deferred income taxes | 108,996 | 164,599 | ||
Other | 70,677 | 87,443 | ||
TOTAL NON-CURRENT LIABILITIES | 929,432 | 956,738 | ||
Equity | 299,598 | 397,794 | $ 353,783 | $ 378,616 |
Total liabilities and equity | 1,294,769 | 1,510,885 | ||
Issuer | ||||
Condensed consolidating financial statements | ||||
Current assets | 112,861 | 153,373 | ||
Property and equipment, net | 887,313 | 986,110 | ||
Investments in subsidiaries | 328,794 | 359,777 | ||
Other Assets | 12,878 | 16,077 | ||
Total assets | 1,341,846 | 1,515,337 | ||
Current liabilities | 276,354 | 352,889 | ||
Non-current liabilities: | ||||
Long-term debt | 749,759 | 704,696 | ||
Deferred income taxes | 88,067 | 129,105 | ||
Other | 33,886 | 36,671 | ||
TOTAL NON-CURRENT LIABILITIES | 871,712 | 870,472 | ||
Equity | 193,780 | 291,976 | ||
Total liabilities and equity | 1,341,846 | 1,515,337 | ||
Guarantor Subsidiaries | ||||
Condensed consolidating financial statements | ||||
Current assets | 272,310 | 293,613 | ||
Property and equipment, net | 308,738 | 344,174 | ||
Investments in subsidiaries | 0 | 0 | ||
Other Assets | 11,802 | 13,304 | ||
Total assets | 592,850 | 651,091 | ||
Current liabilities | 102,267 | 113,746 | ||
Non-current liabilities: | ||||
Long-term debt | 0 | 0 | ||
Deferred income taxes | 132,204 | 141,130 | ||
Other | 36,539 | 50,591 | ||
TOTAL NON-CURRENT LIABILITIES | 168,743 | 191,721 | ||
Equity | 321,840 | 345,624 | ||
Total liabilities and equity | 592,850 | 651,091 | ||
Non-Guarantor Subsidiary | ||||
Condensed consolidating financial statements | ||||
Current assets | 1,441 | 546 | ||
Property and equipment, net | 5,233 | 18,600 | ||
Investments in subsidiaries | 0 | 0 | ||
Other Assets | 0 | 0 | ||
Total assets | 6,674 | 19,146 | ||
Current liabilities | 117 | 586 | ||
Non-current liabilities: | ||||
Long-term debt | 0 | 0 | ||
Deferred income taxes | (649) | 4,227 | ||
Other | 252 | 181 | ||
TOTAL NON-CURRENT LIABILITIES | (397) | 4,408 | ||
Equity | 6,954 | 14,152 | ||
Total liabilities and equity | 6,674 | 19,146 | ||
Adjustments/ Eliminations | ||||
Condensed consolidating financial statements | ||||
Current assets | (317,807) | (314,912) | ||
Property and equipment, net | 0 | 0 | ||
Investments in subsidiaries | (328,794) | (359,777) | ||
Other Assets | 0 | 0 | ||
Total assets | (646,601) | (674,689) | ||
Current liabilities | (312,999) | (310,868) | ||
Non-current liabilities: | ||||
Long-term debt | 0 | 0 | ||
Deferred income taxes | (110,626) | (109,863) | ||
Other | 0 | 0 | ||
TOTAL NON-CURRENT LIABILITIES | (110,626) | (109,863) | ||
Equity | (222,976) | (253,958) | ||
Total liabilities and equity | $ (646,601) | $ (674,689) |
Guarantor Financial Informati72
Guarantor Financial Information (Details 3) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Condensed consolidating financial statements | |||||||||||
Total revenue | $ 40,418 | $ 54,581 | $ 73,231 | $ 64,142 | $ 94,673 | $ 119,283 | $ 129,895 | $ 124,605 | $ 232,372 | $ 468,456 | $ 429,215 |
Costs and expenses | 345,807 | 356,817 | 416,600 | ||||||||
Operating income | (62,456) | (19,739) | (11,058) | (20,182) | (3,244) | 45,565 | 34,739 | 34,579 | (113,435) | 111,639 | 12,615 |
Other income (expense) | (39,900) | (43,071) | (49,905) | ||||||||
Equity in earnings of subsidiaries | 0 | 0 | 0 | ||||||||
Income tax (expense) benefit | 55,139 | (24,687) | 12,428 | ||||||||
NET INCOME (LOSS) | $ (47,209) | $ (9,423) | $ (23,332) | $ (18,232) | $ (4,267) | $ 27,429 | $ 9,327 | $ 11,392 | (98,196) | 43,881 | (24,862) |
Issuer | |||||||||||
Condensed consolidating financial statements | |||||||||||
Total revenue | 169,705 | 324,055 | 280,423 | ||||||||
Costs and expenses | 244,187 | 242,658 | 302,898 | ||||||||
Operating income | (74,482) | 81,397 | (22,475) | ||||||||
Other income (expense) | (41,187) | (45,538) | (50,601) | ||||||||
Equity in earnings of subsidiaries | (24,483) | 21,261 | 23,261 | ||||||||
Income tax (expense) benefit | 41,956 | (13,239) | 24,953 | ||||||||
NET INCOME (LOSS) | (98,196) | 43,881 | (24,862) | ||||||||
Guarantor Subsidiaries | |||||||||||
Condensed consolidating financial statements | |||||||||||
Total revenue | 61,224 | 140,857 | 146,556 | ||||||||
Costs and expenses | 87,008 | 111,750 | 112,441 | ||||||||
Operating income | (25,784) | 29,107 | 34,115 | ||||||||
Other income (expense) | (808) | 919 | (25) | ||||||||
Equity in earnings of subsidiaries | 0 | 0 | 0 | ||||||||
Income tax (expense) benefit | 9,307 | (10,509) | (11,931) | ||||||||
NET INCOME (LOSS) | (17,285) | 19,517 | 22,159 | ||||||||
Non-Guarantor Subsidiary | |||||||||||
Condensed consolidating financial statements | |||||||||||
Total revenue | 1,443 | 3,544 | 2,236 | ||||||||
Costs and expenses | 14,612 | 2,409 | 1,261 | ||||||||
Operating income | (13,169) | 1,135 | 975 | ||||||||
Other income (expense) | 2,095 | 1,548 | 721 | ||||||||
Equity in earnings of subsidiaries | 0 | 0 | 0 | ||||||||
Income tax (expense) benefit | 3,876 | (939) | (594) | ||||||||
NET INCOME (LOSS) | (7,198) | 1,744 | 1,102 | ||||||||
Adjustments/ Eliminations | |||||||||||
Condensed consolidating financial statements | |||||||||||
Total revenue | 0 | 0 | 0 | ||||||||
Costs and expenses | 0 | 0 | 0 | ||||||||
Operating income | 0 | 0 | 0 | ||||||||
Other income (expense) | 0 | 0 | 0 | ||||||||
Equity in earnings of subsidiaries | 24,483 | (21,261) | (23,261) | ||||||||
Income tax (expense) benefit | 0 | 0 | 0 | ||||||||
NET INCOME (LOSS) | $ 24,483 | $ (21,261) | $ (23,261) |
Guarantor Financial Informati73
Guarantor Financial Information (Details 4) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Condensed consolidating financial statements | |||
Operating activities | $ 52,159 | $ 258,121 | $ 220,576 |
Investing activities | (117,395) | (318,997) | (29,043) |
Financing activities | 45,000 | 62,269 | (175,636) |
Net increase (decrease) in cash and cash equivalents | (20,236) | 1,393 | 15,897 |
Beginning of period | 28,016 | 26,623 | 10,726 |
End of period | 7,780 | 28,016 | 26,623 |
Issuer | |||
Condensed consolidating financial statements | |||
Operating activities | 61,138 | 178,769 | 128,146 |
Investing activities | (113,543) | (274,629) | 10,544 |
Financing activities | 35,851 | 97,384 | (125,027) |
Net increase (decrease) in cash and cash equivalents | (16,554) | 1,524 | 13,663 |
Beginning of period | 21,217 | 19,693 | 6,030 |
End of period | 4,663 | 21,217 | 19,693 |
Guarantor Subsidiaries | |||
Condensed consolidating financial statements | |||
Operating activities | 836 | 69,543 | 87,433 |
Investing activities | (15,143) | (34,749) | (34,121) |
Financing activities | 9,469 | (34,987) | (51,122) |
Net increase (decrease) in cash and cash equivalents | (4,838) | (193) | 2,190 |
Beginning of period | 6,693 | 6,886 | 4,696 |
End of period | 1,855 | 6,693 | 6,886 |
Non-Guarantor Subsidiary | |||
Condensed consolidating financial statements | |||
Operating activities | (10,381) | 5,842 | 2,406 |
Investing activities | 11,857 | (5,652) | (2,875) |
Financing activities | (320) | (128) | 513 |
Net increase (decrease) in cash and cash equivalents | 1,156 | 62 | 44 |
Beginning of period | 106 | 44 | 0 |
End of period | 1,262 | 106 | 44 |
Adjustments/ Eliminations | |||
Condensed consolidating financial statements | |||
Operating activities | 566 | 3,967 | 2,591 |
Investing activities | (566) | (3,967) | (2,591) |
Financing activities | 0 | 0 | 0 |
Net increase (decrease) in cash and cash equivalents | 0 | 0 | 0 |
Beginning of period | 0 | 0 | 0 |
End of period | $ 0 | $ 0 | $ 0 |
Subsequent Events (Details)
Subsequent Events (Details) - USD ($) | Mar. 15, 2016 | Mar. 08, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Subsequent Event [Line Items] | ||||
Preferred stock, par value (in dollars per share) | $ 0.10 | $ 0.10 | ||
Subsequent Event | ||||
Subsequent Event [Line Items] | ||||
Number of Board Members | 2 | |||
Term Loan Credit Facility | Subsequent Event | ||||
Subsequent Event [Line Items] | ||||
Current borrowing capacity | $ 350,000,000 | |||
Unamortized original issue discount | 16,800,000 | |||
Proceeds from line of credit | $ 340,000,000 | $ 333,200,000 | ||
Common Stock | Subsequent Event | ||||
Subsequent Event [Line Items] | ||||
Warrants issued, in shares | 2,251,364 | 2,251,364 | ||
Exercise price of warrant | $ 22 | $ 22 | ||
Warrant percentage of outstanding common shares | 18.50% | |||
Warrant percentage of outstanding common shares, as converted | 15.60% | |||
Preferred Stock | Subsequent Event | ||||
Subsequent Event [Line Items] | ||||
Preferred stock, par value (in dollars per share) | $ 0.10 | |||
Shares issued to warrant holders during period | 3,500 |
Supplemental Quarterly Financ75
Supplemental Quarterly Financial Information (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total revenue | $ 40,418 | $ 54,581 | $ 73,231 | $ 64,142 | $ 94,673 | $ 119,283 | $ 129,895 | $ 124,605 | $ 232,372 | $ 468,456 | $ 429,215 |
Operating income | (62,456) | (19,739) | (11,058) | (20,182) | (3,244) | 45,565 | 34,739 | 34,579 | (113,435) | 111,639 | 12,615 |
Net income (loss) | $ (47,209) | $ (9,423) | $ (23,332) | $ (18,232) | $ (4,267) | $ 27,429 | $ 9,327 | $ 11,392 | $ (98,196) | $ 43,881 | $ (24,862) |
Net income (loss) per common share: | |||||||||||
Basic (in dollars per share) | $ (3.88) | $ (0.77) | $ (1.92) | $ (1.50) | $ (0.35) | $ 2.25 | $ 0.77 | $ 0.94 | $ (8.07) | $ 3.61 | $ (2.04) |
Diluted (in dollars per share) | $ (3.88) | $ (0.77) | $ (1.92) | $ (1.50) | $ (0.35) | $ 2.25 | $ 0.77 | $ 0.94 | $ (8.07) | $ 3.61 | $ (2.04) |
Weighted average common shares outstanding: | |||||||||||
Basic (in shares) | 12,170 | 12,170 | 12,170 | 12,170 | 12,170 | 12,166 | 12,166 | 12,166 | 12,170 | 12,167 | 12,165 |
Diluted (in shares) | 12,170 | 12,170 | 12,170 | 12,170 | 12,170 | 12,166 | 12,166 | 12,166 | 12,170 | 12,167 | 12,165 |
Supplemental Oil and Gas Rese76
Supplemental Oil and Gas Reserve Information (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands | 12 Months Ended | ||
Dec. 31, 2015MBoeMBblsMMcf | Dec. 31, 2014MBoeMBblsMMcf | Dec. 31, 2013MBoeMBblsMMcf | |
Reserve Quantities [Line Items] | |||
Proved Developed and Undeveloped Reserves, Net (BOE) (at beginning) | MBoe | 75,430 | 70,015 | 75,357 |
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions (BOE) | MBoe | 3,542 | 23,336 | 27,666 |
Proved Developed and Undeveloped Reserves, Downward Revisions of Previous Estimates (MBOE) | MBoe | (26,158) | (10,101) | (901) |
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place (BOE) | MBoe | (472) | (2,057) | (26,852) |
Proved Developed and Undeveloped Reserves, Production (BOE) | MBoe | (5,773) | (5,763) | (5,255) |
Proved Developed and Undeveloped Reserves, Net (BOE) (at end) | MBoe | 46,569 | 75,430 | 70,015 |
Proved Developed Reserves (BOE) | MBoe | 36,280 | 42,239 | 38,255 |
Proved Developed And Undeveloped Reserves, Downward Revisions Of Previous Estimates Related To Reclassifications Caused By SEC Development Guidelines | MBoe | 9,561 | ||
Proved developed and undeveloped reserves, downward revisions of previous estimates attributable to well performance | MBoe | 11,963 | ||
Proved Developed and Undeveloped Reserves, Downward Revisions of Previous Estimates Attributable to Effects of Lower Commodity Prices | MBoe | 28,560 | ||
Oil | |||
Reserve Quantities [Line Items] | |||
Proved developed and undeveloped reserves, net (at beginning) | 53,867 | 48,665 | 49,119 |
Extensions and discoveries | 2,669 | 19,032 | 20,540 |
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | (18,912) | (7,786) | 85 |
Sales of minerals-in-place | (291) | (1,850) | (17,387) |
Production | (4,257) | (4,194) | (3,692) |
Proved developed and undeveloped reserves, net (at end) | 33,076 | 53,867 | 48,665 |
Proved Developed Reserves (Volume) | 25,349 | 29,059 | 25,989 |
Natural Gas Liquids | |||
Reserve Quantities [Line Items] | |||
Proved developed and undeveloped reserves, net (at beginning) | 8,967 | 8,487 | 9,182 |
Extensions and discoveries | 407 | 2,298 | 3,562 |
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | (3,344) | (1,160) | 1,806 |
Sales of minerals-in-place | (12) | (73) | (5,531) |
Production | (550) | (585) | (532) |
Proved developed and undeveloped reserves, net (at end) | 5,468 | 8,967 | 8,487 |
Proved Developed Reserves (Volume) | 4,266 | 4,668 | 4,293 |
Natural Gas | |||
Reserve Quantities [Line Items] | |||
Proved developed and undeveloped reserves, net (at beginning) | MMcf | 75,575 | 77,179 | 102,336 |
Extensions and discoveries | MMcf | 2,796 | 12,034 | 21,389 |
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MMcf | (23,414) | (6,934) | (16,753) |
Sales of minerals-in-place | MMcf | (1,016) | (803) | (23,605) |
Production | MMcf | (5,794) | (5,901) | (6,188) |
Proved developed and undeveloped reserves, net (at end) | MMcf | 48,147 | 75,575 | 77,179 |
Proved Developed Reserves (Volume) | MMcf | 39,987 | 51,072 | 47,839 |
Supplemental Oil and Gas Rese77
Supplemental Oil and Gas Reserve Information (Details 1) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract] | ||||
Future cash inflows | $ 1,721,207 | $ 5,479,211 | $ 5,162,702 | |
Future costs, production | (711,887) | (1,719,989) | (1,724,560) | |
Future costs, abandonment | (120,737) | (149,112) | (131,747) | |
Future costs, development | (147,189) | (695,180) | (592,695) | |
Future costs, income taxes | (38,306) | (833,601) | (786,196) | |
Future net cash flows | 703,088 | 2,081,329 | 1,927,504 | |
10% discount factor | (312,445) | (1,148,416) | (1,000,581) | |
Standardized measure of discounted net cash flows | $ 390,643 | $ 932,913 | $ 926,923 | $ 939,831 |
Supplemental Oil and Gas Rese78
Supplemental Oil and Gas Reserve Information (Details 2) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized measure, beginning of period | $ 932,913 | $ 926,923 | $ 939,831 |
Net changes in sales prices, net of production costs | (965,126) | (94,104) | 13,292 |
Revisions of quantity estimates | (245,035) | (234,612) | (10,680) |
Accretion of discount | 137,998 | 138,095 | 130,736 |
Changes in future development costs, including development costs incurred that reduced future development costs | 308,261 | 146,392 | 46,068 |
Changes in timing and other | (69,160) | (70,774) | (10,249) |
Net change in income taxes | 395,888 | 2,893 | (84,673) |
Future abandonment cost, net of salvage | (2,968) | 4,066 | 232 |
Extensions and discoveries | 48,367 | 431,895 | 502,619 |
Sales, net of production costs | (126,455) | (309,758) | (289,035) |
Sales of minerals-in-place | (24,040) | (8,103) | (311,218) |
Standardized measure, end of period | $ 390,643 | $ 932,913 | $ 926,923 |
Supplemental Oil and Gas Rese79
Supplemental Oil and Gas Reserve Information (Details 3) | 12 Months Ended | ||
Dec. 31, 2015$ / bbl$ / Mcf | Dec. 31, 2014$ / bbl$ / Mcf | Dec. 31, 2013$ / bbl$ / Mcf | |
Oil | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sales price | 45.75 | 90.48 | 94.88 |
Natural Gas Liquids | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sales price | 15.84 | 31.54 | 31.63 |
Natural Gas | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sales price | $ / Mcf | 2.52 | 4.27 | 3.59 |