Document and Entity Information
Document and Entity Information Document - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 17, 2016 | Jun. 30, 2015 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | SM Energy Co | ||
Entity Central Index Key | 893,538 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Common Stock, Shares, Outstanding | 68,077,546 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 3,080,022,459 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |
ASSETS | |||
Cash and cash equivalents | $ 18 | $ 120 | |
Accounts receivable (Note 2) | 134,124 | 322,630 | |
Derivative asset | 367,710 | 402,668 | |
Prepaid expenses and other | 17,137 | 19,625 | |
Total current assets | 518,989 | 745,043 | |
Proved oil and gas properties | 7,606,405 | 7,348,436 | |
Less - accumulated depletion, depreciation, and amortization | (3,481,836) | (3,233,012) | |
Unproved oil and gas properties | 284,538 | 532,498 | |
Wells in Progress | 387,432 | 503,734 | |
Oil and gas properties held for sale, net of accumulated depletion, depreciation, and amortization of $0 and $22,482, respectively | 641 | 17,891 | |
Other property and equipment, net of accumulated depreciation of $47,979 and $37,079, respectively | 153,100 | 334,356 | |
Total property and equipment, net | 4,950,280 | 5,503,903 | |
Derivative asset | 120,701 | 189,540 | |
Other noncurrent assets | 31,673 | 44,659 | |
Total other noncurrent assets | 152,374 | 234,199 | |
Total Assets | 5,621,643 | 6,483,145 | |
LIABILITIES | |||
Accounts payable and accrued expenses (note 2) | 302,517 | 640,684 | |
Derivative liability | 8 | 0 | |
Deferred tax liability | 0 | 142,976 | |
Other current liabilities | 0 | 1,000 | |
Total current liabilities | 302,525 | 784,660 | |
Revolving credit facility | 202,000 | 166,000 | |
Senior Notes, net of unamortized deferred financing costs (note 5) | 2,315,970 | 2,166,445 | [1] |
Asset retirement obligation | 137,525 | 120,867 | |
Net Profits Plan liability | 7,611 | 27,136 | |
Deferred income taxes | 758,279 | 891,681 | |
Derivative liability | 0 | 70 | |
Other noncurrent liabilities | 45,332 | 39,631 | |
Total noncurrent liabilities | $ 3,466,717 | $ 3,411,830 | |
Commitments and contingencies (note 6) | |||
STOCKHOLDERS' EQUITY | |||
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 68,075,700 and 67,463,060 shares, respectively | $ 681 | $ 675 | |
Additional paid-in capital | 305,607 | 283,295 | |
Retained earnings | 1,559,515 | 2,013,997 | |
Accumulated other comprehensive loss | (13,402) | (11,312) | |
Total stockholders' equity | 1,852,401 | 2,286,655 | |
Total Liabilities and Stockholders' Equity | $ 5,621,643 | $ 6,483,145 | |
[1] | Prior period amounts have been reclassified to conform to the current period presentation on the accompanying balance sheets. Please refer to the section Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional discussion. |
CONSOLIDATED BALANCE SHEETS Par
CONSOLIDATED BALANCE SHEETS Parenthetical - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion and Amortization | $ 3,481,836 | $ 3,233,012 |
Property, Plant and Equipment, Other, Accumulated Depreciation | $ 32,956 | $ 37,079 |
Common Stock, Par Value Per Share | $ 0.01 | $ 0.01 |
Common Stock, Shares Authorized | 200,000,000 | 200,000,000 |
Common Stock, Shares, Issued | 68,075,700 | 67,463,060 |
Common Stock, Shares, Outstanding | 68,075,700 | 67,463,060 |
Assets Held-for-sale [Member] | ||
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion and Amortization | $ 0 | $ 22,482 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating revenues: | |||
Oil, gas, and NGL production revenue | $ 1,499,905 | $ 2,481,544 | $ 2,199,550 |
Net gain on divestiture activity (note 3) | 43,031 | 646 | 27,974 |
Marketed gas system revenue | 9,485 | 24,897 | 60,039 |
Other operating revenues | 4,544 | 15,220 | 5,811 |
Total operating revenues and other income | 1,556,965 | 2,522,307 | 2,293,374 |
Operating Expenses | |||
Oil, gas, and NGL production expense | 723,633 | 715,878 | 597,045 |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 921,009 | 767,532 | 822,872 |
Exploration | 120,569 | 129,857 | 74,104 |
Impairment of proved properties | 468,679 | 84,480 | 172,641 |
Abandonment and impairment of unproved properties | 78,643 | 75,638 | 46,105 |
Impairment of other property and equipment | 49,369 | 0 | 0 |
General and administrative | 157,668 | 167,103 | 149,551 |
Change In Net Profits Plan Liability | (19,525) | (29,849) | (21,842) |
Derivative gain | (408,831) | (583,264) | (3,080) |
Marketed gas system expense | 13,922 | 24,460 | 57,647 |
Other operating expenses | 30,612 | 4,658 | 30,076 |
Total operating expenses | 2,135,748 | 1,356,493 | 1,925,119 |
Income (loss) from operations | (578,783) | 1,165,814 | 368,255 |
Non-operating income (expense): | |||
Other, net | 649 | (2,561) | 67 |
Interest expense | (128,149) | (98,554) | (89,711) |
Loss on extinguishment of debt | (16,578) | 0 | 0 |
Income (loss) before income taxes | (722,861) | 1,064,699 | 278,611 |
Income tax (expense) benefit | 275,151 | (398,648) | (107,676) |
Net income (loss) | $ (447,710) | $ 666,051 | $ 170,935 |
Earnings Per Share, Basic [Abstract] | |||
Basic weighted-average common shares outstanding | 67,723 | 67,230 | 66,615 |
Basic net income (loss) per common share | $ (6.61) | $ 9.91 | $ 2.57 |
Earnings Per Share, Diluted [Abstract] | |||
Diluted weighted-average common shares outstanding | 67,723 | 68,044 | 67,998 |
Diluted net income (loss) per common share | $ (6.61) | $ 9.79 | $ 2.51 |
CONSOLIDATED STATEMENT OF COMPR
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Statement of Comprehensive Income [Abstract] | ||||
Net income (loss) | $ (447,710) | $ 666,051 | $ 170,935 | |
Reclassification to earnings | [1] | 0 | 0 | 1,115 |
Pension liability adjustment | [2] | (2,090) | (5,896) | 2,483 |
Total other comprehensive income (loss), net of tax | (2,090) | (5,896) | 3,598 | |
Total comprehensive income (loss) | $ (449,800) | $ 660,155 | $ 174,533 | |
[1] | Reclassification from accumulated other comprehensive loss related to de-designated hedges. Refer to Note 10 - Derivative Financial Instruments for further information. | |||
[2] | Refer to Note 1 - Summary of Significant Accounting Policies for detail of the pension amount reclassified to general and administrative expense on the Company’s consolidated statements of operations. |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) |
Common Stock, Dividends, Per Share, Declared | $ 0.10 | |||||
Balances, Common Shares, Beginning at Dec. 31, 2012 | 66,245,816 | |||||
Balances, Beginning at Dec. 31, 2012 | $ 1,414,466 | $ 662 | $ 233,642 | $ 1,190,397 | $ (9,014) | |
Balances, Treasury Shares, Beginning at Dec. 31, 2012 | (50,581) | |||||
Balances, Treasury Stock, Value, Beginning at Dec. 31, 2012 | $ (1,221) | |||||
Increase (Decrease) in Stockholders' Equity | ||||||
Net income (loss) | 170,935 | 170,935 | ||||
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | 3,598 | 3,598 | ||||
Cash dividends, $ 0.10 per share | (6,663) | (6,663) | ||||
Issuance of common stock under Employee Stock Purchase Plan (in shares) | 77,427 | |||||
Issuance of common stock under Employee Stock Purchase Plan | 3,672 | $ 1 | 3,671 | |||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (in shares) | 526,852 | |||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings | $ (16,220) | $ 5 | (16,225) | |||
Issuance of common stock upon stock option exercises (in shares) | 228,758 | 228,758 | ||||
Issuance of common stock upon stock option exercises | $ 3,186 | $ 3 | 3,183 | |||
Stock-based compensation expense (in shares) | 0 | 28,169 | ||||
Stock-based compensation expense | 32,347 | $ 0 | 31,949 | $ 398 | ||
Other income tax benefit (expense) | 1,500 | 1,500 | ||||
Balances, Common Shares, Ending at Dec. 31, 2013 | 67,078,853 | |||||
Balances, Ending at Dec. 31, 2013 | $ 1,606,821 | $ 671 | 257,720 | 1,354,669 | (5,416) | |
Balances, Treasury Shares, Ending at Dec. 31, 2013 | (22,412) | |||||
Balances, Treasury Stock, Value, Ending at Dec. 31, 2013 | $ (823) | |||||
Common Stock, Dividends, Per Share, Declared | $ 0.10 | |||||
Increase (Decrease) in Stockholders' Equity | ||||||
Net income (loss) | $ 666,051 | 666,051 | ||||
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | (5,896) | (5,896) | ||||
Cash dividends, $ 0.10 per share | (6,723) | (6,723) | ||||
Issuance of common stock under Employee Stock Purchase Plan (in shares) | 83,136 | |||||
Issuance of common stock under Employee Stock Purchase Plan | 4,061 | $ 1 | 4,060 | |||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (in shares) | 256,718 | |||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings | $ (10,624) | $ 3 | (10,627) | |||
Issuance of common stock upon stock option exercises (in shares) | 39,088 | 39,088 | ||||
Issuance of common stock upon stock option exercises | $ 816 | $ 0 | 816 | |||
Stock-based compensation expense (in shares) | 5,265 | 22,412 | ||||
Stock-based compensation expense | 32,694 | $ 0 | 31,871 | $ 823 | ||
Other income tax benefit (expense) | (545) | (545) | ||||
Balances, Common Shares, Ending at Dec. 31, 2014 | 67,463,060 | |||||
Balances, Ending at Dec. 31, 2014 | $ 2,286,655 | $ 675 | 283,295 | 2,013,997 | (11,312) | |
Balances, Treasury Shares, Ending at Dec. 31, 2014 | 0 | |||||
Balances, Treasury Stock, Value, Ending at Dec. 31, 2014 | $ 0 | |||||
Common Stock, Dividends, Per Share, Declared | $ 0.10 | |||||
Increase (Decrease) in Stockholders' Equity | ||||||
Net income (loss) | $ (447,710) | (447,710) | ||||
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | (2,090) | (2,090) | ||||
Cash dividends, $ 0.10 per share | (6,772) | (6,772) | ||||
Issuance of common stock under Employee Stock Purchase Plan (in shares) | 197,214 | |||||
Issuance of common stock under Employee Stock Purchase Plan | 4,844 | $ 2 | 4,842 | |||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (in shares) | 375,523 | |||||
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings | (8,678) | $ 4 | (8,682) | |||
Stock-based compensation expense (in shares) | 39,903 | 0 | ||||
Stock-based compensation expense | 27,467 | $ 0 | 27,467 | $ 0 | ||
Other income tax benefit (expense) | (1,315) | (1,315) | ||||
Balances, Common Shares, Ending at Dec. 31, 2015 | 68,075,700 | |||||
Balances, Ending at Dec. 31, 2015 | $ 1,852,401 | $ 681 | $ 305,607 | $ 1,559,515 | $ (13,402) | |
Balances, Treasury Shares, Ending at Dec. 31, 2015 | 0 | |||||
Balances, Treasury Stock, Value, Ending at Dec. 31, 2015 | $ 0 |
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) | $ (447,710) | $ 666,051 | $ 170,935 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Net gain on divestiture activity | (43,031) | (646) | (27,974) |
Depletion, depreciation, amortization, and asset retirement obligation liability accretion | 921,009 | 767,532 | 822,872 |
Exploratory dry hole expense | 36,612 | 44,427 | 5,846 |
Impairment of proved properties | 468,679 | 84,480 | 172,641 |
Abandonment and impairment of unproved properties | 78,643 | 75,638 | 46,105 |
Impairment of other property and equipment | 49,369 | 0 | 0 |
Stock-based compensation expense | 27,467 | 32,694 | 32,347 |
Change In Net Profits Plan Liability | (19,525) | (29,849) | (21,842) |
Derivative gain | (408,831) | (583,264) | (3,080) |
Derivative settlement gain | 512,566 | 12,615 | 22,062 |
Amortization of deferred financing costs | 7,710 | 6,146 | 5,390 |
Non-cash loss on extinguishment of debt | 4,123 | 0 | 0 |
Deferred income taxes | (276,722) | 397,780 | 105,555 |
Plugging and abandonment | (7,496) | (8,796) | (9,946) |
Other, net | 13,761 | 1,069 | 2,775 |
Changes in current assets and liabilities: | |||
Accounts receivable | 140,200 | 24,088 | (79,398) |
Prepaid expenses and other | 2,563 | (1,822) | 98 |
Accounts payable and accrued expenses | (86,267) | 9,466 | 91,516 |
Accrued derivative settlements | 5,232 | (41,034) | 2,612 |
Net Cash Provided by Operating Activities | 978,352 | 1,456,575 | 1,338,514 |
Cash flows from investing activities: | |||
Net proceeds from the sale of oil and gas properties | 357,938 | 43,858 | 424,849 |
Capital expenditures | (1,493,608) | (1,974,798) | (1,553,536) |
Acquisition of proved and unproved oil and gas properties | (7,984) | (544,553) | (61,603) |
Other, net | (985) | (3,256) | (2,613) |
Net Cash Used in Investing Activities | (1,144,639) | (2,478,749) | (1,192,903) |
Cash flows from financing activities: | |||
Proceeds from credit facility | 1,872,500 | 1,285,500 | 1,203,000 |
Repayment of credit facility | (1,836,500) | (1,119,500) | (1,543,000) |
Debt issuance costs related to credit facility | 0 | (3,388) | (3,444) |
Net proceeds from Senior Notes | 490,951 | 589,991 | 490,185 |
Repayment of Senior Notes | 350,000 | 0 | 0 |
Proceeds from sale of common stock | 4,844 | 4,877 | 6,858 |
Dividends paid | (6,772) | (6,723) | (6,663) |
Net share settlement from issuance of stock awards | (8,678) | (10,624) | (16,220) |
Other, net | (160) | (87) | (5) |
Net Cash Provided by Financing Activities | 166,185 | 740,046 | 130,711 |
Net change in cash and cash equivalents | (102) | (282,128) | 276,322 |
Cash and cash equivalents at beginning of period | 120 | 282,248 | 5,926 |
Cash and cash equivalents at end of period | 18 | 120 | 282,248 |
Supplemental schedule of additional cash flow information and non-cash activities: | |||
Cash paid for interest, net of capitalized interest | 126,988 | 89,145 | 70,702 |
Net cash paid (refunded) for income taxes | $ 1,630 | $ 1,936 | $ (204) |
CONSOLIDATED STATEMENTS OF CAS8
CONSOLIDATED STATEMENTS OF CASH FLOWS Parenthetical - USD ($) $ in Thousands | 3 Months Ended | ||||
Jun. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Significant Noncash Transactions [Line Items] | |||||
Capital Expenditures Incurred but Not yet Paid - Instant | $ 97,355 | $ 357,156 | |||
Accounts Payable and Accrued Liabilities [Member] | |||||
Other Significant Noncash Transactions [Line Items] | |||||
Capital Expenditures Incurred but Not yet Paid - Instant | $ 97,400 | $ 357,200 | $ 217,800 | ||
Rocky Mountain Acquisition 2014 [Member] | |||||
Other Significant Noncash Transactions [Line Items] | |||||
Noncash or Part Noncash Acquisition, Net Nonmonetary Assets Acquired (Liabilities Assumed) | $ 6,200 | ||||
Rocky Mountain Non-Cash Asset Trade 2013 [Member] | |||||
Other Significant Noncash Transactions [Line Items] | |||||
Noncash or Part Noncash Acquisition, Net Nonmonetary Assets Acquired (Liabilities Assumed) | $ 25,000 |
Summary of Significant Accounti
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Basis of Presentation and Significant Accounting Policies [Abstract] | |
Basis of Presentation and Significant Accounting Policies [Text Block] | Note 1 – Summary of Significant Accounting Policies Description of Operations SM Energy Company is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil and condensate, natural gas, and NGLs in onshore North America. Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Subsidiaries that the Company does not control are accounted for using the equity or cost methods as appropriate. Equity method investments are included in other noncurrent assets in the accompanying consolidated balance sheets (“accompanying balance sheets”). Intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2015 , through the filing date of this report. Certain prior period amounts have been reclassified to conform to the current period presentation on the accompanying financial statements. Please refer to the caption Recently Issued Accounting Standards below for additional discussion of the change in presentation of debt issuance costs on the accompanying balance sheets. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization expense, impairment of proved properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements. Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. Accounts Receivable The Company’s accounts receivable consist mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months and the Company has had minimal bad debts. Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. The Company’s allowance for doubtful accounts as of December 31, 2015 , totaled $1.1 million , primarily for receivables from joint interest owners. The Company had no allowance for doubtful accounts as of December 31, 2014 . Concentration of Credit Risk and Major Customers The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to regular review. The Company does not believe the loss of any single purchaser would materially impact its operating results, as crude oil, natural gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating regions. During 2015 and 2014, the Company had one major customer, which represented approximately 21 percent and 19 percent , respectively, of total production revenue, which is discussed in the next paragraph. During 2015 and 2014 , the Company also sold to four entities that are under common ownership. In aggregate, these four entities represented approximately 10 percent and 14 percent of total production revenue in 2015 and 2014 , respectively; however, none of these entities individually represented more than 10 percent of total production revenue. Additionally, in 2015 the Company sold to three entities that are under common ownership, which in aggregate represented 11 percent of its total production revenue; however, none of these entities individually represented more than 10 percent of the Company’s total production revenue. During 2013 , the Company had three major customers, which represented approximately 26 percent , 16 percent , and 12 percent , respectively, of total production revenue. During the third quarter of 2013, the Company entered into various marketing agreements with a joint venture partner, whereby the Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. While the Company’s joint venture partner is the first purchaser under these contracts, representing 21 percent and 19 percent of total production revenue in 2015 and 2014 , respectively, the Company also shares with them the risk of non-performance by their counterparty purchasers. Several of the Company’s joint venture partner’s counterparty purchasers under these contracts are also direct purchasers of products produced by the Company from other operated areas. The Company’s policy is to use the commodity affiliates of the lenders under its credit facility as its derivative counterparties, and each counterparty must have investment grade senior unsecured debt ratings. Each of the Company’s 10 counterparties meet both of these requirements as of the filing date of this report. The Company has accounts in the following locations with a national bank: Denver, Colorado ; Houston, Texas ; Midland, Texas ; and Billings, Montana . The Company’s policy is to invest in highly-rated instruments and to limit the amount of credit exposure at each individual institution. Oil and Gas Producing Activities The Company accounts for its oil and gas exploration and development costs using the successful efforts method. G&G costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures within the accompanying statements of cash flows. The costs of development wells are capitalized whether those wells are successful or unsuccessful. DD&A of capitalized costs related to proved oil and gas properties is calculated on a pool-by-pool basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. As of December 31, 2015 , and 2014 , the estimated salvage value of the Company’s equipment was $29.7 million and $50.8 million , respectively. Assets Held for Sale Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presented on the accompanying balance sheets at the lower of carrying value or fair value less the cost to sell. For additional discussion on assets held for sale, please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions . Other Property and Equipment Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from three to 30 years, or the unit of output method where appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. Internal Use Software Development Costs The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2015 , and 2014 , the Company has capitalized approximately $44.0 million and $35.0 million , respectively, related to the development and implementation of accounting and operational software. Derivative Financial Instruments The Company seeks to manage or reduce commodity price risk on its production by entering into derivative contracts. The Company seeks to minimize its basis risk and indexes its oil derivative contracts to NYMEX prices, its NGL derivative contracts to OPIS prices, and its gas derivative contracts to various regional index prices associated with pipelines into which the Company’s gas production is sold. For additional discussion on derivatives, please see Note 10 – Derivative Financial Instruments . Net Profits Plan The Company records the estimated fair value of expected future payments to be made under the Net Profits Plan as a noncurrent liability in the accompanying balance sheets. The underlying assumptions used in the calculation of the estimated liability include estimates of production, proved reserves, recurring and workover lease operating expense, transportation, production and ad valorem tax rates, present value discount factors, pricing assumptions, and overall market conditions. The estimates used in calculating the long-term liability are adjusted from period-to-period based on the most current information attributable to the underlying assumptions. Changes in the estimated liability of future payments associated with the Net Profits Plan are recorded as increases or decreases to expense in the current period as a separate line item in the accompanying statements of operations, as these changes are considered changes in estimates. The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash compensation related to periodic operations are recognized as compensation expense and are included within general and administrative expense and exploration expense in the accompanying statements of operations. The corresponding current liability is included in accounts payable and accrued expenses in the accompanying balance sheets. This treatment provides for a consistent matching of cash expense with net cash flows from the oil and gas properties in each respective pool of the Net Profits Plan. For additional discussion, please refer to the heading Net Profits Plan in Note 7 – Compensation Plans and Note 11 – Fair Value Measurements . Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. For additional discussion, please refer to Note 9 – Asset Retirement Obligations . Revenue Recognition The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized when the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses knowledge of its properties and historical performance, contractual agreements, NYMEX, OPIS, and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates. The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized on all gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. Impairment of Proved and Unproved Properties Proved oil and gas property costs are evaluated for impairment and reduced to fair value, which is based on expected future discounted cash flows, when there is an indication that the carrying costs may not be recoverable. Expected future cash flows are calculated on all proved reserves and risk adjusted probable and possible reserves using a discount rate and price forecasts that management believes are representative of current market conditions. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. An impairment is recorded on unproved property when the Company determines that either the property will not be developed or the carrying value is not realizable. The Company recorded $468.7 million , $84.5 million , and $172.6 million , of proved property impairment expense for the years ended December 31, 2015 , 2014 , and 2013 , respectively. The impairments of proved properties in 2015 were due to continued commodity price declines, largely impacting the Company’s Powder River Basin program and certain legacy and non-core assets in the Rocky Mountain region, as well as the Company’s decision to reduce capital invested in the development of its east Texas exploration program in its South Texas & Gulf Coast region. The impairments of proved properties in 2014 were primarily a result of the significant decline in commodity prices in late 2014 and recognition of the outcomes of exploration and delineation wells in certain prospects in the Company’s South Texas & Gulf Coast and Permian regions. The impairments in 2013 primarily resulted from the write-down of certain Mississippian limestone assets in the Company’s Permian region due to negative engineering revisions, write-downs related to Olmos interval, dry gas assets in the South Texas & Gulf Coast region as a result of a plugging and abandonment program, and write-downs of certain underperforming assets due to the Company’s decision to no longer pursue the development of those assets. For the years ended December 31, 2015 , 2014 , and 2013 , the Company recorded expense related to the abandonment and impairment of unproved properties of $78.6 million , $75.6 million , and $46.1 million , respectively. The Company’s abandonment and impairment of unproved properties expense in 2015 and 2014 was primarily a result of lease expirations and acreage the Company no longer intended to develop in light of changes in drilling plans in response to the continued decline in commodity prices. The Company’s abandonment and impairment of unproved properties expense in 2013 was mostly related to acreage the Company no longer intended to develop in its Permian region. Impairment of Other Property and Equipment A long-lived asset is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may be greater than its undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying value over its estimated fair value. The Company uses an income valuation technique if there is not a market-observable price for the asset. For the year ended December 31, 2015 , the Company recorded a $49.4 million impairment charge on its gas gathering system assets in east Texas, in conjunction with the impairment of the associated proved and unproved properties, resulting from the Company’s decision to reduce capital spent in the program in light of sustained, low commodity prices. The Company did not have any impairments of other property and equipment for the years ended December 31, 2014, or 2013. Sales of Proved and Unproved Properties The partial sale of proved property within an existing field is accounted for as normal retirement and no net gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A net gain on divestiture activity is recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of unproved property. For additional discussion, please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions . Stock-Based Compensation At December 31, 2015 , the Company had stock-based employee compensation plans that included RSUs, PSUs, and restricted stock awards issued to employees and non-employee directors, as more fully described in Note 7 - Compensation Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and included within general and administrative expense and exploration expense in the accompanying statements of operations. Income Taxes The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. Earnings per Share Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company. Diluted net income (loss) per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs, contingent PSUs, and in-the-money outstanding stock options. When there is a loss from continuing operations, as was the case for the year ended December 31, 2015, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three -year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading Performance Share Units Under the Equity Plan . The treasury stock method is used to measure the dilutive impact of unvested RSUs, contingent PSUs, and in-the-money stock options. All remaining stock options were exercised during the year ended December 31, 2014. The following table details the weighted-average dilutive and anti-dilutive securities related to RSUs, PSUs, and stock options for the years presented: For the Years Ended December 31, 2015 2014 2013 (in thousands) Dilutive — 814 1,383 Anti-dilutive 256 — — The following table sets forth the calculations of basic and diluted earnings per share: For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share amounts) Net income (loss) $ (447,710 ) $ 666,051 $ 170,935 Basic weighted-average common shares outstanding 67,723 67,230 66,615 Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs (1) — 814 1,383 Diluted weighted-average common shares outstanding 67,723 68,044 67,998 Basic net income (loss) per common share $ (6.61 ) $ 9.91 $ 2.57 Diluted net income (loss) per common share $ (6.61 ) $ 9.79 $ 2.51 ____________________________________________ (1) For the year ended December 31, 2015, the shares were anti-dilutive and excluded from the calculation of diluted earnings per share. Comprehensive Income (Loss) Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss). The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table: Derivative Adjustments (1) Pension Liability Adjustments (in thousands) For the year ended December 31, 2013 Net actuarial gain $ 2,766 Reclassification to earnings $ 1,777 1,239 Tax expense (662 ) (1,522 ) Income, net of tax $ 1,115 $ 2,483 For the year ended December 31, 2014 Net actuarial loss $ (10,062 ) Reclassification to earnings $ — 706 Tax benefit — 3,460 Loss, net of tax $ — $ (5,896 ) For the year ended December 31, 2015 Net actuarial loss $ (4,990 ) Reclassification to earnings $ — 1,853 Tax benefit — 1,047 Loss, net of tax $ — $ (2,090 ) ____________________________________________ (1) As of December 31, 2013, all commodity derivative contracts that had been previously designated as cash flow hedges had settled and had been reclassified into earnings from AOCL. Fair Value of Financial Instruments The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had $202.0 million of outstanding loans under its credit facility as of December 31, 2015 . The Company had $166.0 million of outstanding loans under its credit facility as of December 31, 2014 . The Company’s Senior Notes are recorded at cost, net of unamortized deferred financing costs, and the respective fair values are disclosed in Note 11 - Fair Value Measurements. The Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Industry Segment and Geographic Information The Company operates in the exploration and production segment of the oil and gas industry within the United States. The Company reports as a single industry segment. The Company sold its Mid-Continent assets in 2015, and therefore, no longer has marketed gas volumes as of December 31, 2015. Prior to the sale of these assets, the Company’s gas marketing function provided mostly internal services and acted as the first purchaser of natural gas and natural gas liquids produced by the Company in certain cases. The Company considered its marketing function as ancillary to its oil and gas producing activities. The amount of income these operations generated from marketing gas produced by third parties was not material to the Company’s results of operations, and segmentation of such activity would not have provided a better understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties is presented in the marketed gas system revenue and marketed gas system expense line items in the accompanying statements of operations. Off-Balance Sheet Arrangements The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that SM Energy is the primary beneficiary of a variable interest entity, that entity is consolidated into SM Energy. The Company has not been involved in any unconsolidated SPE transactions in 2015 or 2014 . Recently Issued Accounting Standards In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue from contracts with customers. This guidance is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance. In August 2015, the FASB deferred the effective date of the new revenue recognition standard by one year. The revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures. In August 2014, the FASB issued new authoritative guidance that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures but does not believe it will impact the Company’s financial statements or disclosures. Effective January 1, 2015, the Company adopted, on a prospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-01, “Income Statement – Extraordinary and Unusual Items.” This ASU simplifies income statement presentation by eliminating the concept of extraordinary items. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard. In February 2015, the FASB issued new authoritative accounting guidance meant to clarify the consolidation reporting guidance in GAAP. This guidance is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures. Effective November 1, 2015, the Company early adopted, on a retrospective basis, FASB ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”). ASU 2015-03 requires deferred financing costs to be presented on the accompanying balance sheets as a direct deduction from the carrying value of the related debt liability. In accordance, the Company has reclassified $33.6 million of deferred financing costs related to its Senior Notes at December 31, 2014, from the other noncurrent assets line item to the Senior Notes, net of unamortized deferred financing costs line item. The December 31, 2014, accompanying balance sheet line items that were adjusted as a result of the adoption of ASU 2015-03 are presented in the following table: As of December 31, 2014 As Reported As Adjusted (in thousands) Other noncurrent assets $ 78,214 $ 44,659 Total other noncurrent assets $ 267,754 $ 234,199 Total Assets $ 6,516,700 $ 6,483,145 Senior Notes $ 2,200,000 N/A Senior Notes, net of unamortized deferred financing costs N/A $ 2,166,445 Total noncurrent liabilities $ 3,445,385 $ 3,411,830 Total Liabilities and Stockholders’ Equity $ 6,516,700 $ 6,483,145 ASU 2015-03 does not specifically address the accounting for deferred financing costs related to line-of-credit arrangements. In August 2015, the FASB issued ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” (“ASU 2015-15”) allowing for deferred financing costs associated with line-of-credit arrangements to continue to be presented as assets. ASU 2015-15 is consistent with how the Company currently accounts for deferred financing costs related to the Company’s revolving credit facility. Effective December 1, 2015, the Company early adopted, on a prospective basis, FASB ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes” (“ASU 2015-17”). ASU 2015-17 requires that deferred tax liabilities and assets, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments in ASU 2015-17. As ASU 2015-17 was adopted on a prospective basis, the Company did not retrospectively adjust prior periods. There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of December 31, 2015 , and through the filing date of this report. |
Accounts Receivable and Account
Accounts Receivable and Accounts Payable and Accrued Expenses | 12 Months Ended |
Dec. 31, 2015 | |
Accounts Receivable and Accounts Payable and Accrued Expenses [Abstract] | |
Accounts Receivable and Accounts Payable and Accrued Expenses [Text Block] | Note 2 – Accounts Receivable and Accounts Payable and Accrued Expenses Accounts receivable are comprised of the following: As of December 31, 2015 2014 (in thousands) Accrued oil, gas, and NGL production revenue $ 58,256 $ 180,250 Amounts due from joint interest owners 22,269 58,347 Accrued derivative settlements 34,579 39,811 State severance tax refunds 12,072 24,394 Other 6,948 19,828 Total accounts receivable $ 134,124 $ 322,630 Accounts payable and accrued expenses are comprised of the following: As of December 31, 2015 2014 (in thousands) Accrued capital expenditures $ 97,355 $ 357,156 Revenue and severance tax payable 44,387 63,779 Accrued lease operating expense 21,943 34,822 Accrued property taxes 14,078 15,059 Accrued compensation 41,154 56,279 Accrued interest 34,378 40,786 Other 49,222 72,803 Total accounts payable and accrued expenses $ 302,517 $ 640,684 |
Acquisitions, Divestitures, and
Acquisitions, Divestitures, and Assets Held for Sale | 12 Months Ended |
Dec. 31, 2015 | |
Acquisitions, Divestitures, and Assets Held for Sale Disclosure [Abstract] | |
Acquisitions, Divestitures, and Assets Held for Sale | Note 3 – Divestitures, Assets Held for Sale, and Acquisitions 2015 Divestiture Activity • Mid-Continent Divestiture. During the second quarter of 2015, the Company divested its Mid-Continent assets in multiple transactions for total divestiture proceeds of $316.8 million and a final net gain of $108.4 million . Certain of these assets were written down by $30.0 million to reflect fair value less estimated costs to sell upon reclassification to assets held for sale as of March 31, 2015. This write-down is reflected in the final net gain of $108.4 million discussed above. In conjunction with the divestiture of its Mid-Continent assets, the Company closed its Tulsa, Oklahoma office. For the year ended December 31, 2015 , the Company recorded $9.3 million of exit and disposal costs, the majority of which were recorded as general and administrative expense in the accompanying statements of operations. Additionally, during the third quarter of 2015, the Company vacated its office space in Tulsa. The Company has subleased the space for a portion of the remaining term. As of December 31, 2015 , the Company is obligated to pay lease costs of approximately $4.0 million , net of expected income from office space currently subleased, which will be expensed over the duration of the lease, which expires in 2022. This obligation will decrease if the Company successfully subleases space for additional terms. • Permian Divestiture. During the fourth quarter of 2015, the Company divested certain non-core assets in its Permian region. Total divestiture proceeds were $25.1 million and the estimated total net gain on this divestiture was $2.4 million . This divestiture is subject to normal post-closing adjustments, which are expected to occur in the first half of 2016. Write-downs on certain other assets held for sale and subsequently sold during the year ended December 31, 2015, totaled $68.6 million . Write-downs on assets held for sale are reflected as a loss on divestiture activity which is included in the net gain on divestiture activity line item in the accompanying statements of operations. Please refer to Assets Held for Sale below for further discussion. 2014 Divestiture Activity • Rocky Mountain Divestiture. During the second quarter of 2014, the Company divested certain non-core assets in the Montana portion of the Williston Basin. Total divestiture proceeds were $50.1 million and the final net gain on this divestiture was $26.9 million . The Company recorded $27.6 million of write-downs to fair value less estimated costs to sell for assets that were held for sale during the year ended December 31, 2014, which offset the net gain on the Rocky Mountain divestiture discussed above. 2013 Divestiture Activity • Mid-Continent Divestitures. In December 2013, the Company divested of certain non-strategic assets located in its Mid-Continent region, with the largest transaction being the sale of the Company’s Anadarko Basin assets. Total divestiture proceeds were $368.5 million and the final net gain on these divestitures was $25.3 million . A portion of one transaction was structured to qualify as a like-kind exchange under Section 1031 of the IRC. • Rocky Mountain Divestitures . During 2013, the Company divested of certain non-strategic assets located in its Rocky Mountain region. Final divestiture proceeds for these divestitures were $57.1 million and the final net gain was $13.2 million . • Permian Divestiture . In December 2013, the Company divested of certain non-strategic assets located in its Permian region. Final divestiture proceeds were $14.0 million and the final net loss was $7.0 million . The Company recorded an immaterial write-down to fair value less estimated costs to sell for assets that were held for sale as of December 31, 2013. Assets Held for Sale Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell. Any subsequent decreases to the estimated fair value less costs to sell impact the measurement of assets held for sale. A s of December 31, 2015 , the accompanying balance sheets present $641,000 of assets held for sale. There is a corresponding asset retirement obligation liability of $241,000 for assets held for sale included in the asset retirement obligation financial statement line item. Certain assets classified as held for sale and subsequently sold during 2015 were written down to fair value less estimated costs to sell, as discussed above. The Company determined that neither these planned nor executed asset sales qualify for discontinued operations accounting under financial statement presentation authoritative guidance. 2015 Acquisition Activity There was no significant acquisition activity during the year ended December 31, 2015. 2014 Acquisition Activity • Gooseneck Property Acquisitions On September 24, 2014 , the Company acquired approximately 61,000 net acres of proved and unproved oil and gas properties in its Gooseneck area in North Dakota, along with related equipment, contracts, records, and other assets. Total cash consideration paid by the Company after final closing adjustments was $321.8 million and the effective date for the acquisition was July 1, 2014 . On October 15, 2014 , the Company acquired additional interests in proved and unproved oil and gas properties in its Gooseneck area. Total cash consideration paid by the Company was $84.8 million and the effective date for the acquisition was August 1, 2014 . The Company determined that both of these acquisitions met the criteria of a business combination under Accounting Standards Codification (“ASC”) Topic 805, Business Combinations . The Company allocated the final adjusted purchase price to the acquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below. Refer to Note 11 – Fair Value Measurements for additional discussion on the valuation techniques used in determining the fair value of acquired properties. Acquisition #1 Acquisition #2 As of September 24, 2014 As of October 15, 2014 Purchase Price (in thousands) Cash consideration $ 321,807 $ 84,836 Fair value of assets and liabilities acquired: Proved oil and gas properties $ 203,467 $ 54,612 Unproved oil and gas properties 126,588 29,610 Total fair value of oil and gas properties acquired 330,055 84,222 Working capital (6,135 ) 2,232 Asset retirement obligation (2,113 ) (1,618 ) Total fair value of net assets acquired $ 321,807 $ 84,836 • Rocky Mountain Acquisitions. In addition to the Gooseneck property acquisitions discussed above, the Company acquired other proved and unproved properties in its Rocky Mountain region during 2014, primarily in the Powder River Basin, in multiple transactions for approximately $135.5 million in total cash consideration after final closing adjustments, plus approximately 7,000 net acres of non-core assets in the Company’s Rocky Mountain region. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 4 – Income Taxes The provision for income taxes consists of the following: For the Years Ended December 31, 2015 2014 2013 (in thousands) Current portion of income tax expense Federal $ — $ — $ — State 1,571 868 2,121 Deferred portion of income tax expense (benefit) (276,722 ) 397,780 105,555 Total income tax expense (benefit) $ (275,151 ) $ 398,648 $ 107,676 Effective tax rate 38.1 % 37.4 % 38.6 % The components of the net deferred income tax liabilities are as follows: As of December 31, 2015 2014 (in thousands) Deferred tax liabilities: Oil and gas properties $ 854,029 $ 1,029,424 Derivative asset 179,543 220,437 Other 1,233 4,475 Total deferred tax liabilities 1,034,805 1,254,336 Deferred tax assets: Federal and state tax net operating loss carryovers 244,942 184,447 Stock compensation 14,529 16,763 Other liabilities 27,449 25,715 Total deferred tax assets 286,920 226,925 Valuation allowance (10,394 ) (7,246 ) Net deferred tax assets 276,526 219,679 Total net deferred tax liabilities (1) $ 758,279 $ 1,034,657 Current federal income tax refundable $ 5,378 $ 4,734 Current state income tax refundable $ 65 $ — Current state income tax payable $ — $ 25 ____________________________________________ (1) All deferred tax liabilities and assets as of December 31, 2015, are classified as noncurrent on the accompanying balance sheets upon the Company’s adoption of ASU 2015-17 on a prospective basis. Prior year amounts have not been restated. Please refer to the caption Recently Issued Accounting Standards in Note 1 - Summary of Significant Accounting Policies for additional discussion. At December 31, 2015 , the Company estimated its federal net operating loss carryforward at $796.7 million , which includes unrecognized excess income tax benefits associated with stock awards of $126.7 million . The federal net operating loss carryforward begins to expire in 2031 . The Company has estimated state net operating loss carryforwards of $338.9 million that expire between 2016 and 2036 and it has federal R&D credit carryforwards of $7.2 million that expire between 2028 and 2033. The Company’s valuation allowance relates to charitable contribution carryforwards, state net operating loss carryforwards, and state tax credits, which the Company anticipates will expire before they can be utilized. The change in the valuation allowance from 2014 to 2015 primarily reflects an allocable change to the Company’s mix of state apportioned losses and the anticipated utilization of state cumulative net operating losses. Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, R&D credits, and other permanent differences, as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Federal statutory tax expense (benefit) $ (253,001 ) $ 372,644 $ 97,514 Increase (decrease) in tax resulting from: State tax expense (benefit) (net of federal benefit) (21,583 ) 21,350 9,400 Change in valuation allowance 3,148 2,245 (314 ) Research and development credit (1,971 ) — — Other (1,744 ) 2,409 1,076 Income tax expense (benefit) $ (275,151 ) $ 398,648 $ 107,676 Acquisitions, divestitures, drilling activity, and basis differentials impacting the prices received for oil, gas, and NGLs affect apportionment of taxable income to the states where the Company owns oil and gas properties. As its apportionment factors change, the Company’s blended state income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total state income tax expense (benefit) reported in the current year. Items affecting state apportionment factors are evaluated at the beginning of each year, after completion of the prior year income tax return, and when significant acquisition, divestiture, or changes in drilling activity or estimated state revenue occurs during the year. The Company and its subsidiaries file federal income tax returns and various state income tax returns. With certain exceptions, the Company is no longer subject to United States federal or state income tax examinations by these tax authorities for years before 2007. During the first quarter of 2015, as a result of its R&D credit settlement with the IRS Appeals Office in late 2014, the Company recorded an additional $2.0 million net R&D credit from a claim filed on an amended return. At December 31, 2015, the Company’s 2007 - 2011 IRS examination was still ongoing, but a final agreement was reached in January 2016. There are no material adjustments to previously recorded amounts. During the quarter ended September 30, 2015, the IRS initiated an audit of the SM-Mitsui Tax Partnership for the 2013 tax year. The Company has a significant investment in the underlying assets of the tax partnership and this audit was still in progress at December 31, 2015 . The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. Interest expense in the accompanying statements of operations includes a negligible amount associated with income taxes. At December 31, 2015 , the Company estimates the range of reasonably possible change in 2016 to the recorded unrecognized tax benefits presented in the table below could be from zero to $1.8 million . The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2015 2014 2013 (in thousands) Beginning balance $ 1,582 $ 2,358 $ 2,278 Additions for tax positions of prior years 1,200 140 80 Settlements — (916 ) — Ending balance $ 2,782 $ 1,582 $ 2,358 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Note 5 – Long-Term Debt Revolving Credit Facility The Company’s Fifth Amended and Restated Credit Agreement, as amended, provides a maximum loan amount of $2.5 billion , current aggregate lender commitments of $1.5 billion , and a maturity date of December 10, 2019 . The borrowing base is subject to regular semi-annual redeterminations. Effective as of October 7, 2015 , the Company’s lenders decreased the borrowing base to $2.0 billion as part of the regularly scheduled semi-annual redetermination under the Credit Agreement. This expected reduction from $2.4 billion was primarily a result of the Company’s sale of its Mid-Continent assets, plus adjustments consistent with lower commodity prices. There was no change in the current aggregate lender commitments of $1.5 billion . The next redetermination date is scheduled for April 1, 2016 . The borrowing base redetermination process under the credit facility considers the value of the Company’s proved oil and gas properties and commodity derivative contracts, as determined by the lender group. Borrowings under the facility are secured by mortgages on assets having a value equal to at least 75 percent of the total value of the Company’s proved oil and gas properties. The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including limitations on dividend payments and requirements to maintain certain financial ratios, which include debt to adjusted EBITDAX, as defined by the Credit Agreement as the ratio of debt to 12-month trailing adjusted EBITDAX, of less than 4.0 and an adjusted current ratio, as defined by the Credit Agreement, of no less than 1.0 . The Company was in compliance with all financial and non-financial covenants under the Credit Agreement as of December 31, 2015 , and through the filing date of this report. Interest and commitment fees are accrued based on the borrowing base utilization grid below. Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternate Base Rate (“ABR”) and swingline loans accrue interest at Prime plus the applicable margin from the utilization table below. Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying statements of operations. Borrowing Base Utilization Grid Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans 1.250 % 1.500 % 1.750 % 2.000 % 2.250 % ABR Loans or Swingline Loans 0.250 % 0.500 % 0.750 % 1.000 % 1.250 % Commitment Fee Rate 0.300 % 0.300 % 0.350 % 0.375 % 0.375 % The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of February 17, 2016 , December 31, 2015 , and December 31, 2014 : As of February 17, 2016 As of December 31, 2015 As of December 31, 2014 (in thousands) Credit facility balance (1) $ 243,000 $ 202,000 $ 166,000 Letters of credit (2) $ 200 $ 200 $ 808 Available borrowing capacity $ 1,256,800 $ 1,297,800 $ 1,333,192 ____________________________________________ (1) Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and thus are not deducted from the credit facility balance. (2) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis. Senior Notes The Senior Notes, net of unamortized deferred financing costs, line on the accompanying balance sheets as of December 31, 2015 , and 2014 , consisted of the following: As of December 31, 2015 2014 (1) Senior Notes Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Senior Notes Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs (in thousands) 6.625% Notes due 2019 $ — $ — $ — $ 350,000 $ 4,591 $ 345,409 6.50% Notes due 2021 350,000 4,106 345,894 350,000 4,806 345,194 6.125% Notes due 2022 600,000 8,714 591,286 600,000 9,812 590,188 6.50% Notes due 2023 400,000 5,231 394,769 400,000 5,969 394,031 5.0% Notes due 2024 500,000 7,455 492,545 500,000 8,377 491,623 5.625% Notes due 2025 500,000 8,524 491,476 — — — Total $ 2,350,000 $ 34,030 $ 2,315,970 $ 2,200,000 $ 33,555 $ 2,166,445 ____________________________________________ (1) Prior period amounts have been reclassified to conform to the current period presentation on the accompanying balance sheets. Please refer to the section Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional discussion. The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes. The Company is subject to certain covenants under the indentures governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends; however, the first $6.5 million of dividends paid each year are not restricted by the restricted payment covenant. The Company was in compliance with all covenants under its Senior Notes as of December 31, 2015 , and through the filing date of this report. All Senior Notes are registered under the Securities Act as of December 31, 2015. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices based on a make-whole amount plus accrued and unpaid interest as described in the indentures governing the notes. 2019 Notes On May 7, 2015, the Company commenced a cash tender offer for any and all of its outstanding 6.625% Senior Notes due 2019 at a price of $1,036.88 per $1,000 of principal amount for all 2019 Notes tendered by May 20, 2015 (“Consent Payment Deadline”), and at a price of $1,006.88 per $1,000 of principal amount for all 2019 Notes properly tendered thereafter. On the Consent Payment Deadline, the Company received tenders and consents from the holders of approximately $242.9 million in aggregate principal amount, or approximately 69 percent , of its outstanding 2019 Notes in connection with the cash tender offer. Following its entry into the supplemental indenture dated as of May 21, 2015, to the indenture dated as of February 7, 2011, between the Company and U.S. Bank National Association, as Trustee, the Company accepted the 2019 Notes tendered as of the Consent Payment Deadline in exchange for payment of total consideration, including accrued interest, of approximately $256.2 million under the Tender Offer and Consent Solicitation. On June 5, 2015 , the Company accepted $1.5 million of 2019 Notes tendered after the Consent Payment Deadline in exchange for payment of total consideration, including accrued interest, of approximately $1.6 million . On June 22, 2015 , the Company redeemed the remaining outstanding 2019 Notes at a redemption price of 103.313% of the principal amount for payment of total consideration, including accrued interest, of approximately $111.5 million . The Company recorded a loss on extinguishment of debt related to the tender offer and redemption of its 2019 Notes of approximately $16.6 million for the quarter ended June 30, 2015. This amount includes approximately $12.5 million associated with the premium paid for the tender offer and redemption of the 2019 Notes and approximately $4.1 million related to the acceleration of unamortized deferred financing costs. 2021 Notes On November 8, 2011 , the Company issued $350.0 million in aggregate principal amount of 6.50% Senior Notes due 2021 . The 2021 Notes were issued at par and mature on November 15, 2021 . The Company received net proceeds of $343.1 million after deducting fees of $6.9 million , which are being amortized as deferred financing costs over the life of the 2021 Notes. 2022 Notes On November 17, 2014 , the Company issued $600.0 million in aggregate principal amount of 6.125% Senior Notes due 2022 . The 2022 Notes were issued at par and mature on November 15, 2022 . The Company received net proceeds of $590.0 million after deducting fees of $10.0 million , which are being amortized as deferred financing costs over the life of the 2022 Notes. On November 17, 2014 , the Company entered into a registration rights agreement that provided holders of the 2022 Notes certain registration rights under the Securities Act. The Company closed its offer to exchange its 2022 Notes for notes registered under the Securities Act on July 10, 2015. 2023 Notes On June 29, 2012 , the Company issued $400.0 million in aggregate principal amount of 6.50% Senior Notes due 2023 . The 2023 Notes were issued at par and mature on January 1, 2023 . The Company received net proceeds of $392.1 million after deducting fees of $7.9 million , which are being amortized as deferred financing costs over the life of the 2023 Notes. 2024 Notes On May 20, 2013 , the Company issued $500.0 million in aggregate principal amount of 5.0% Senior Notes due 2024 . The 2024 Notes were issued at par and mature on January 15, 2024 . The Company received net proceeds of $490.2 million after deducting fees of $9.8 million , which are being amortized as deferred financing costs over the life of the 2024 Notes. 2025 Notes On May 21, 2015 , the Company issued $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025 . The 2025 Notes were issued at par and mature on June 1, 2025 . The Company received net proceeds of $491.0 million after deducting fees of $9.0 million , which are being amortized as deferred financing costs over the life of the 2025 Notes. The net proceeds were used to fund the consideration paid to the tendering holders of the 2019 Notes and to redeem the remaining untendered 2019 Notes, as well as repay outstanding borrowings under the Credit Agreement and for general corporate purposes. Capitalized Interest Capitalized interest costs for the Company for the years ended December 31, 2015 , 2014 , and 2013 , were $25.1 million , $16.2 million , and $11.0 million , respectively. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 6 – Commitments and Contingencies Commitments The Company has entered into various agreements, which include drilling rig contracts of $35.3 million , gathering, processing, and transportation throughput commitments of $864.0 million , office leases, including maintenance, of $59.4 million , and other miscellaneous contracts and leases of $5.7 million . The annual minimum payments for the next five years and total minimum payments thereafter are presented below: Years Ending December 31, Amount (1) (in thousands) 2016 $ 132,747 2017 128,074 2018 131,489 2019 142,161 2020 141,854 Thereafter 288,113 Total $ 964,438 ____________________________________________ (1) During the third quarter of 2015, the Company vacated its office space in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive $3.5 million of sublease income as follows: $831,000 in 2016 , $953,000 in 2017 , $978,000 in 2018 , and $741,000 in 2019 . Drilling rig contracts The Company has multiple long-term drilling rig contracts. Early termination of these rig contracts as of December 31, 2015 , would result in termination penalties of $26.0 million , which would be in lieu of paying the remaining drilling commitments of $35.3 million included in the table above. In light of the low commodity price environment, the Company curtailed drilling activity during 2015 . For the year ended December 31, 2015 , the Company incurred $13.7 million of expense related to the early termination of drilling rig contracts or fees incurred on rigs placed on standby, which are recorded in the other operating expenses line item in the accompanying statements of operations. These fees include the costs to terminate the contract for an operated drilling rig in the Company’s South Texas & Gulf Coast region, in early 2016. Subsequent to December 31, 2015, the Company renegotiated the terms of certain drilling rig contracts to provide increased flexibility with regard to the timing of activity and payment. Transportation commitments The Company has gathering, processing, and transportation throughput commitments with various third parties that require delivery of a minimum amount of 2,277 Bcf of natural gas and 36 MMBbl of crude oil, of which the first 1,059 Bcf of natural gas delivered under a certain agreement does not have a deficiency payment. These contracts expire at various dates through 2028 . The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. As of December 31, 2015, if the Company delivers no product, the aggregate undiscounted deficiency payments total approximately $864.0 million . If a shortfall in the minimum volume commitment for natural gas is projected, the Company has rights under certain contracts to arrange for third party gas to be delivered, and such volumes would count toward its minimum volume commitment. Subsequent to December 31, 2015 , the Company entered into amendments to certain oil gathering and gas gathering agreements related to certain of its Eagle Ford shale assets, neither of which previously had a minimum volume commitment, in order to obtain more favorable rates and terms. Under these amendments, the Company is now committed to deliver 310 Bcf of natural gas and 41 MMBbl of oil through 2034. In the event that the Company delivers no product, the aggregate undiscounted deficiency payments under these amended agreements would be approximately $360.8 million . Subsequent to December 31, 2015 , the Company also entered into an amendment to a gas gathering agreement related to certain of its other Eagle Ford shale assets, which reduced the Company’s volume commitment amount as of December 31, 2015 , by 829 Bcf and reduced the aggregate undiscounted deficiency payments by $118.2 million . As of the filing date of this report, the Company does not expect to incur any material shortfalls. Office leases The Company leases office space under various operating leases with terms extending as far as 2026 . Rent expense, net of sublease income, for the years ended December 31, 2015 , 2014 , and 2013 , was $6.1 million , $6.5 million , and $5.7 million , respectively. The Company also leases office equipment under various operating leases. Contingencies The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such pending litigation and claims will not have a material effect on the results of operations, the financial position, or the cash flows of the Company. The Company is subject to routine severance, royalty and joint interest audits from regulatory authorities, non-operators and others, as the case may be, and records accruals for estimated exposure when a claim is deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise from third party interpretations of the Company’s contracts or otherwise affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices that royalty owners are paid for production from their leases, allowable costs under joint interest arrangements, and other matters. At December 31, 2015 , the Company had $5.3 million accrued for estimated exposure related to claims for payment of royalties on certain Federal and Indian leases. Although the Company believes that it has properly estimated its exposure with respect to the various contracts, laws and regulations, administrative rulings, and interpretations thereof, adjustments could be required as new interpretations and regulations arise. |
Compensation Plans
Compensation Plans | 12 Months Ended |
Dec. 31, 2015 | |
Compensation Related Costs [Abstract] | |
Compensation Plans | Note 7 – Compensation Plans Equity Plan There are several components to the Company’s Equity Plan that are described in this section. Various types of equity awards have been granted by the Company in different periods. As of December 31, 2015 , 2.8 million shares of common stock remained available for grant under the Equity Plan. The issuance of a direct share benefit, such as a share of common stock, a stock option, a restricted share, an RSU, or a PSU, counts as one share against the number of shares available to be granted under the Equity Plan. Each PSU has the potential to count as two shares against the number of shares available to be granted under the Equity Plan based on the final performance multiplier. Stock options were issued out of the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan, both predecessors to the Equity Plan, although the last grant was in 2004, and all remaining stock options were exercised during the year ended December 31, 2014. Performance Share Units Under the Equity Plan The Company grants PSUs to eligible employees as a part of its long-term equity compensation program. The number of shares of the Company’s common stock issued to settle PSUs ranges from 0% to 200% of the number of PSUs awarded and is determined based on certain performance criteria over a three -year measurement period. The performance criteria for the PSUs are based on a combination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of certain peer companies for the performance period. Compensation expense for PSUs is recognized within general and administrative and exploration expense over the vesting periods of the respective awards. The fair value of PSUs was measured at the grant date with a stochastic process method using the Geometric Brownian Motion Model (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three-year performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three-year vesting period, as well as the volatilities and dividend yields for each of the Company’s peers. The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. Total compensation expense recorded for PSUs was $10.6 million , $16.0 million , and $16.8 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. As of December 31, 2015 , there was $18.4 million of total unrecognized expense related to PSUs, which is being amortized through 2018 . A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2015 2014 2013 PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value Non-vested at beginning of year (1) 433,660 $ 73.63 572,469 $ 66.07 669,308 $ 63.91 Granted (1) 320,753 $ 45.34 202,404 $ 94.66 274,831 $ 64.13 Vested (1) (76,438 ) $ 51.76 (206,830 ) $ 64.79 (345,005 ) $ 60.06 Forfeited (1) (51,647 ) $ 73.62 (134,383 ) $ 86.72 (26,665 ) $ 69.74 Non-vested at end of year (1) 626,328 $ 61.81 433,660 $ 73.63 572,469 $ 66.07 ____________________________________________ (1) The number of awards assumes a multiplier of one . The final number of shares of common stock issued may vary depending on the three -year performance multiplier, which ranges from zero to two . The fair value of the PSUs granted in 2015 , 2014 , and 2013 was $14.5 million , $19.2 million , and $17.6 million , respectively. The PSUs granted in 2015 , 2014 , and 2013 will remain unvested until the third anniversary date of their issuance, at which time they will fully vest, unless the employee is retirement eligible in which case the PSUs vest immediately upon attainment of retirement age. The total fair value of PSUs that vested during the years ended December 31, 2015 , 2014 , and 2013 was $4.0 million , $13.4 million , and $20.7 million , respectively. During the years ended December 31, 2015 , 2014 , and 2013 , the Company issued 188,279 , 85,121 , and 387,461 net shares, respectively, of common stock for PSUs granted in 2012, 2011, and 2010 that earned a 1.0 , 0.55 , and 1.725 multiplier, respectively. The Company and the majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. As a result, the Company withheld 100,683 , 45,042 , and 200,050 shares, respectively, to satisfy income and payroll tax withholding obligations that arose upon the delivery of the shares underlying the PSUs in 2015, 2014, and 2013, respectively. Restricted Stock Units Under the Equity Plan The Company grants RSUs to eligible employees as part of its long-term equity incentive compensation program. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the award. Total compensation expense recorded for RSUs for the years ended December 31, 2015 , 2014 , and 2013 , was $13.4 million , $13.9 million , and $13.1 million , respectively. As of December 31, 2015 , there was $19.3 million of total unrecognized expense related to unvested RSU awards, which is being amortized through 2018 . The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the day of the grant. A summary of the status and activity of non-vested RSUs is presented below: For the Years Ended December 31, 2015 2014 2013 RSUs Weighted- Average Grant-Date Fair Value RSUs Weighted- Average Grant-Date Fair Value RSUs Weighted- Average Grant-Date Fair Value Non-vested at beginning of year 515,724 $ 68.29 580,431 $ 57.05 496,244 $ 51.81 Granted 356,246 $ 43.72 234,560 $ 83.98 329,939 $ 60.01 Vested (278,289 ) $ 63.12 (253,031 ) $ 58.19 (207,376 ) $ 49.73 Forfeited (49,944 ) $ 66.53 (46,236 ) $ 62.06 (38,376 ) $ 54.37 Non-vested at end of year 543,737 $ 55.01 515,724 $ 68.29 580,431 $ 57.05 The fair value of RSUs granted in 2015 , 2014 , and 2013 was $15.6 million , $19.7 million , and $19.8 million , respectively. The RSUs granted in 2015 , 2014 , and 2013 vest one-third of the total grant on each of the next three anniversaries of the date of the grant. The total fair value of RSUs that vested during the years ended December 31, 2015 , 2014 , and 2013 , was $17.6 million , $14.7 million , and $10.3 million , respectively. During the years ended December 31, 2015 , 2014 , and 2013 , the Company settled 278,289 , 253,031 , and 207,378 RSUs, respectively. The Company and the majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. As a result, the Company issued net shares of common stock of 187,244 , 171,597 , and 139,391 for 2015 , 2014 , and 2013 , respectively. The remaining 91,045 , 81,434 , and 67,987 shares were withheld to satisfy income and payroll tax withholding obligations that arose upon delivery of the shares underlying the RSUs for 2015 , 2014 , and 2013 , respectively. Stock Option Grants Under the Equity Plan The Company previously granted stock options under the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan. The last issuance of stock options occurred on December 31, 2004. Stock options to purchase shares of the Company’s common stock had been granted to eligible employees and members of the Board of Directors. All options granted under the option plans were granted at exercise prices equal to the respective closing market price of the Company’s underlying common stock on the grant dates. All stock options granted under the option plans were exercisable for a period of up to 10 years from the date of grant. The remaining options from the 2004 grant were exercised during the year ended December 31, 2014. As of December 31, 2015, and 2014, there was no unrecognized compensation expense related to stock option awards. A summary of activity associated with the Company’s Stock Option Plans during the years ended December 31, 2014, and 2013, is presented in the following table: Weighted - Average Aggregate Exercise Intrinsic Shares Price Value For the year ended December 31, 2013 Outstanding, start of year 267,846 $ 14.95 Exercised (228,758 ) $ 13.92 $ 12,326,994 Forfeited — $ — Outstanding, end of year 39,088 $ 20.87 $ 2,432,837 Vested and exercisable at end of year 39,088 $ 20.87 $ 2,432,837 For the year ended December 31, 2014 Outstanding, start of year 39,088 $ 20.87 Exercised (39,088 ) $ 20.87 $ 1,993,726 Forfeited — $ — Outstanding, end of year — $ — $ — Vested and exercisable at end of year — $ — $ — The fair value of options was measured at the date of grant using the Black-Scholes-Merton option-pricing model. Cash received from stock options exercised for the years ended December 31, 2014 , and 2013 , was $4.0 million and $3.2 million , respectively. Cash flows resulting from excess tax benefits are classified as part of cash flows from financing activities. Excess tax benefits are realized tax benefits from tax deductions for vested RSUs, settled PSUs, and exercised options in excess of the deferred tax asset attributable to stock compensation costs for such equity awards. The Company recorded no excess tax benefits for the years ended December 31, 2015 , 2014 , and 2013 . Director Shares In 2015 , 2014 , and 2013 , the Company issued 37,950 , 27,677 , and 28,169 shares, respectively, of its common stock to its non-employee directors under the Company’s Equity Plan. Additionally, the Company issued 1,953 shares to the Company’s former Chief Executive Officer in 2015 for his service as a director through May 2015, following his retirement as an officer of the Company. The Company recorded compensation expense related to these issuances of $1.6 million , $1.6 million , and $1.4 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. All shares of common stock issued to the Company’s non-employee directors are earned over the one -year service period following the date of grant, unless five years of service has been provided to the Company by the director, in which case that director’s shares vest upon the earlier of the completion of the one year service period or the director retiring from the Board of Directors. Employee Stock Purchase Plan Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85% of the lower of the fair market value of the stock on the first or last day of the purchase period, and shares issued under the ESPP have no restriction period. The ESPP is intended to qualify under Section 423 of the IRC. The Company had approximately 0.9 million shares available for issuance under the ESPP as of December 31, 2015 . There were 197,214 , 83,136 , and 77,427 shares issued under the ESPP in 2015 , 2014 , and 2013 , respectively. Total proceeds to the Company for the issuance of these shares were $4.8 million , $4.1 million , and $3.7 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes-Merton option-pricing model. Expected volatility was calculated based on the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a six month vesting period. The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions: For the Years Ended December 31, 2015 2014 2013 Risk free interest rate 0.1 % 0.1 % 0.1 % Dividend yield 0.2 % 0.1 % 0.2 % Volatility factor of the expected market price of the Company’s common stock 61.2 % 33.0 % 41.1 % Expected life (in years) 0.5 0.5 0.5 The Company expensed $1.8 million , $1.1 million , and $1.1 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively, based on the estimated fair value of the ESPP grants. 401(k) Plan The Company has a defined contribution plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute a maximum of 60 percent of their base salaries up to the contribution limits established under the IRC. The Company matches each employee’s contribution up to six percent of the employee’s base salary and performance bonus, and may make additional contributions at its discretion. The Company matches contributions made by employees hired after December 31, 2014, up to nine percent of the employee’s base salary and performance bonus in lieu of pension plan benefits. Please refer to Note 8 - Pension Benefits for additional discussion of change to pension benefits. The Company’s matching contributions to the 401(k) Plan were $5.6 million , $6.4 million , and $4.2 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. No discretionary contributions were made by the Company to the 401(k) Plan for any of these years. Net Profits Plan Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during each year were designated within a specific pool. Key employees recommended by senior management and designated as participants by the Compensation Committee of the Company’s Board of Directors and employed by the Company on the last day of that year became entitled to payments under the Net Profits Plan after the Company has received net cash flows returning 100 percent of all costs associated with that pool. Thereafter, 10 percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the 10 percent level. In December 2007, the Board of Directors discontinued the creation of new pools under the Net Profits Plan. As a result, the 2007 pool was the last Net Profits Plan pool established by the Company. Cash payments made or accrued under the Net Profits Plan that have been recorded as either general and administrative expense or exploration expense are detailed in the table below: For the Years Ended December 31, 2015 2014 2013 (in thousands) General and administrative expense $ 3,239 $ 8,326 $ 13,734 Exploration expense 259 690 1,310 Total $ 3,498 $ 9,016 $ 15,044 Additionally, the Company made or accrued cash payments under the Net Profits Plan of $3.8 million , $8.3 million , and $10.3 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively, as a result of divestitures of properties subject to the Net Profits Plan. These cash payments are accounted for as a reduction in the net gain on divestiture activity line item in the accompanying statements of operations. The Company records changes in the present value of estimated future payments under the Net Profits Plan as a separate line item in the accompanying statements of operations. The change in the estimated liability is recorded as a non-cash expense or benefit in the current period. The amount recorded as an expense or benefit associated with the change in the estimated liability is not allocated to general and administrative expense or exploration expense because it is associated with the future net cash flows from oil and gas properties in the respective pools rather than results being realized through current period production. If the Company allocated the change in liability to these specific functional line items, based on the current allocation of actual distributions made by the Company, such expenses or benefits would predominately be allocated to general and administrative expense. As time has passed, the amount distributed relating to prospective exploration efforts has become insignificant as more is paid to employees that have terminated employment and do not provide ongoing exploration support to the Company. |
Pension Benefits
Pension Benefits | 12 Months Ended |
Dec. 31, 2015 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |
Pension Benefits | Note 8 – Pension Benefits The Company has a non-contributory defined benefit pension plan covering substantially all employees who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). The Company froze the Pension Plans to new participants, effective as of December 31, 2015. Employees participating in the Pension Plans as of December 31, 2015, will continue to earn benefits. Obligations and Funded Status for the Pension Plans The Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment to accumulated other comprehensive income, net of tax. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31. For the Years Ended December 31, 2015 2014 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 57,867 $ 43,285 Service cost 7,949 6,335 Interest cost 2,496 2,191 Actuarial loss 2,397 8,821 Benefits paid (8,162 ) (2,765 ) Projected benefit obligation at end of year 62,547 57,867 Change in plan assets: Fair value of plan assets at beginning of year 27,940 24,658 Actual return on plan assets (410 ) 737 Employer contribution 6,401 5,310 Benefits paid (8,162 ) (2,765 ) Fair value of plan assets at end of year 25,769 27,940 Funded status at end of year $ (36,778 ) $ (29,927 ) The Company’s underfunded status for the Pension Plans as of December 31, 2015 , and 2014 , is $36.8 million and $29.9 million , respectively, and is recognized in the accompanying balance sheets as a portion of other noncurrent liabilities. No plan assets of the Qualified Pension Plan were returned to the Company during the year ended December 31, 2015 . There are no plan assets in the Nonqualified Pension Plan. Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans As of December 31, 2015 2014 (in thousands) Projected benefit obligation $ 62,547 $ 57,867 Accumulated benefit obligation $ 46,439 $ 43,205 Less: Fair value of plan assets (25,769 ) (27,940 ) Underfunded accumulated benefit obligation $ 20,670 $ 15,265 Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of unrecognized net gain or loss resulting from actual experience different from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for a year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of participating employees expected to receive benefits under the plan. Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensive loss as of December 31, 2015 and 2014 , consist of: As of December 31, 2015 2014 (in thousands) Unrecognized actuarial losses $ 20,966 $ 17,812 Unrecognized prior service costs 101 118 Unrecognized transition obligation — — Accumulated other comprehensive loss $ 21,067 $ 17,930 The estimated net loss that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year is $1.5 million . Pre-tax changes recognized in other comprehensive income (loss) during 2015 , 2014 , and 2013 , were as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Net actuarial gain (loss) $ (4,990 ) $ (10,062 ) $ 2,766 Prior service cost — — — Less: Amortization of prior service cost (17 ) (17 ) (17 ) Amortization of net actuarial loss (1,486 ) (689 ) (1,222 ) Settlements (350 ) — — Total other comprehensive income (loss) $ (3,137 ) $ (9,356 ) $ 4,005 Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2015 2014 2013 (in thousands) Components of net periodic benefit cost: Service cost $ 7,949 $ 6,335 $ 6,291 Interest cost 2,496 2,191 1,627 Expected return on plan assets that reduces periodic pension cost (2,182 ) (1,978 ) (1,538 ) Amortization of prior service cost 17 17 17 Amortization of net actuarial loss 1,486 689 1,222 Settlements 350 — — Net periodic benefit cost $ 10,116 $ 7,254 $ 7,619 Gains and losses in excess of 10 percent of the greater of the benefit obligation and the market-related value of assets are amortized over the average remaining service period of active participants. Pension Plan Assumptions Weighted-average assumptions to measure the Company’s projected benefit obligation and net periodic benefit cost are as follows: As of December 31, 2015 2014 2013 Projected benefit obligation Discount rate 4.7% 4.3% 5.0% Rate of compensation increase 6.2% 6.2% 6.2% Net periodic benefit cost Discount rate 4.3% 5.0% 3.9% Expected return on plan assets (1) 7.5% 7.5% 7.5% Rate of compensation increase 6.2% 6.2% 6.2% ____________________________________________ (1) There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan. The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy does not permit the direct investment of plan assets in the Company’s securities. The Qualified Pension Plan’s investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targeting the optimal expected returns for given levels of risk are applied. The Qualified Pension Plan’s investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to maintain the target allocations. The weighted-average asset allocation of the Qualified Pension Plan is as follows: Target As of December 31, Asset Category 2016 2015 2014 Equity securities 42.0 % 39.1 % 39.6 % Fixed income securities 35.0 % 34.0 % 33.9 % Other securities 23.0 % 26.9 % 26.5 % Total 100.0 % 100.0 % 100.0 % There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan. An expected return on plan assets of 7.5 percent was used to calculate the Company’s obligation under the Qualified Pension Plan for 2015 and 2014 . Factors considered in determining the expected rate of return include the long-term historical rate of return provided by the equity and debt securities markets and input from the investment consultants and trustees managing the plan assets. The difference in investment income using the projected rate of return compared to the actual rates of return for the past two years was not material and is not expected to have a material effect on the accompanying statements of operations or cash flows from operating activities in future years. Fair Value Assumptions The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2015 and 2014 , utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements are as follows: Fair Value Measurements Using: Actual Asset Allocation Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (in thousands) As of December 31, 2015 Cash — % $ — $ — $ — $ — Equity Securities: Domestic (1) 26.1 % 6,729 4,943 1,786 — International (2) 13.0 % 3,353 3,353 — — Total Equity Securities 39.1 % 10,082 8,296 1,786 — Fixed Income Securities: High-Yield Bonds (3) 2.8 % 722 722 — — Core Fixed Income (4) 22.5 % 5,789 5,789 — — Floating Rate Corp Loans (5) 8.7 % 2,247 2,247 — — Total Fixed Income Securities 34.0 % 8,758 8,758 — — Other Securities: Commodities (6) 2.7 % 700 700 — — Real Estate (7) 5.8 % 1,499 — — 1,499 Collective Investment Trusts (8) 4.6 % 1,184 — 1,184 — Hedge Fund (9) 13.8 % 3,546 — — 3,546 Total Other Securities 26.9 % 6,929 700 1,184 5,045 Total Investments 100.0 % $ 25,769 $ 17,754 $ 2,970 $ 5,045 As of December 31, 2014 Cash — % $ — $ — $ — $ — Equity Securities: Domestic (1) 27.1 % 7,569 5,550 2,019 — International (2) 12.5 % 3,498 3,498 — — Total Equity Securities 39.6 % 11,067 9,048 2,019 — Fixed Income Securities: High-Yield Bonds (3) 2.9 % 797 797 — — Core Fixed Income (4) 22.4 % 6,247 6,247 — — Floating Rate Corp Loans (5) 8.6 % 2,413 2,413 — — Total Fixed Income Securities 33.9 % 9,457 9,457 — — Other Securities: Commodities (6) 2.9 % 810 810 — — Real Estate (7) 4.7 % 1,327 — — 1,327 Collective Investment Trusts (8) 4.1 % 1,149 — 1,149 — Hedge Fund (9) 14.8 % 4,130 593 — 3,537 Total Other Securities 26.5 % 7,416 1,403 1,149 4,864 Total Investments 100.0 % $ 27,940 $ 19,908 $ 3,168 $ 4,864 ____________________________________________ (1) Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of this fund is to approximate the S&P 500 by investing in one or more collective investment funds. (2) International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations. (3) High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis. (4) The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index. (5) Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. (6) Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities. (7) The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. (8) Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities. (9) The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies. Included below is a summary of the changes in Level 3 plan assets (in thousands): Balance at January 1, 2014 $ 3,421 Purchases 1,232 Realized gain on assets 144 Unrealized gain on assets 67 Balance at December 31, 2014 $ 4,864 Purchases — Realized gain on assets 165 Unrealized gain on assets 16 Balance at December 31, 2015 $ 5,045 Contributions The Company contributed $6.4 million , $5.3 million , and $5.0 million , to the Pension Plans in the years ended December 31, 2015 , 2014 , and 2013 , respectively. The Company expects to make a $5.8 million contribution to the Pension Plans in 2016 . Benefit Payments The Pension Plans made actual benefit payments of $8.2 million , $2.8 million , and $3.3 million in the years ended December 31, 2015 , 2014 , and 2013 , respectively. Expected benefit payments over the next 10 years are as follows: Years Ending December 31, (in thousands) 2016 $ 3,618 2017 $ 4,350 2018 $ 4,605 2019 $ 6,057 2020 $ 6,846 2021 through 2025 $ 47,188 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Note 9 – Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the plugging and abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation (“ARO”) and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the operating section of the Company’s accompanying statements of cash flows. The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities range from 5.5 percent to 12 percent . In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors or the Company’s credit-adjusted risk-free rate as market conditions warrant. A reconciliation of the Company’s total asset retirement obligation liability is as follows: As of December 31, 2015 2014 (in thousands) Beginning asset retirement obligation $ 122,124 $ 121,186 Liabilities incurred 14,471 13,506 Liabilities settled (24,781 ) (11,372 ) Accretion expense 5,091 6,090 Revision to estimated cash flows 23,969 (7,286 ) Ending asset retirement obligation $ 140,874 $ 122,124 As of December 31, 2015 and 2014 , accounts payable and accrued expenses contain $3.3 million and $1.3 million , respectively, related to the Company’s current asset retirement obligation liability for estimated plugging and abandonment costs associated with platform structures that are being retired, which are also included in the table above. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Financial Instruments | Note 10 – Derivative Financial Instruments Summary of Oil, Gas, and NGL Derivative Contracts in Place The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivative contracts consist of swap arrangements for oil, gas, and NGLs. As of December 31, 2015 , the Company had commodity derivative contracts outstanding through the second quarter of 2020 for a total of 5.6 million Bbls of oil production, 172.7 million MMBtu of gas production, and 13.0 million Bbls of NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of December 31, 2015 : Oil Swaps Contract Period NYMEX WTI Volumes Weighted- Average Contract Price (Bbls) (per Bbl) First quarter 2016 1,868,000 $ 86.93 Second quarter 2016 1,752,000 $ 86.73 Third quarter 2016 1,170,000 $ 90.29 Fourth quarter 2016 780,000 $ 90.05 All oil swaps 5,570,000 Natural Gas Swaps Contract Period Volumes Weighted- Average Contract Price (MMBtu) (per MMBtu) First quarter 2016 23,341,000 $ 3.82 Second quarter 2016 20,780,000 $ 3.40 Third quarter 2016 18,829,000 $ 3.38 Fourth quarter 2016 17,236,000 $ 3.82 2017 37,528,000 $ 4.09 2018 30,606,000 $ 4.27 2019 24,415,000 $ 4.34 All gas swaps* 172,735,000 ____________________________________________ *Natural gas swaps are comprised of IF El Paso Permian ( 2% ), IF HSC ( 95% ), IF NGPL TXOK ( 1% ), and IF NNG Ventura ( 2% ). NGL Swaps OPIS Purity Ethane Mont Belvieu OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPIS Isobutane Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average (Bbls) (per Bbl) (Bbls) (per Bbl) (Bbls) (per Bbl) (Bbls) (per Bbl) First quarter 2016 926,000 $ 8.29 1,059,000 $ 19.60 143,000 $ 25.62 122,000 $ 25.87 Second quarter 2016 828,000 $ 8.28 949,000 $ 19.64 130,000 $ 25.62 111,000 $ 25.87 Third quarter 2016 751,000 $ 8.70 862,000 $ 19.03 — $ — — $ — Fourth quarter 2016 688,000 $ 8.71 791,000 $ 18.53 — $ — — $ — 2017 2,271,000 $ 9.16 — $ — — $ — — $ — 2018 1,671,000 $ 10.65 — $ — — $ — — $ — 2019 1,200,000 $ 10.92 — $ — — $ — — $ — 2020 539,000 $ 11.13 — $ — — $ — — $ — Total NGL swaps 8,874,000 3,661,000 273,000 233,000 Commodity Derivative Contracts Entered Into After December 31, 2015 Subsequent to December 31, 2015, the Company restructured certain of its gas derivative contracts by buying fixed price volumes to exactly offset existing 2018 and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No cash or other consideration was included as part of the restructuring. The net result of buying fixed price volumes in 2018 and 2019 is that the Company no longer has protection against natural gas price volatility in those years. These updated contracts are reflected in the following table, which summarizes the approximate gas volumes and average contract prices of contracts the Company had in place as of February 17, 2016 , including derivatives contracts for settlement anytime during the first quarter of 2016 and later periods: Natural Gas Swaps Contract Period Volumes Weighted- Average Contract Price Purchased Volumes Weighted- Average Contract Price Total Volumes (MMBtu) (per MMBtu) (MMBtu) (per MMBtu) (MMBtu) First quarter 2016 23,341,000 $ 3.82 — $ — 23,341,000 Second quarter 2016 20,780,000 $ 3.40 — $ — 20,780,000 Third quarter 2016 18,829,000 $ 3.38 — $ — 18,829,000 Fourth quarter 2016 17,236,000 $ 3.82 — $ — 17,236,000 2017 76,135,000 $ 4.26 — $ — 76,135,000 2018 30,606,000 $ 4.27 (30,606,000 ) $ 4.27 — 2019 24,415,000 $ 4.34 (24,415,000 ) $ 4.34 — All gas swaps* 211,342,000 (55,021,000 ) 156,321,000 ____________________________________________ *Total volumes of natural gas swaps are comprised of IF El Paso Permian ( 2% ), IF HSC ( 96% ), IF NGPL TXOK ( 1% ), and IF NNG Ventura ( 1% ). Additionally, subsequent to December 31, 2015, the Company entered into NGL fixed price swap contracts for 1.6 million Bbls of ethane production through 2018 with an average contract price of $8.67 per Bbl and 235,000 Bbls of isobutane production through the fourth quarter of 2016 with a contract price of $22.58 per Bbl. Derivative Assets and Liabilities Fair Value The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The fair value of the commodity derivative contracts was a net asset of $488.4 million and $592.1 million at December 31, 2015 and 2014 , respectively. The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: As of December 31, 2015 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity Contracts Current assets $ 367,710 Current liabilities $ 8 Commodity Contracts Noncurrent assets 120,701 Noncurrent liabilities — Derivatives not designated as hedging instruments $ 488,411 $ 8 As of December 31, 2014 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity Contracts Current assets $ 402,668 Current liabilities $ — Commodity Contracts Noncurrent assets 189,540 Noncurrent liabilities 70 Derivatives not designated as hedging instruments $ 592,208 $ 70 Offsetting of Derivative Assets and Liabilities As of December 31, 2015 and 2014 , all derivative instruments held by the Company were subject to master netting arrangements by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets. The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts: Derivative Assets Derivative Liabilities As of December 31, As of December 31, Offsetting of Derivative Assets and Liabilities 2015 2014 2015 2014 (in thousands) Gross amounts presented in the accompanying balance sheets $ 488,411 $ 592,208 $ (8 ) $ (70 ) Amounts not offset in the accompanying balance sheets (8 ) (70 ) 8 70 Net amounts $ 488,403 $ 592,138 $ — $ — Discontinuance of Cash Flow Hedge Accounting As of January 1, 2011, the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges at December 31, 2010. Fair values at December 31, 2010, were frozen in AOCL as of the de-designation date and were reclassified into earnings as the original derivative transactions settled. As of September 30, 2013, all commodity derivative contracts that had been previously designated as cash flow hedges had settled and had been reclassified into earnings from AOCL. Subsequent to December 31, 2010, the Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in AOCL. The Company had no derivatives designated as cash flow hedges for the years ended December 31, 2015 , 2014 , and 2013 , and no new gains or losses were deferred to AOCL during these respective years. Please refer to Note 11 - Fair Value Measurements for more information regarding the Company’s derivative instruments, including its valuation techniques. The following table summarizes the components of derivative gain presented in the accompanying statements of operations: For the Years Ended December 31, 2015 2014 2013 (in thousands) Derivative settlement (gain) loss: Oil contracts $ (362,219 ) $ (28,410 ) $ 15,161 Gas contracts (1) (123,180 ) 26,706 (30,338 ) NGL contracts (27,167 ) (10,911 ) (6,885 ) Total derivative settlement gain $ (512,566 ) $ (12,615 ) $ (22,062 ) Total derivative (gain) loss: Oil contracts $ (191,165 ) $ (457,082 ) $ 14,665 Gas contracts (189,734 ) (93,267 ) (14,053 ) NGL contracts (27,932 ) (32,915 ) (3,692 ) Total derivative gain $ (408,831 ) $ (583,264 ) $ (3,080 ) ____________________________________________ (1) Natural gas derivative settlements for the years ended December 31, 2015 , and 2014, include $15.3 million and $5.6 million , respectively, of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region. The following table details the effect of derivative instruments on AOCL and the accompanying statements of operations (net of income tax): Location on Accompanying Statements of Operations For the Years Ended December 31, Derivatives 2015 2014 2013 (in thousands) Amount reclassified from AOCL Commodity Contracts Other operating revenues $ — $ — $ 1,115 The realized net hedge loss for the year ended December 31, 2013, shown net of income tax in the table above, is comprised of realized settlements on commodity derivative contracts that were previously designated as cash flow hedges. Realized hedge gains or losses from the settlement of commodity derivatives previously designated as cash flow hedges are reported in the other operating revenues line item on the accompanying statements of operations. The Company realized a pre-tax net loss of $1.8 million from its commodity derivative contracts that were previously designated as cash flow hedges for the year ended December 31, 2013. Credit Related Contingent Features As of December 31, 2015 , and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. The Company’s obligations under its credit facility and derivative contracts are secured by mortgages on assets having a value equal to at least 75 percent of the total value of the Company’s proved oil and gas properties. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Disclosures [Text Block] | Note 11 – Fair Value Measurements The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: • Level 1 – quoted prices in active markets for identical assets or liabilities • Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable • Level 3 – significant inputs to the valuation model are unobservable The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2015 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 488,411 $ — Proved oil and gas properties (2) $ — $ — $ 124,184 Other property and equipment (2) $ — $ — $ 629 Liabilities: Derivatives (1) $ — $ 8 $ — Net Profits Plan (1) $ — $ — $ 7,611 ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2014 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 592,208 $ — Proved oil and gas properties (2) $ — $ — $ 33,423 Oil and gas properties held for sale (2) $ — $ — $ 17,891 Liabilities: Derivatives (1) $ — $ 70 $ — Net Profits Plan (1) $ — $ — $ 27,136 ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date. All of the Company’s derivative counterparties are members of the Company’s credit facility lender group. The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and with other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date. Refer to Note 10 - Derivative Financial Instruments for more information regarding the Company’s derivative instruments. Net Profits Plan The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. The inputs available for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income valuation technique, which converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and lower commodity prices result in a smaller Net Profits Plan liability. The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. Discount rates of 10 percent and 12 percent were used to calculate this liability as of December 31, 2015, and 2014, respectively, and are intended to represent the Company’s best estimate of the present value of expected future payments under the Net Profits Plan. The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, discount rates, and overall market conditions. The Company regularly assesses the current market environment. The Net Profits Plan liability is determined using price assumptions of five one -year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price differentials and to include the effects of the forecasted production covered by derivative contracts in the relevant periods. The non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the oil, gas, and NGL commodity markets. If the commodity prices used in the calculation changed by five percent , the liability recorded at December 31, 2015 , would differ by approximately $1.1 million . A one percent increase or decrease in the discount rate would result in a change of approximately $300,000 . Actual cash payments to be made to participants in future periods are dependent on realized actual production, realized commodity prices, and costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated. No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits Plan liability. As such, the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation of fair value of the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates. The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs: For the Years Ended December 31, 2015 2014 2013 (in thousands) Beginning balance $ 27,136 $ 56,985 $ 78,827 Net increase (decrease) in liability (1) (12,238 ) (12,492 ) 3,527 Net settlements (1) (2) (7,287 ) (17,357 ) (25,369 ) Transfers in (out) of Level 3 — — — Ending balance $ 7,611 $ 27,136 $ 56,985 ____________________________________________ (1) Net changes in the Company’s Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations. (2) Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash payments made or accrued under the Net Profits Plan of $3.8 million , $8.3 million , and $10.3 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively, as a result of the divestitures of properties subject to the Net Profits Plan. Long-Term Debt The following table reflects the fair value of the Senior Notes measured using Level 1 inputs based on quoted secondary market trading prices. The Senior Notes were not presented at fair value on the accompanying balance sheets as of December 31, 2015 or 2014 , as they are recorded at carrying value, net of unamortized deferred financing costs. As of December 31, 2015 2014 (in thousands) 2019 Notes (1) $ — $ 350,018 2021 Notes $ 262,938 $ 343,000 2022 Notes $ 440,250 $ 556,500 2023 Notes $ 296,000 $ 379,000 2024 Notes $ 334,065 $ 435,000 2025 Notes (1) $ 326,875 $ — ____________________________________________ (1) The 2019 Notes were fully redeemed on June 22, 2015 and the 2025 Notes were issued on May 21, 2015 . The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates. Proved and Unproved Oil and Gas Properties Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management. The calculation of the discount rate is based on the best information available and was estimated to be 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows as of December 31, 2015 . A 12 percent discount rate was estimated as of December 31, 2014 . The Company believes the discount rate is representative of current market conditions and takes into account estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. The Company recorded impairment of proved oil and gas properties expense of $468.7 million for the year ended December 31, 2015 , due to the decline in proved and risk-adjusted probable and possible reserve expected cash flows, driven by the continued commodity price declines. Impairments were recorded mainly in the Company’s east Texas and Powder River Basin programs with smaller impacts on other legacy and non-core assets in the Rocky Mountain region. These assets were impaired to fair value totaling $124.2 million as of December 31, 2015 . The Company recorded impairment of proved oil and gas properties expense of $84.5 million for the year ended December 31, 2014, resulting from the significant decline in commodity prices at the end of 2014 and recognition of the outcomes of exploration and delineation wells in certain prospects in the Company’s South Texas & Gulf Coast and Permian regions. As of December 31, 2014 , proved oil and gas properties measured at fair value totaled $33.4 million . Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, and estimated reserve values. The Company recorded abandonment and impairment of unproved oil and gas properties expense of $78.6 million and $75.6 million for the years ended December 31, 2015 , and 2014, respectively, resulting from lease expirations and acreage the Company no longer intended to develop in light of changes in drilling plans in response to the decline in commodity prices. Unproved properties measured at fair value were zero in the accompanying balance sheets as of December 31, 2015 , and 2014 . Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. Fair value of other property and equipment is valued using an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets. The Company recorded impairment of other property and equipment expense of $49.4 million for the year ended December 31, 2015 , on the Company’s gathering system assets in its east Texas program. These assets were impaired in conjunction with the impairment of the associated proved and unproved properties, which the Company does not intend to develop during an environment of sustained low commodity prices. The fair value of these assets at December 31, 2015 , was $629,000 . Proved properties classified as held for sale, including the corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company estimates acreage value based on the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. For the years ended December 31, 2015 , and 2014, write-downs on certain assets held for sale totaled $98.6 million and $27.6 million , respectively. These write-downs are included within the net gain on divestiture activity line item on the accompanying statements of operations. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for further discussion. There were no assets held for sale recorded at fair value as of December 31, 2015, as the carrying value was below the estimated fair value less costs to sell. As of December 31, 2014, assets held for sale measured at fair value totaled $17.9 million . The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation. Refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional information on the fair value of assets acquired during 2014. |
Acquisition and Development Agr
Acquisition and Development Agreement and Carry and Earning Agreement | 12 Months Ended |
Dec. 31, 2015 | |
Acquisition and Development Agreement and Carry and Earning Agreement [Abstract] | |
Acquisition and Development Agreement and Carry and Earning Agreement | Note 12 - Acquisition and Development Agreement In June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui (the “Acquisition and Development Agreement”). Pursuant to the Acquisition and Development Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in certain non-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs attributable to the Company’s remaining interest in these assets until Mitsui expended an aggregate $680.0 million on behalf of the Company. The Acquisition and Development Agreement also provided for reimbursement of capital expenditures and other costs, net of revenues, paid by the Company that were attributable to the transferred interest during the period between the effective date and the closing date, which the parties agreed would be applied over the carry period to cover the Company’s remaining 10 percent of drilling and completion costs for the affected acreage. During the second quarter of 2014, the remainder of the carry under the Acquisition and Development Agreement was expended. Accordingly, the Company accrued and funded its full share of drilling and completion costs in its non-operated Eagle Ford shale program for the remainder of 2014 and all of 2015. |
Suspended Well Costs
Suspended Well Costs | 12 Months Ended |
Dec. 31, 2015 | |
Suspended Well Costs [Abstract] | |
Suspended Well Costs Disclosure [Text Block] | Note 13 - Suspended Well Costs The following table reflects the net changes in capitalized exploratory well costs during 2015 , 2014 , and 2013 . The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year: For the Years Ended December 31, 2015 2014 2013 (in thousands) Beginning balance on January 1, $ 43,589 $ 34,527 $ 9,100 Additions to capitalized exploratory well costs pending the determination of proved reserves 11,952 43,589 34,527 Divestitures (809 ) — — Reclassifications to wells, facilities, and equipment based on the determination of proved reserves (18,485 ) (33,340 ) (9,100 ) Capitalized exploratory well costs charged to expense (24,295 ) (1,187 ) — Ending balance at December 31, $ 11,952 $ 43,589 $ 34,527 As of December 31, 2015 , there were no exploratory well costs that were capitalized for more than one year. |
Summary of Significant Accoun22
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Consolidation, Policy [Policy Text Block] | Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Subsidiaries that the Company does not control are accounted for using the equity or cost methods as appropriate. Equity method investments are included in other noncurrent assets in the accompanying consolidated balance sheets (“accompanying balance sheets”). Intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2015 , through the filing date of this report. Certain prior period amounts have been reclassified to conform to the current period presentation on the accompanying financial statements. |
Use of Estimates, Policy [Policy Text Block] | Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization expense, impairment of proved properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements. |
Cash and Cash Equivalents, Policy [Policy Text Block] | Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. |
Receivables, Policy [Policy Text Block] | Accounts Receivable The Company’s accounts receivable consist mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months and the Company has had minimal bad debts. Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. |
Concentration Risk, Credit Risk, Policy [Policy Text Block] | Concentration of Credit Risk and Major Customers The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to regular review. The Company does not believe the loss of any single purchaser would materially impact its operating results, as crude oil, natural gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating regions. During 2015 and 2014, the Company had one major customer, which represented approximately 21 percent and 19 percent , respectively, of total production revenue, which is discussed in the next paragraph. During 2015 and 2014 , the Company also sold to four entities that are under common ownership. In aggregate, these four entities represented approximately 10 percent and 14 percent of total production revenue in 2015 and 2014 , respectively; however, none of these entities individually represented more than 10 percent of total production revenue. Additionally, in 2015 the Company sold to three entities that are under common ownership, which in aggregate represented 11 percent of its total production revenue; however, none of these entities individually represented more than 10 percent of the Company’s total production revenue. During 2013 , the Company had three major customers, which represented approximately 26 percent , 16 percent , and 12 percent , respectively, of total production revenue. During the third quarter of 2013, the Company entered into various marketing agreements with a joint venture partner, whereby the Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. While the Company’s joint venture partner is the first purchaser under these contracts, representing 21 percent and 19 percent of total production revenue in 2015 and 2014 , respectively, the Company also shares with them the risk of non-performance by their counterparty purchasers. Several of the Company’s joint venture partner’s counterparty purchasers under these contracts are also direct purchasers of products produced by the Company from other operated areas. The Company’s policy is to use the commodity affiliates of the lenders under its credit facility as its derivative counterparties, and each counterparty must have investment grade senior unsecured debt ratings. Each of the Company’s 10 counterparties meet both of these requirements as of the filing date of this report. The Company has accounts in the following locations with a national bank: Denver, Colorado ; Houston, Texas ; Midland, Texas ; and Billings, Montana . The Company’s policy is to invest in highly-rated instruments and to limit the amount of credit exposure at each individual institution. |
Full Cost or Successful Efforts, Policy [Policy Text Block] | Oil and Gas Producing Activities The Company accounts for its oil and gas exploration and development costs using the successful efforts method. G&G costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures within the accompanying statements of cash flows. The costs of development wells are capitalized whether those wells are successful or unsuccessful. DD&A of capitalized costs related to proved oil and gas properties is calculated on a pool-by-pool basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. |
Assets Held For Sale [Policy Text Block] | Assets Held for Sale Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presented on the accompanying balance sheets at the lower of carrying value or fair value less the cost to sell. |
Property, Plant and Equipment, Policy [Policy Text Block] | Other Property and Equipment Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from three to 30 years, or the unit of output method where appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. |
Internal Use Software, Policy [Policy Text Block] | Internal Use Software Development Costs The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. |
Net Profits Plan [Policy Text Block] | Net Profits Plan The Company records the estimated fair value of expected future payments to be made under the Net Profits Plan as a noncurrent liability in the accompanying balance sheets. The underlying assumptions used in the calculation of the estimated liability include estimates of production, proved reserves, recurring and workover lease operating expense, transportation, production and ad valorem tax rates, present value discount factors, pricing assumptions, and overall market conditions. The estimates used in calculating the long-term liability are adjusted from period-to-period based on the most current information attributable to the underlying assumptions. Changes in the estimated liability of future payments associated with the Net Profits Plan are recorded as increases or decreases to expense in the current period as a separate line item in the accompanying statements of operations, as these changes are considered changes in estimates. The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash compensation related to periodic operations are recognized as compensation expense and are included within general and administrative expense and exploration expense in the accompanying statements of operations. The corresponding current liability is included in accounts payable and accrued expenses in the accompanying balance sheets. This treatment provides for a consistent matching of cash expense with net cash flows from the oil and gas properties in each respective pool of the Net Profits Plan. |
Asset Retirement Obligations, Policy [Policy Text Block] | Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. |
Revenue Recognition, Policy [Policy Text Block] | Revenue Recognition The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized when the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses knowledge of its properties and historical performance, contractual agreements, NYMEX, OPIS, and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates. The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized on all gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. |
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block] | Impairment of Proved and Unproved Properties Proved oil and gas property costs are evaluated for impairment and reduced to fair value, which is based on expected future discounted cash flows, when there is an indication that the carrying costs may not be recoverable. Expected future cash flows are calculated on all proved reserves and risk adjusted probable and possible reserves using a discount rate and price forecasts that management believes are representative of current market conditions. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. An impairment is recorded on unproved property when the Company determines that either the property will not be developed or the carrying value is not realizable. |
Property, Plant and Equipment, Impairment [Policy Text Block] | Impairment of Other Property and Equipment A long-lived asset is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may be greater than its undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying value over its estimated fair value. The Company uses an income valuation technique if there is not a market-observable price for the asset. |
Disposition of Proved and Unproved Property [Policy Text Block] | Sales of Proved and Unproved Properties The partial sale of proved property within an existing field is accounted for as normal retirement and no net gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A net gain on divestiture activity is recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of unproved property. |
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block] | Stock-Based Compensation At December 31, 2015 , the Company had stock-based employee compensation plans that included RSUs, PSUs, and restricted stock awards issued to employees and non-employee directors, as more fully described in Note 7 - Compensation Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and included within general and administrative expense and exploration expense in the accompanying statements of operations. |
Income Tax, Policy [Policy Text Block] | Income Taxes The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. |
Earnings Per Share, Policy [Policy Text Block] | Earnings per Share Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company. Diluted net income (loss) per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs, contingent PSUs, and in-the-money outstanding stock options. When there is a loss from continuing operations, as was the case for the year ended December 31, 2015, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three -year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading Performance Share Units Under the Equity Plan . The treasury stock method is used to measure the dilutive impact of unvested RSUs, contingent PSUs, and in-the-money stock options. |
Comprehensive Income, Policy [Policy Text Block] | Comprehensive Income (Loss) Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss). |
Segment Reporting, Policy [Policy Text Block] | Industry Segment and Geographic Information The Company operates in the exploration and production segment of the oil and gas industry within the United States. The Company reports as a single industry segment. The Company sold its Mid-Continent assets in 2015, and therefore, no longer has marketed gas volumes as of December 31, 2015. Prior to the sale of these assets, the Company’s gas marketing function provided mostly internal services and acted as the first purchaser of natural gas and natural gas liquids produced by the Company in certain cases. The Company considered its marketing function as ancillary to its oil and gas producing activities. The amount of income these operations generated from marketing gas produced by third parties was not material to the Company’s results of operations, and segmentation of such activity would not have provided a better understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties is presented in the marketed gas system revenue and marketed gas system expense line items in the accompanying statements of operations. |
Off-Balance-Sheet Credit Exposure, Policy [Policy Text Block] | Off-Balance Sheet Arrangements The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that SM Energy is the primary beneficiary of a variable interest entity, that entity is consolidated into SM Energy. |
New Accounting Pronouncements, Policy [Policy Text Block] | Recently Issued Accounting Standards In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue from contracts with customers. This guidance is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance. In August 2015, the FASB deferred the effective date of the new revenue recognition standard by one year. The revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures. In August 2014, the FASB issued new authoritative guidance that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures but does not believe it will impact the Company’s financial statements or disclosures. Effective January 1, 2015, the Company adopted, on a prospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-01, “Income Statement – Extraordinary and Unusual Items.” This ASU simplifies income statement presentation by eliminating the concept of extraordinary items. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard. In February 2015, the FASB issued new authoritative accounting guidance meant to clarify the consolidation reporting guidance in GAAP. This guidance is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures. Effective November 1, 2015, the Company early adopted, on a retrospective basis, FASB ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”). ASU 2015-03 requires deferred financing costs to be presented on the accompanying balance sheets as a direct deduction from the carrying value of the related debt liability. In accordance, the Company has reclassified $33.6 million of deferred financing costs related to its Senior Notes at December 31, 2014, from the other noncurrent assets line item to the Senior Notes, net of unamortized deferred financing costs line item. The December 31, 2014, accompanying balance sheet line items that were adjusted as a result of the adoption of ASU 2015-03 are presented in the following table: As of December 31, 2014 As Reported As Adjusted (in thousands) Other noncurrent assets $ 78,214 $ 44,659 Total other noncurrent assets $ 267,754 $ 234,199 Total Assets $ 6,516,700 $ 6,483,145 Senior Notes $ 2,200,000 N/A Senior Notes, net of unamortized deferred financing costs N/A $ 2,166,445 Total noncurrent liabilities $ 3,445,385 $ 3,411,830 Total Liabilities and Stockholders’ Equity $ 6,516,700 $ 6,483,145 ASU 2015-03 does not specifically address the accounting for deferred financing costs related to line-of-credit arrangements. In August 2015, the FASB issued ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” (“ASU 2015-15”) allowing for deferred financing costs associated with line-of-credit arrangements to continue to be presented as assets. ASU 2015-15 is consistent with how the Company currently accounts for deferred financing costs related to the Company’s revolving credit facility. Effective December 1, 2015, the Company early adopted, on a prospective basis, FASB ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes” (“ASU 2015-17”). ASU 2015-17 requires that deferred tax liabilities and assets, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments in ASU 2015-17. As ASU 2015-17 was adopted on a prospective basis, the Company did not retrospectively adjust prior periods. There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of December 31, 2015 , and through the filing date of this report. |
Pension Benefits Policy [Policy Text Block] | The Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment to accumulated other comprehensive income, net of tax. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31. |
Fair Value Measurement Policy Surrounding Derivatives | The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. |
Pension Benefits Pension and Ot
Pension Benefits Pension and Other Post-retirement Plans (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Pension and Other Post-Retirement Accounting Policies [Abstract] | |
Pension Benefits Policy [Policy Text Block] | The Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment to accumulated other comprehensive income, net of tax. The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31. |
Derivative Financial Instrume24
Derivative Financial Instruments Derivatives Policy (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Fair Value Measurement Policy Surrounding Derivatives | The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value of Financial Instruments (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. |
Summary of Significant Accoun26
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Basis of Presentation and Significant Accounting Policies [Abstract] | |
Comprehensive Income (Loss) [Table Text Block] | The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table: Derivative Adjustments (1) Pension Liability Adjustments (in thousands) For the year ended December 31, 2013 Net actuarial gain $ 2,766 Reclassification to earnings $ 1,777 1,239 Tax expense (662 ) (1,522 ) Income, net of tax $ 1,115 $ 2,483 For the year ended December 31, 2014 Net actuarial loss $ (10,062 ) Reclassification to earnings $ — 706 Tax benefit — 3,460 Loss, net of tax $ — $ (5,896 ) For the year ended December 31, 2015 Net actuarial loss $ (4,990 ) Reclassification to earnings $ — 1,853 Tax benefit — 1,047 Loss, net of tax $ — $ (2,090 ) ____________________________________________ (1) As of December 31, 2013, all commodity derivative contracts that had been previously designated as cash flow hedges had settled and had been reclassified into earnings from AOCL. |
Dilutive and Anti-Dilutive Shares for Earnings per Share [Table Text Block] | The following table details the weighted-average dilutive and anti-dilutive securities related to RSUs, PSUs, and stock options for the years presented: For the Years Ended December 31, 2015 2014 2013 (in thousands) Dilutive — 814 1,383 Anti-dilutive 256 — — |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | The following table sets forth the calculations of basic and diluted earnings per share: For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share amounts) Net income (loss) $ (447,710 ) $ 666,051 $ 170,935 Basic weighted-average common shares outstanding 67,723 67,230 66,615 Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs (1) — 814 1,383 Diluted weighted-average common shares outstanding 67,723 68,044 67,998 Basic net income (loss) per common share $ (6.61 ) $ 9.91 $ 2.57 Diluted net income (loss) per common share $ (6.61 ) $ 9.79 $ 2.51 ____________________________________________ (1) For the year ended December 31, 2015, the shares were anti-dilutive and excluded from the calculation of diluted earnings per share. |
Summary of Significant Accoun27
Summary of Significant Accounting Policies New Accounting Pronouncements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
New Accounting Pronouncement, Early Adoption [Table Text Block] | The December 31, 2014, accompanying balance sheet line items that were adjusted as a result of the adoption of ASU 2015-03 are presented in the following table: As of December 31, 2014 As Reported As Adjusted (in thousands) Other noncurrent assets $ 78,214 $ 44,659 Total other noncurrent assets $ 267,754 $ 234,199 Total Assets $ 6,516,700 $ 6,483,145 Senior Notes $ 2,200,000 N/A Senior Notes, net of unamortized deferred financing costs N/A $ 2,166,445 Total noncurrent liabilities $ 3,445,385 $ 3,411,830 Total Liabilities and Stockholders’ Equity $ 6,516,700 $ 6,483,145 |
Accounts Receivable and Accou28
Accounts Receivable and Accounts Payable and Accrued Expenses Accounts Receivable and Accounts Payable and Accrued Expenses (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounts Receivable and Accounts Payable and Accrued Expenses [Abstract] | |
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block] | Accounts receivable are comprised of the following: As of December 31, 2015 2014 (in thousands) Accrued oil, gas, and NGL production revenue $ 58,256 $ 180,250 Amounts due from joint interest owners 22,269 58,347 Accrued derivative settlements 34,579 39,811 State severance tax refunds 12,072 24,394 Other 6,948 19,828 Total accounts receivable $ 134,124 $ 322,630 |
Schedule of Accounts Payable and Accrued Liabilities [Table Text Block] | Accounts payable and accrued expenses are comprised of the following: As of December 31, 2015 2014 (in thousands) Accrued capital expenditures $ 97,355 $ 357,156 Revenue and severance tax payable 44,387 63,779 Accrued lease operating expense 21,943 34,822 Accrued property taxes 14,078 15,059 Accrued compensation 41,154 56,279 Accrued interest 34,378 40,786 Other 49,222 72,803 Total accounts payable and accrued expenses $ 302,517 $ 640,684 |
Acquisitions, Divestitures, a29
Acquisitions, Divestitures, and Assets Held for Sale Fair Value of Acquired Properties (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value of Net Assets Acquired [Table Text Block] | The Company determined that both of these acquisitions met the criteria of a business combination under Accounting Standards Codification (“ASC”) Topic 805, Business Combinations . The Company allocated the final adjusted purchase price to the acquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below. Refer to Note 11 – Fair Value Measurements for additional discussion on the valuation techniques used in determining the fair value of acquired properties. Acquisition #1 Acquisition #2 As of September 24, 2014 As of October 15, 2014 Purchase Price (in thousands) Cash consideration $ 321,807 $ 84,836 Fair value of assets and liabilities acquired: Proved oil and gas properties $ 203,467 $ 54,612 Unproved oil and gas properties 126,588 29,610 Total fair value of oil and gas properties acquired 330,055 84,222 Working capital (6,135 ) 2,232 Asset retirement obligation (2,113 ) (1,618 ) Total fair value of net assets acquired $ 321,807 $ 84,836 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule of componenets of provision for income taxes | The provision for income taxes consists of the following: For the Years Ended December 31, 2015 2014 2013 (in thousands) Current portion of income tax expense Federal $ — $ — $ — State 1,571 868 2,121 Deferred portion of income tax expense (benefit) (276,722 ) 397,780 105,555 Total income tax expense (benefit) $ (275,151 ) $ 398,648 $ 107,676 Effective tax rate 38.1 % 37.4 % 38.6 % |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | The components of the net deferred income tax liabilities are as follows: As of December 31, 2015 2014 (in thousands) Deferred tax liabilities: Oil and gas properties $ 854,029 $ 1,029,424 Derivative asset 179,543 220,437 Other 1,233 4,475 Total deferred tax liabilities 1,034,805 1,254,336 Deferred tax assets: Federal and state tax net operating loss carryovers 244,942 184,447 Stock compensation 14,529 16,763 Other liabilities 27,449 25,715 Total deferred tax assets 286,920 226,925 Valuation allowance (10,394 ) (7,246 ) Net deferred tax assets 276,526 219,679 Total net deferred tax liabilities (1) $ 758,279 $ 1,034,657 Current federal income tax refundable $ 5,378 $ 4,734 Current state income tax refundable $ 65 $ — Current state income tax payable $ — $ 25 ____________________________________________ (1) All deferred tax liabilities and assets as of December 31, 2015, are classified as noncurrent on the accompanying balance sheets upon the Company’s adoption of ASU 2015-17 on a prospective basis. Prior year amounts have not been restated. Please refer to the caption Recently Issued Accounting Standards in Note 1 - Summary of Significant Accounting Policies for additional discussion. |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, R&D credits, and other permanent differences, as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Federal statutory tax expense (benefit) $ (253,001 ) $ 372,644 $ 97,514 Increase (decrease) in tax resulting from: State tax expense (benefit) (net of federal benefit) (21,583 ) 21,350 9,400 Change in valuation allowance 3,148 2,245 (314 ) Research and development credit (1,971 ) — — Other (1,744 ) 2,409 1,076 Income tax expense (benefit) $ (275,151 ) $ 398,648 $ 107,676 |
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block] | The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2015 2014 2013 (in thousands) Beginning balance $ 1,582 $ 2,358 $ 2,278 Additions for tax positions of prior years 1,200 140 80 Settlements — (916 ) — Ending balance $ 2,782 $ 1,582 $ 2,358 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Schedule of Borrowing Base Utilization, Credit Facility [Table Text Block] | Interest and commitment fees are accrued based on the borrowing base utilization grid below. Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternate Base Rate (“ABR”) and swingline loans accrue interest at Prime plus the applicable margin from the utilization table below. Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying statements of operations. Borrowing Base Utilization Grid Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans 1.250 % 1.500 % 1.750 % 2.000 % 2.250 % ABR Loans or Swingline Loans 0.250 % 0.500 % 0.750 % 1.000 % 1.250 % Commitment Fee Rate 0.300 % 0.300 % 0.350 % 0.375 % 0.375 % |
Schedule of Line of Credit Facilities [Table Text Block] | The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of February 17, 2016 , December 31, 2015 , and December 31, 2014 : As of February 17, 2016 As of December 31, 2015 As of December 31, 2014 (in thousands) Credit facility balance (1) $ 243,000 $ 202,000 $ 166,000 Letters of credit (2) $ 200 $ 200 $ 808 Available borrowing capacity $ 1,256,800 $ 1,297,800 $ 1,333,192 ____________________________________________ (1) Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and thus are not deducted from the credit facility balance. (2) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis. |
Schedule of Long-term Debt Instruments [Table Text Block] | The Senior Notes, net of unamortized deferred financing costs, line on the accompanying balance sheets as of December 31, 2015 , and 2014 , consisted of the following: As of December 31, 2015 2014 (1) Senior Notes Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Senior Notes Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs (in thousands) 6.625% Notes due 2019 $ — $ — $ — $ 350,000 $ 4,591 $ 345,409 6.50% Notes due 2021 350,000 4,106 345,894 350,000 4,806 345,194 6.125% Notes due 2022 600,000 8,714 591,286 600,000 9,812 590,188 6.50% Notes due 2023 400,000 5,231 394,769 400,000 5,969 394,031 5.0% Notes due 2024 500,000 7,455 492,545 500,000 8,377 491,623 5.625% Notes due 2025 500,000 8,524 491,476 — — — Total $ 2,350,000 $ 34,030 $ 2,315,970 $ 2,200,000 $ 33,555 $ 2,166,445 ____________________________________________ (1) Prior period amounts have been reclassified to conform to the current period presentation on the accompanying balance sheets. Please refer to the section Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional discussion. |
Commitments and Contingencies C
Commitments and Contingencies Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block] | The annual minimum payments for the next five years and total minimum payments thereafter are presented below: Years Ending December 31, Amount (1) (in thousands) 2016 $ 132,747 2017 128,074 2018 131,489 2019 142,161 2020 141,854 Thereafter 288,113 Total $ 964,438 ____________________________________________ (1) During the third quarter of 2015, the Company vacated its office space in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive $3.5 million of sublease income as follows: $831,000 in 2016 , $953,000 in 2017 , $978,000 in 2018 , and $741,000 in 2019 . |
Compensation Plans (Tables)
Compensation Plans (Tables) | 12 Months Ended | |
Dec. 31, 2015 | ||
Compensation Related Costs [Abstract] | ||
Schedule of performance share awards under equity incentive compensation plan | A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2015 2014 2013 PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value Non-vested at beginning of year (1) 433,660 $ 73.63 572,469 $ 66.07 669,308 $ 63.91 Granted (1) 320,753 $ 45.34 202,404 $ 94.66 274,831 $ 64.13 Vested (1) (76,438 ) $ 51.76 (206,830 ) $ 64.79 (345,005 ) $ 60.06 Forfeited (1) (51,647 ) $ 73.62 (134,383 ) $ 86.72 (26,665 ) $ 69.74 Non-vested at end of year (1) 626,328 $ 61.81 433,660 $ 73.63 572,469 $ 66.07 ____________________________________________ (1) The number of awards assumes a multiplier of one . The final number of shares of common stock issued may vary depending on the three -year performance multiplier, which ranges from zero to two . | [1] |
Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block] | A summary of the status and activity of non-vested RSUs is presented below: For the Years Ended December 31, 2015 2014 2013 RSUs Weighted- Average Grant-Date Fair Value RSUs Weighted- Average Grant-Date Fair Value RSUs Weighted- Average Grant-Date Fair Value Non-vested at beginning of year 515,724 $ 68.29 580,431 $ 57.05 496,244 $ 51.81 Granted 356,246 $ 43.72 234,560 $ 83.98 329,939 $ 60.01 Vested (278,289 ) $ 63.12 (253,031 ) $ 58.19 (207,376 ) $ 49.73 Forfeited (49,944 ) $ 66.53 (46,236 ) $ 62.06 (38,376 ) $ 54.37 Non-vested at end of year 543,737 $ 55.01 515,724 $ 68.29 580,431 $ 57.05 | |
Schedule of stock option grants under prior stock option plans | A summary of activity associated with the Company’s Stock Option Plans during the years ended December 31, 2014, and 2013, is presented in the following table: Weighted - Average Aggregate Exercise Intrinsic Shares Price Value For the year ended December 31, 2013 Outstanding, start of year 267,846 $ 14.95 Exercised (228,758 ) $ 13.92 $ 12,326,994 Forfeited — $ — Outstanding, end of year 39,088 $ 20.87 $ 2,432,837 Vested and exercisable at end of year 39,088 $ 20.87 $ 2,432,837 For the year ended December 31, 2014 Outstanding, start of year 39,088 $ 20.87 Exercised (39,088 ) $ 20.87 $ 1,993,726 Forfeited — $ — Outstanding, end of year — $ — $ — Vested and exercisable at end of year — $ — $ — | |
Schedule of employee stock purchase plan | The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions: For the Years Ended December 31, 2015 2014 2013 Risk free interest rate 0.1 % 0.1 % 0.1 % Dividend yield 0.2 % 0.1 % 0.2 % Volatility factor of the expected market price of the Company’s common stock 61.2 % 33.0 % 41.1 % Expected life (in years) 0.5 0.5 0.5 | |
Schedule of net profits plan cash payment allocation | Cash payments made or accrued under the Net Profits Plan that have been recorded as either general and administrative expense or exploration expense are detailed in the table below: For the Years Ended December 31, 2015 2014 2013 (in thousands) General and administrative expense $ 3,239 $ 8,326 $ 13,734 Exploration expense 259 690 1,310 Total $ 3,498 $ 9,016 $ 15,044 | |
[1] | The number of awards assumes a multiplier of one. The final number of shares of common stock issued may vary depending on the three-year performance multiplier, which ranges from zero to two. |
Pension Benefits (Tables)
Pension Benefits (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |
Schedule of Net Funded Status [Table Text Block] | For the Years Ended December 31, 2015 2014 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 57,867 $ 43,285 Service cost 7,949 6,335 Interest cost 2,496 2,191 Actuarial loss 2,397 8,821 Benefits paid (8,162 ) (2,765 ) Projected benefit obligation at end of year 62,547 57,867 Change in plan assets: Fair value of plan assets at beginning of year 27,940 24,658 Actual return on plan assets (410 ) 737 Employer contribution 6,401 5,310 Benefits paid (8,162 ) (2,765 ) Fair value of plan assets at end of year 25,769 27,940 Funded status at end of year $ (36,778 ) $ (29,927 ) |
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block] | Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans As of December 31, 2015 2014 (in thousands) Projected benefit obligation $ 62,547 $ 57,867 Accumulated benefit obligation $ 46,439 $ 43,205 Less: Fair value of plan assets (25,769 ) (27,940 ) Underfunded accumulated benefit obligation $ 20,670 $ 15,265 |
Schedule of Net Periodic Benefit Cost Not yet Recognized [Table Text Block] | Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensive loss as of December 31, 2015 and 2014 , consist of: As of December 31, 2015 2014 (in thousands) Unrecognized actuarial losses $ 20,966 $ 17,812 Unrecognized prior service costs 101 118 Unrecognized transition obligation — — Accumulated other comprehensive loss $ 21,067 $ 17,930 |
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block] | Pre-tax changes recognized in other comprehensive income (loss) during 2015 , 2014 , and 2013 , were as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Net actuarial gain (loss) $ (4,990 ) $ (10,062 ) $ 2,766 Prior service cost — — — Less: Amortization of prior service cost (17 ) (17 ) (17 ) Amortization of net actuarial loss (1,486 ) (689 ) (1,222 ) Settlements (350 ) — — Total other comprehensive income (loss) $ (3,137 ) $ (9,356 ) $ 4,005 |
Components of the net periodic benefit cost for both the Qualified and the Nonqualified Pension Plan | Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2015 2014 2013 (in thousands) Components of net periodic benefit cost: Service cost $ 7,949 $ 6,335 $ 6,291 Interest cost 2,496 2,191 1,627 Expected return on plan assets that reduces periodic pension cost (2,182 ) (1,978 ) (1,538 ) Amortization of prior service cost 17 17 17 Amortization of net actuarial loss 1,486 689 1,222 Settlements 350 — — Net periodic benefit cost $ 10,116 $ 7,254 $ 7,619 |
Schedule of Assumptions Used [Table Text Block] | Weighted-average assumptions to measure the Company’s projected benefit obligation and net periodic benefit cost are as follows: As of December 31, 2015 2014 2013 Projected benefit obligation Discount rate 4.7% 4.3% 5.0% Rate of compensation increase 6.2% 6.2% 6.2% Net periodic benefit cost Discount rate 4.3% 5.0% 3.9% Expected return on plan assets (1) 7.5% 7.5% 7.5% Rate of compensation increase 6.2% 6.2% 6.2% ____________________________________________ (1) There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan. |
Schedule of Allocation of Plan Assets Summary [Table Text Block] | The weighted-average asset allocation of the Qualified Pension Plan is as follows: Target As of December 31, Asset Category 2016 2015 2014 Equity securities 42.0 % 39.1 % 39.6 % Fixed income securities 35.0 % 34.0 % 33.9 % Other securities 23.0 % 26.9 % 26.5 % Total 100.0 % 100.0 % 100.0 % |
Schedule of Allocation of Plan Assets [Table Text Block] | The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2015 and 2014 , utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements are as follows: Fair Value Measurements Using: Actual Asset Allocation Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (in thousands) As of December 31, 2015 Cash — % $ — $ — $ — $ — Equity Securities: Domestic (1) 26.1 % 6,729 4,943 1,786 — International (2) 13.0 % 3,353 3,353 — — Total Equity Securities 39.1 % 10,082 8,296 1,786 — Fixed Income Securities: High-Yield Bonds (3) 2.8 % 722 722 — — Core Fixed Income (4) 22.5 % 5,789 5,789 — — Floating Rate Corp Loans (5) 8.7 % 2,247 2,247 — — Total Fixed Income Securities 34.0 % 8,758 8,758 — — Other Securities: Commodities (6) 2.7 % 700 700 — — Real Estate (7) 5.8 % 1,499 — — 1,499 Collective Investment Trusts (8) 4.6 % 1,184 — 1,184 — Hedge Fund (9) 13.8 % 3,546 — — 3,546 Total Other Securities 26.9 % 6,929 700 1,184 5,045 Total Investments 100.0 % $ 25,769 $ 17,754 $ 2,970 $ 5,045 As of December 31, 2014 Cash — % $ — $ — $ — $ — Equity Securities: Domestic (1) 27.1 % 7,569 5,550 2,019 — International (2) 12.5 % 3,498 3,498 — — Total Equity Securities 39.6 % 11,067 9,048 2,019 — Fixed Income Securities: High-Yield Bonds (3) 2.9 % 797 797 — — Core Fixed Income (4) 22.4 % 6,247 6,247 — — Floating Rate Corp Loans (5) 8.6 % 2,413 2,413 — — Total Fixed Income Securities 33.9 % 9,457 9,457 — — Other Securities: Commodities (6) 2.9 % 810 810 — — Real Estate (7) 4.7 % 1,327 — — 1,327 Collective Investment Trusts (8) 4.1 % 1,149 — 1,149 — Hedge Fund (9) 14.8 % 4,130 593 — 3,537 Total Other Securities 26.5 % 7,416 1,403 1,149 4,864 Total Investments 100.0 % $ 27,940 $ 19,908 $ 3,168 $ 4,864 ____________________________________________ (1) Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of this fund is to approximate the S&P 500 by investing in one or more collective investment funds. (2) International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations. (3) High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis. (4) The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index. (5) Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. (6) Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities. (7) The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. (8) Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities. (9) The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies. |
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block] | Included below is a summary of the changes in Level 3 plan assets (in thousands): Balance at January 1, 2014 $ 3,421 Purchases 1,232 Realized gain on assets 144 Unrealized gain on assets 67 Balance at December 31, 2014 $ 4,864 Purchases — Realized gain on assets 165 Unrealized gain on assets 16 Balance at December 31, 2015 $ 5,045 |
Schedule of Expected Benefit Payments [Table Text Block] | Expected benefit payments over the next 10 years are as follows: Years Ending December 31, (in thousands) 2016 $ 3,618 2017 $ 4,350 2018 $ 4,605 2019 $ 6,057 2020 $ 6,846 2021 through 2025 $ 47,188 |
Asset Retirement Obligations Re
Asset Retirement Obligations Reconciliation of Asset Retirement Obligation Liability (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Change in Asset Retirement Obligation [Table Text Block] | A reconciliation of the Company’s total asset retirement obligation liability is as follows: As of December 31, 2015 2014 (in thousands) Beginning asset retirement obligation $ 122,124 $ 121,186 Liabilities incurred 14,471 13,506 Liabilities settled (24,781 ) (11,372 ) Accretion expense 5,091 6,090 Revision to estimated cash flows 23,969 (7,286 ) Ending asset retirement obligation $ 140,874 $ 122,124 |
Derivative Financial Instrume36
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Notional Amounts of Outstanding Derivative Positions at Subsequent Date [Text Block] | These updated contracts are reflected in the following table, which summarizes the approximate gas volumes and average contract prices of contracts the Company had in place as of February 17, 2016 , including derivatives contracts for settlement anytime during the first quarter of 2016 and later periods: Natural Gas Swaps Contract Period Volumes Weighted- Average Contract Price Purchased Volumes Weighted- Average Contract Price Total Volumes (MMBtu) (per MMBtu) (MMBtu) (per MMBtu) (MMBtu) First quarter 2016 23,341,000 $ 3.82 — $ — 23,341,000 Second quarter 2016 20,780,000 $ 3.40 — $ — 20,780,000 Third quarter 2016 18,829,000 $ 3.38 — $ — 18,829,000 Fourth quarter 2016 17,236,000 $ 3.82 — $ — 17,236,000 2017 76,135,000 $ 4.26 — $ — 76,135,000 2018 30,606,000 $ 4.27 (30,606,000 ) $ 4.27 — 2019 24,415,000 $ 4.34 (24,415,000 ) $ 4.34 — All gas swaps* 211,342,000 (55,021,000 ) 156,321,000 ____________________________________________ *Total volumes of natural gas swaps are comprised of IF El Paso Permian ( 2% ), IF HSC ( 96% ), IF NGPL TXOK ( 1% ), and IF NNG Ventura ( 1% ). |
Schedule of Notional Amounts of Outstanding Derivative Positions | The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of December 31, 2015 : Oil Swaps Contract Period NYMEX WTI Volumes Weighted- Average Contract Price (Bbls) (per Bbl) First quarter 2016 1,868,000 $ 86.93 Second quarter 2016 1,752,000 $ 86.73 Third quarter 2016 1,170,000 $ 90.29 Fourth quarter 2016 780,000 $ 90.05 All oil swaps 5,570,000 Natural Gas Swaps Contract Period Volumes Weighted- Average Contract Price (MMBtu) (per MMBtu) First quarter 2016 23,341,000 $ 3.82 Second quarter 2016 20,780,000 $ 3.40 Third quarter 2016 18,829,000 $ 3.38 Fourth quarter 2016 17,236,000 $ 3.82 2017 37,528,000 $ 4.09 2018 30,606,000 $ 4.27 2019 24,415,000 $ 4.34 All gas swaps* 172,735,000 ____________________________________________ *Natural gas swaps are comprised of IF El Paso Permian ( 2% ), IF HSC ( 95% ), IF NGPL TXOK ( 1% ), and IF NNG Ventura ( 2% ). NGL Swaps OPIS Purity Ethane Mont Belvieu OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPIS Isobutane Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average (Bbls) (per Bbl) (Bbls) (per Bbl) (Bbls) (per Bbl) (Bbls) (per Bbl) First quarter 2016 926,000 $ 8.29 1,059,000 $ 19.60 143,000 $ 25.62 122,000 $ 25.87 Second quarter 2016 828,000 $ 8.28 949,000 $ 19.64 130,000 $ 25.62 111,000 $ 25.87 Third quarter 2016 751,000 $ 8.70 862,000 $ 19.03 — $ — — $ — Fourth quarter 2016 688,000 $ 8.71 791,000 $ 18.53 — $ — — $ — 2017 2,271,000 $ 9.16 — $ — — $ — — $ — 2018 1,671,000 $ 10.65 — $ — — $ — — $ — 2019 1,200,000 $ 10.92 — $ — — $ — — $ — 2020 539,000 $ 11.13 — $ — — $ — — $ — Total NGL swaps 8,874,000 3,661,000 273,000 233,000 |
Schedule of fair value of derivatives in accompanying balance sheets | The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: As of December 31, 2015 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity Contracts Current assets $ 367,710 Current liabilities $ 8 Commodity Contracts Noncurrent assets 120,701 Noncurrent liabilities — Derivatives not designated as hedging instruments $ 488,411 $ 8 As of December 31, 2014 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity Contracts Current assets $ 402,668 Current liabilities $ — Commodity Contracts Noncurrent assets 189,540 Noncurrent liabilities 70 Derivatives not designated as hedging instruments $ 592,208 $ 70 |
Schedule of the potential effects of master netting arrangements | The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts: Derivative Assets Derivative Liabilities As of December 31, As of December 31, Offsetting of Derivative Assets and Liabilities 2015 2014 2015 2014 (in thousands) Gross amounts presented in the accompanying balance sheets $ 488,411 $ 592,208 $ (8 ) $ (70 ) Amounts not offset in the accompanying balance sheets (8 ) (70 ) 8 70 Net amounts $ 488,403 $ 592,138 $ — $ — |
Schedule of gains and losses on derivative instruments in the statement of operations | The following table summarizes the components of derivative gain presented in the accompanying statements of operations: For the Years Ended December 31, 2015 2014 2013 (in thousands) Derivative settlement (gain) loss: Oil contracts $ (362,219 ) $ (28,410 ) $ 15,161 Gas contracts (1) (123,180 ) 26,706 (30,338 ) NGL contracts (27,167 ) (10,911 ) (6,885 ) Total derivative settlement gain $ (512,566 ) $ (12,615 ) $ (22,062 ) Total derivative (gain) loss: Oil contracts $ (191,165 ) $ (457,082 ) $ 14,665 Gas contracts (189,734 ) (93,267 ) (14,053 ) NGL contracts (27,932 ) (32,915 ) (3,692 ) Total derivative gain $ (408,831 ) $ (583,264 ) $ (3,080 ) ____________________________________________ (1) Natural gas derivative settlements for the years ended December 31, 2015 , and 2014, include $15.3 million and $5.6 million , respectively, of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region. |
Detail of the effect of derivative instruments reclassified from AOCI to the statement of operations (net of income tax) | The following table details the effect of derivative instruments on AOCL and the accompanying statements of operations (net of income tax): Location on Accompanying Statements of Operations For the Years Ended December 31, Derivatives 2015 2014 2013 (in thousands) Amount reclassified from AOCL Commodity Contracts Other operating revenues $ — $ — $ 1,115 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended | |
Dec. 31, 2015 | ||
Fair Value Disclosures [Abstract] | ||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2015 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 488,411 $ — Proved oil and gas properties (2) $ — $ — $ 124,184 Other property and equipment (2) $ — $ — $ 629 Liabilities: Derivatives (1) $ — $ 8 $ — Net Profits Plan (1) $ — $ — $ 7,611 ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2014 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 592,208 $ — Proved oil and gas properties (2) $ — $ — $ 33,423 Oil and gas properties held for sale (2) $ — $ — $ 17,891 Liabilities: Derivatives (1) $ — $ 70 $ — Net Profits Plan (1) $ — $ — $ 27,136 ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. | [1],[2],[3],[4] |
Schedule of reconciliation of fair value measurements using Level 3 inputs | The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs: For the Years Ended December 31, 2015 2014 2013 (in thousands) Beginning balance $ 27,136 $ 56,985 $ 78,827 Net increase (decrease) in liability (1) (12,238 ) (12,492 ) 3,527 Net settlements (1) (2) (7,287 ) (17,357 ) (25,369 ) Transfers in (out) of Level 3 — — — Ending balance $ 7,611 $ 27,136 $ 56,985 ____________________________________________ (1) Net changes in the Company’s Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations. (2) Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash payments made or accrued under the Net Profits Plan of $3.8 million , $8.3 million , and $10.3 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively, as a result of the divestitures of properties subject to the Net Profits Plan. | |
Long Term Debt Fair Value [Table Text Block] | The following table reflects the fair value of the Senior Notes measured using Level 1 inputs based on quoted secondary market trading prices. The Senior Notes were not presented at fair value on the accompanying balance sheets as of December 31, 2015 or 2014 , as they are recorded at carrying value, net of unamortized deferred financing costs. As of December 31, 2015 2014 (in thousands) 2019 Notes (1) $ — $ 350,018 2021 Notes $ 262,938 $ 343,000 2022 Notes $ 440,250 $ 556,500 2023 Notes $ 296,000 $ 379,000 2024 Notes $ 334,065 $ 435,000 2025 Notes (1) $ 326,875 $ — ____________________________________________ (1) The 2019 Notes were fully redeemed on June 22, 2015 and the 2025 Notes were issued on May 21, 2015 . | |
[1] | This represents a financial asset or liability that is measured at fair value on a recurring basis. | |
[2] | This represents a financial asset or liability that is measured at fair value on a recurring basis. | |
[3] | This represents a non-financial asset that is measured at fair value on a nonrecurring basis. | |
[4] | This represents a non-financial asset that is measured at fair value on a nonrecurring basis. |
Suspended Well Costs (Tables)
Suspended Well Costs (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Suspended Well Costs [Abstract] | |
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block] | The following table reflects the net changes in capitalized exploratory well costs during 2015 , 2014 , and 2013 . The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year: For the Years Ended December 31, 2015 2014 2013 (in thousands) Beginning balance on January 1, $ 43,589 $ 34,527 $ 9,100 Additions to capitalized exploratory well costs pending the determination of proved reserves 11,952 43,589 34,527 Divestitures (809 ) — — Reclassifications to wells, facilities, and equipment based on the determination of proved reserves (18,485 ) (33,340 ) (9,100 ) Capitalized exploratory well costs charged to expense (24,295 ) (1,187 ) — Ending balance at December 31, $ 11,952 $ 43,589 $ 34,527 |
Summary of Significant Accoun39
Summary of Significant Accounting Policies Other (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | ||
Basis of Presentation and Significant Accounting Policies [Line Items] | ||||
Receivables Collection Period | 2 months | |||
Allowance for Doubtful Accounts Receivable | $ 1,100 | $ 0 | ||
Capitalized Computer Software, Gross | $ 44,000 | 35,000 | ||
Concentration of Credit Risk and Major Customers [Abstract] | ||||
Marketing agreement length for gathering, transportation, and processing through-put commitments | 10 years | |||
Number of Derivative Counterparties | 10 | |||
Revenues [Abstract] | ||||
Revenue Receipt, Days After Sale, Low End of Range | 30 days | |||
Revenue Receipt, Days After Sale, High End of Range | 90 days | |||
Impairment of Proved, Unproved, and Other Properties [Abstract] | ||||
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast | 5 years | |||
Impairment of proved properties | $ 468,679 | 84,480 | $ 172,641 | |
Abandonment and impairment of unproved properties | 78,643 | 75,638 | 46,105 | |
Impairment of other property and equipment | 49,369 | 0 | $ 0 | |
Line of Credit [Member] | ||||
Basis of Presentation and Significant Accounting Policies [Line Items] | ||||
Revolving credit facility | [1] | $ 202,000 | $ 166,000 | |
Customer Concentration Risk [Member] | Oil And Gas Sales Revenue [Member] | ||||
Concentration of Credit Risk and Major Customers [Abstract] | ||||
Number of Major Customers | 1 | 1 | 3 | |
Customer Concentration Risk [Member] | Oil And Gas Sales Revenue [Member] | Major Customer One [Member] | ||||
Concentration of Credit Risk and Major Customers [Abstract] | ||||
Entity-Wide Revenue, Major Customer, Percentage | 21.00% | 19.00% | 16.00% | |
Customer Concentration Risk [Member] | Oil And Gas Sales Revenue [Member] | Major Customer Two [Member] | ||||
Concentration of Credit Risk and Major Customers [Abstract] | ||||
Entity-Wide Revenue, Major Customer, Percentage | 26.00% | |||
Customer Concentration Risk [Member] | Oil And Gas Sales Revenue [Member] | Major Customer Three [Member] | ||||
Concentration of Credit Risk and Major Customers [Abstract] | ||||
Entity-Wide Revenue, Major Customer, Percentage | 12.00% | |||
Customer Concentration Risk [Member] | Oil And Gas Sales Revenue [Member] | Unnamed Major Customer One with Related Entities [Member] | ||||
Concentration of Credit Risk and Major Customers [Abstract] | ||||
Entity-Wide Revenue, Major Customer, Percentage | 10.00% | 14.00% | ||
Number of Entities Related to One Unnamed Customer | 4 | |||
Customer Concentration Risk [Member] | Oil And Gas Sales Revenue [Member] | Unnamed Major Customer Two with Related Entities [Member] | ||||
Concentration of Credit Risk and Major Customers [Abstract] | ||||
Entity-Wide Revenue, Major Customer, Percentage | 11.00% | |||
Number of Entities Related to One Unnamed Customer | 3 | |||
Oil and Gas Properties [Member] | ||||
Property, Plant and Equipment [Abstract] | ||||
Property, Plant, and Equipment, Salvage Value | $ 29,700 | $ 50,800 | ||
Minimum [Member] | Property, Plant and Equipment, Other Types [Member] | ||||
Inventory, Net [Abstract] | ||||
Property, Plant and Equipment, Estimated Useful Lives | 3 | |||
Maximum [Member] | Property, Plant and Equipment, Other Types [Member] | ||||
Inventory, Net [Abstract] | ||||
Property, Plant and Equipment, Estimated Useful Lives | 30 | |||
[1] | Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and thus are not deducted from the credit facility balance. |
Summary of Significant Accoun40
Summary of Significant Accounting Policies Earnings Per Share (Details) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014USD ($)$ / sharesshares | Dec. 31, 2013USD ($)$ / sharesshares | ||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 256 | 0 | 0 | |
Earnings Per Share Reconciliation [Abstract] | ||||
Net Income (loss) | $ | $ (447,710) | $ 666,051 | $ 170,935 | |
Weighted Average Number of Shares Outstanding, Basic | 67,723 | 67,230 | 66,615 | |
Incremental Common Shares Attributable to Share-based Payment Arrangements | 0 | [1] | 814 | 1,383 |
Weighted Average Number of Shares Outstanding, Diluted | 67,723 | 68,044 | 67,998 | |
Basic net income (loss) per common share | $ / shares | $ (6.61) | $ 9.91 | $ 2.57 | |
Diluted net income (loss) per common share | $ / shares | $ (6.61) | $ 9.79 | $ 2.51 | |
Performance Shares [Member] | ||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||
Award Vesting Period | 3 years | |||
Multiplier Applied to PSU Awards at Settlement | 1 | 0.55 | 1.725 | |
Minimum [Member] | Performance Shares [Member] | ||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||
Multiplier Applied to PSU Awards at Settlement | 0 | |||
Maximum [Member] | Performance Shares [Member] | ||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||
Multiplier Applied to PSU Awards at Settlement | 2 | |||
[1] | For the year ended December 31, 2015, the shares were anti-dilutive and excluded from the calculation of diluted earnings per share. |
Summary of Significant Accoun41
Summary of Significant Accounting Policies Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Other comprehensive income [Abstract] | ||||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Reclassification to Earnings, before Tax | [1] | $ 0 | $ 0 | $ 1,777 |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax, Portion Attributable to Parent | [1] | 0 | 0 | 662 |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax, Portion Attributable to Parent | [1] | 0 | 0 | 1,115 |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax | (4,990) | (10,062) | 2,766 | |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax | (1,853) | (706) | (1,239) | |
Other Comprehensive Income (Loss), Minimum Pension Liability, Tax | (1,047) | (3,460) | 1,522 | |
Pension liability adjustment | [2] | $ (2,090) | $ (5,896) | $ 2,483 |
[1] | As of December 31, 2013, all commodity derivative contracts that had been previously designated as cash flow hedges had settled and had been reclassified into earnings from AOCL. | |||
[2] | Refer to Note 1 - Summary of Significant Accounting Policies for detail of the pension amount reclassified to general and administrative expense on the Company’s consolidated statements of operations. |
Summary of Significant Accoun42
Summary of Significant Accounting Policies New Accounting Pronouncements (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |
New Accounting Pronouncement, Early Adoption [Line Items] | |||
Unamortized Debt Issuance Expense | $ 34,030 | $ 33,555 | [1] |
Other noncurrent assets | 31,673 | 44,659 | |
Assets, Noncurrent | 152,374 | 234,199 | |
Assets | 5,621,643 | 6,483,145 | |
Senior Notes | 2,315,970 | 2,166,445 | [1] |
Liabilities, Noncurrent | 3,466,717 | 3,411,830 | |
Liabilities and Equity | $ 5,621,643 | 6,483,145 | |
New Accounting Pronouncement, Early Adoption, Effect [Member] | |||
New Accounting Pronouncement, Early Adoption [Line Items] | |||
Unamortized Debt Issuance Expense | 33,600 | ||
Scenario, Previously Reported [Member] | |||
New Accounting Pronouncement, Early Adoption [Line Items] | |||
Other noncurrent assets | 78,214 | ||
Assets, Noncurrent | 267,754 | ||
Assets | 6,516,700 | ||
Senior Notes | 2,200,000 | ||
Liabilities, Noncurrent | 3,445,385 | ||
Liabilities and Equity | $ 6,516,700 | ||
[1] | Prior period amounts have been reclassified to conform to the current period presentation on the accompanying balance sheets. Please refer to the section Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional discussion. |
Accounts Receivable and Accou43
Accounts Receivable and Accounts Payable and Accrued Expenses Accounts Receivable (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Accounts, Notes, Loans and Financing Receivable | ||
Accounts Receivable, Net, Current | $ 134,124 | $ 322,630 |
Accrued oil, gas, and NGL production revenue [Member] | ||
Accounts, Notes, Loans and Financing Receivable | ||
Accounts Receivable, Net, Current | 58,256 | 180,250 |
Amounts due From Joint Interest Owners [Member] | ||
Accounts, Notes, Loans and Financing Receivable | ||
Accounts Receivable, Net, Current | 22,269 | 58,347 |
Accrued derivative settlements [Member] | ||
Accounts, Notes, Loans and Financing Receivable | ||
Accounts Receivable, Net, Current | 34,579 | 39,811 |
State severance tax refunds [Member] | ||
Accounts, Notes, Loans and Financing Receivable | ||
Accounts Receivable, Net, Current | 12,072 | 24,394 |
Other [Member] | ||
Accounts, Notes, Loans and Financing Receivable | ||
Accounts Receivable, Net, Current | $ 6,948 | $ 19,828 |
Accounts Receivable and Accou44
Accounts Receivable and Accounts Payable and Accrued Expenses Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Accounts Payable and Accrued Liabilities, Current [Abstract] | ||
Capital Expenditures Incurred but Not yet Paid - Instant | $ 97,355 | $ 357,156 |
Accrued Revenue And Severance Tax Payable | 44,387 | 63,779 |
Accrued Lease Operating Expense | 21,943 | 34,822 |
Accrual for Taxes Other than Income Taxes, Current | 14,078 | 15,059 |
Employee-related Liabilities, Current | 41,154 | 56,279 |
Interest Payable, Current | 34,378 | 40,786 |
Other Accrued Liabilities, Current | 49,222 | 72,803 |
Accounts payable and accrued expenses | $ 302,517 | $ 640,684 |
Acquisitions (Details)
Acquisitions (Details) a in Thousands, $ in Thousands | Oct. 15, 2014USD ($) | Sep. 24, 2014USD ($)a | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($)a | Dec. 31, 2013USD ($) |
Business Acquisition [Line Items] | |||||
Proved Oil and Gas Property, Successful Effort Method | $ 7,606,405 | $ 7,348,436 | |||
Unproved Oil and Gas Property, Successful Effort Method | 284,538 | 532,498 | |||
Asset Retirement Obligations, Noncurrent | (137,525) | (120,867) | |||
Payments to Acquire Oil and Gas Property and Equipment | $ 7,984 | 544,553 | $ 61,603 | ||
Gooseneck Prospect Acquisition 2014 [Member] | |||||
Business Acquisition [Line Items] | |||||
Net acres acquired | a | 61 | ||||
Payments to Acquire Businesses, Gross | $ 321,807 | ||||
Proved Oil and Gas Property, Successful Effort Method | 203,467 | ||||
Unproved Oil and Gas Property, Successful Effort Method | 126,588 | ||||
Oil and Gas Property, Successful Effort Method, Net | 330,055 | ||||
Working Capital Acquired | (6,135) | ||||
Asset Retirement Obligations, Noncurrent | (2,113) | ||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $ 321,807 | ||||
Gooseneck Second Prospect Acquisition 2014 [Member] | |||||
Business Acquisition [Line Items] | |||||
Payments to Acquire Businesses, Gross | $ 84,836 | ||||
Proved Oil and Gas Property, Successful Effort Method | 54,612 | ||||
Unproved Oil and Gas Property, Successful Effort Method | 29,610 | ||||
Oil and Gas Property, Successful Effort Method, Net | 84,222 | ||||
Working Capital Acquired | 2,232 | ||||
Asset Retirement Obligations, Noncurrent | (1,618) | ||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $ 84,836 | ||||
Rocky Mountain Acquisition 2014 [Member] | |||||
Business Acquisition [Line Items] | |||||
Payments to Acquire Oil and Gas Property and Equipment | $ 135,500 | ||||
Leasehold Acres Consideration to Acquire Unproved Property | a | 7 |
Acquisitions, Divestitures, a46
Acquisitions, Divestitures, and Assets Held for Sale Divestitures and Assets Held for Sale (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Cash received on divestiture of non-strategic assets | $ 357,938,000 | $ 43,858,000 | $ 424,849,000 | ||
Net gain on divestiture activity | 43,031,000 | 646,000 | 27,974,000 | ||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | 98,600,000 | 27,600,000 | |||
Contractual Obligation | [1] | $ 964,438,000 | |||
Assets Held-for-sale, Current | |||||
Reasonably certain period within which sale will take place (in years) | 1 year | ||||
Oil and gas properties held for sale | $ 641,000 | 17,891,000 | |||
Asset Retirement Obligations Assets Held-for-sale Noncurrent | 241,000 | ||||
Mid Continent Divestiture 2015 [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Cash received on divestiture of non-strategic assets | 316,800,000 | ||||
Net gain on divestiture activity | 108,400,000 | ||||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | $ 30,000,000 | ||||
Business Exit Costs | 9,300,000 | ||||
Permian Divestiture 2015 [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Cash received on divestiture of non-strategic assets | 25,100,000 | ||||
Net gain on divestiture activity | 2,400,000 | ||||
Other Divestitures 2015 [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | 68,600,000 | ||||
Rocky Mountain Divestiture 2014 [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Cash received on divestiture of non-strategic assets | 50,100,000 | ||||
Net gain on divestiture activity | $ 26,900,000 | ||||
Mid Continent Divestiture 2013 [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Cash received on divestiture of non-strategic assets | 368,500,000 | ||||
Net gain on divestiture activity | 25,300,000 | ||||
Rocky Mountain Divestiture 2013 [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Cash received on divestiture of non-strategic assets | 57,100,000 | ||||
Net gain on divestiture activity | 13,200,000 | ||||
Permian Divestiture 2013 [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Cash received on divestiture of non-strategic assets | 14,000,000 | ||||
Net gain on divestiture activity | $ (7,000,000) | ||||
Office Space Leases [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Contractual Obligation | 59,400,000 | ||||
Office Space Leases [Member] | Mid Continent Divestiture 2015 [Member] | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Contractual Obligation | $ 4,000,000 | ||||
[1] | During the third quarter of 2015, the Company vacated its office space in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive $3.5 million of sublease income as follows: $831,000 in 2016, $953,000 in 2017, $978,000 in 2018, and $741,000 in 2019. |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Components of the provision for income taxes | |||
Federal | $ 0 | $ 0 | $ 0 |
State | 1,571 | 868 | 2,121 |
Deferred portion of income tax expense (benefit) | (276,722) | 397,780 | 105,555 |
Income tax expense (benefit) | $ (275,151) | $ 398,648 | $ 107,676 |
Effective tax rate (as a percent) | 38.10% | 37.40% | 38.60% |
Deferred Income Taxes [Abstract] | |||
Deferred Tax Liabilities, Oil and Gas Properties | $ 854,029 | $ 1,029,424 | |
Deferred Tax Liabilities, Derivative asset | 179,543 | 220,437 | |
Deferred Tax Liabilities, Other | 1,233 | 4,475 | |
Deferred Tax Liabilities | 1,034,805 | 1,254,336 | |
Deferred Tax Assets, Federal and State Tax Net Operating Loss Carryforwards | 244,942 | 184,447 | |
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost | 14,529 | 16,763 | |
Deferred Tax Assets, Other Liabilities | 27,449 | 25,715 | |
Deferred Tax Assets, Gross | 286,920 | 226,925 | |
Deferred Tax Assets, Valuation Allowance | (10,394) | (7,246) | |
Deferred Tax Assets, Net | 276,526 | 219,679 | |
Deferred Tax Liabilities, Net | 758,279 | 1,034,657 | |
Unrecognized Tax Benefits, Exercise of Stock Awards | 126,700 | ||
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract] | |||
Federal statutory tax expense (benefit) | (253,001) | 372,644 | $ 97,514 |
State tax expense (benefit) (net of federal benefit) | (21,583) | 21,350 | 9,400 |
Change in valuation allowance | 3,148 | 2,245 | (314) |
Research and development credit | (1,971) | 0 | 0 |
Other | (1,744) | 2,409 | 1,076 |
Tax Credit Recorded for IRS R&D Settlement | 2,000 | ||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Unrecognized Tax Benefits, Beginning Balance | 1,582 | 2,358 | 2,278 |
Unrecognized Tax Benefits, Additions For Tax Positions Of Prior Years | 1,200 | 140 | 80 |
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 0 | (916) | 0 |
Unrecognized Tax Benefits, Ending Balance | 2,782 | 1,582 | $ 2,358 |
Internal Revenue Service (IRS) [Member] | |||
Deferred Income Taxes [Abstract] | |||
Income Taxes Receivable, Current | 5,378 | 4,734 | |
Operating Loss Carryforwards | 796,700 | ||
State and Local Jurisdiction [Member] | |||
Deferred Income Taxes [Abstract] | |||
Income Taxes Receivable, Current | 65 | 0 | |
Taxes Payable, Current | 0 | $ 25 | |
Operating Loss Carryforwards | 338,900 | ||
Minimum [Member] | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Increase in Unrecognized Tax Benefits is Reasonably Possible | 0 | ||
Decrease in Unrecognized Tax Benefits is Reasonably Possible | 0 | ||
Maximum [Member] | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Increase in Unrecognized Tax Benefits is Reasonably Possible | 1,800 | ||
Decrease in Unrecognized Tax Benefits is Reasonably Possible | 1,800 | ||
Internal Revenue Service (IRS) [Member] | Research Tax Credit Carryforward [Member] | Domestic Tax Authority [Member] | |||
Deferred Income Taxes [Abstract] | |||
Tax Credit Carryforward, Amount | $ 7,200 |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) | May. 21, 2015 | Nov. 17, 2014 | May. 20, 2013 | Jun. 29, 2012 | Nov. 08, 2011 | Jun. 30, 2015 | Jun. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 22, 2015 | Jun. 05, 2015 | May. 20, 2015 | |
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | $ 2,350,000,000 | $ 2,200,000,000 | [1] | |||||||||||
Unamortized Debt Issuance Expense | 34,030,000 | 33,555,000 | [1] | |||||||||||
Senior Notes, net of unamortized deferred financing costs (note 5) | 2,315,970,000 | 2,166,445,000 | [1] | |||||||||||
Gains (Losses) on Extinguishment of Debt | (16,578,000) | 0 | $ 0 | |||||||||||
Gains (Losses) on Extinguishment of Debt, Non-Cash Portion | 4,123,000 | 0 | 0 | |||||||||||
Net proceeds from debt issuance | 490,951,000 | 589,991,000 | 490,185,000 | |||||||||||
Interest Costs, Capitalized During Period | 25,100,000 | 16,200,000 | $ 11,000,000 | |||||||||||
Senior Notes [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Covenant Compliance, Dividends Excluded From Computation | 6,500,000 | |||||||||||||
6.625% Senior Notes Due 2019 [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | 0 | 350,000,000 | [1] | |||||||||||
Unamortized Debt Issuance Expense | 0 | 4,591,000 | [1] | |||||||||||
Senior Notes, net of unamortized deferred financing costs (note 5) | $ 0 | 345,409,000 | [1] | |||||||||||
6.625% Senior Notes Due 2019 [Member] | Senior Notes [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.625% | |||||||||||||
Price per Note Tendered | $ 1,006.88 | $ 1,036.88 | ||||||||||||
Debt Instrument, Face Amount, Individual Note | 1,000 | 1,000 | ||||||||||||
Debt Instrument, Repurchased Face Amount | 1,500,000 | $ 242,900,000 | ||||||||||||
Percentage of Notes Tendered | 69.00% | |||||||||||||
Debt Instrument, Repurchase Amount | $ 1,600,000 | $ 256,200,000 | ||||||||||||
Gains (Losses) on Extinguishment of Debt | $ (16,578,000) | |||||||||||||
Debt Instrument, Repurchase Premium | 12,500,000 | |||||||||||||
Gains (Losses) on Extinguishment of Debt, Non-Cash Portion | $ 4,123,000 | |||||||||||||
6.625% Senior Notes Due 2019 [Member] | From February 15, 2015 to February 14, 2016 [Member] | Senior Notes [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Repurchase Amount | $ 111,500,000 | |||||||||||||
Debt Instrument, Redemption Price, Percentage | 103.313% | |||||||||||||
6.50% Senior Notes Due 2021 [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | $ 350,000,000 | 350,000,000 | [1] | |||||||||||
Unamortized Debt Issuance Expense | 4,106,000 | 4,806,000 | [1] | |||||||||||
Senior Notes, net of unamortized deferred financing costs (note 5) | 345,894,000 | 345,194,000 | [1] | |||||||||||
6.50% Senior Notes Due 2021 [Member] | Senior Notes [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | $ 350,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.50% | |||||||||||||
Net proceeds from debt issuance | $ 343,100,000 | |||||||||||||
Deferred Finance Costs, Gross | $ 6,900,000 | |||||||||||||
6.125% Senior Notes Due 2022 [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | 600,000,000 | 600,000,000 | [1] | |||||||||||
Unamortized Debt Issuance Expense | 8,714,000 | 9,812,000 | [1] | |||||||||||
Senior Notes, net of unamortized deferred financing costs (note 5) | 591,286,000 | 590,188,000 | [1] | |||||||||||
6.125% Senior Notes Due 2022 [Member] | Senior Notes [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | $ 600,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.125% | |||||||||||||
Net proceeds from debt issuance | $ 590,000,000 | |||||||||||||
Deferred Finance Costs, Gross | $ 10,000,000 | |||||||||||||
6.50% Senior Notes Due 2023 [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | 400,000,000 | 400,000,000 | [1] | |||||||||||
Unamortized Debt Issuance Expense | 5,231,000 | 5,969,000 | [1] | |||||||||||
Senior Notes, net of unamortized deferred financing costs (note 5) | 394,769,000 | 394,031,000 | [1] | |||||||||||
6.50% Senior Notes Due 2023 [Member] | Senior Notes [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | $ 400,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.50% | |||||||||||||
Net proceeds from debt issuance | $ 392,100,000 | |||||||||||||
Deferred Finance Costs, Gross | $ 7,900,000 | |||||||||||||
5% Senior Notes Due 2024 [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | 500,000,000 | 500,000,000 | [1] | |||||||||||
Unamortized Debt Issuance Expense | 7,455,000 | 8,377,000 | [1] | |||||||||||
Senior Notes, net of unamortized deferred financing costs (note 5) | 492,545,000 | 491,623,000 | [1] | |||||||||||
5% Senior Notes Due 2024 [Member] | Senior Notes [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | $ 500,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.00% | |||||||||||||
Net proceeds from debt issuance | $ 490,200,000 | |||||||||||||
Deferred Finance Costs, Gross | $ 9,800,000 | |||||||||||||
5.625% Senior Notes Due 2025 [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | 500,000,000 | 0 | [1] | |||||||||||
Unamortized Debt Issuance Expense | 8,524,000 | 0 | [1] | |||||||||||
Senior Notes, net of unamortized deferred financing costs (note 5) | $ 491,476,000 | $ 0 | [1] | |||||||||||
5.625% Senior Notes Due 2025 [Member] | Senior Notes [Member] | ||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||
Debt Instrument, Face Amount | $ 500,000,000 | |||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.625% | |||||||||||||
Net proceeds from debt issuance | $ 491,000,000 | |||||||||||||
Deferred Finance Costs, Gross | $ 9,000,000 | |||||||||||||
[1] | Prior period amounts have been reclassified to conform to the current period presentation on the accompanying balance sheets. Please refer to the section Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional discussion. |
Long-term Debt Revolving Credit
Long-term Debt Revolving Credit Facility (Details) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2015USD ($) | Feb. 17, 2016USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2014USD ($) | ||
Line of Credit Facility [Line Items] | |||||
Percentage of Proved Oil and Gas Properties Secured for Credit Facility Borrowing | 75.00% | ||||
Line of Credit [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Long-term Line of Credit | [1] | $ 202,000 | $ 166,000 | ||
Letters of Credit Outstanding, Amount | [2] | 200 | 808 | ||
Line of Credit Facility, Remaining Borrowing Capacity | $ 1,297,800 | $ 1,333,192 | |||
Line of Credit [Member] | Borrowing Base Utilization of 25 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.30% | ||||
Line of Credit [Member] | Borrowing Base Utilization Of More Than 25 Percent But Less Than 50 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.30% | ||||
Line of Credit [Member] | Borrowing Base Utilization Of More Than 50 Percent But Less Than 75 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.35% | ||||
Line of Credit [Member] | Borrowing Base Utilization Of More Than 75 Percent But Less Than 90 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.375% | ||||
Line of Credit [Member] | Borrowing Base Utilization Of More Than 90 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.375% | ||||
Line of Credit [Member] | Revolving Credit Facility [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,500,000 | ||||
Line of Credit Facility, Current Borrowing Capacity | 1,500,000 | ||||
Borrowing Base, Line of Credit | $ 2,000,000 | $ 2,400,000 | |||
Subsequent Event [Member] | Line of Credit [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Long-term Line of Credit | [1] | $ 243,000 | |||
Letters of Credit Outstanding, Amount | [2] | 200 | |||
Line of Credit Facility, Remaining Borrowing Capacity | $ 1,256,800 | ||||
Eurodollar [Member] | Line of Credit [Member] | Borrowing Base Utilization of 25 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 1.25% | ||||
Eurodollar [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 25 Percent But Less Than 50 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 1.50% | ||||
Eurodollar [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 50 Percent But Less Than 75 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 1.75% | ||||
Eurodollar [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 75 Percent But Less Than 90 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 2.00% | ||||
Eurodollar [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 90 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 2.25% | ||||
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | Line of Credit [Member] | Borrowing Base Utilization of 25 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 0.25% | ||||
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 25 Percent But Less Than 50 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | ||||
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 50 Percent But Less Than 75 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 0.75% | ||||
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 75 Percent But Less Than 90 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 90 Percent [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument, Basis Spread on Variable Rate | 1.25% | ||||
Maximum [Member] | Line of Credit [Member] | Revolving Credit Facility [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument Covenant Compliance Debt To Adjusted EBITDAX Ratio | 4 | ||||
Minimum [Member] | Line of Credit [Member] | Revolving Credit Facility [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt Instrument Covenant Compliance Adjusted Current Ratio | 1 | ||||
[1] | Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and thus are not deducted from the credit facility balance. | ||||
[2] | Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis. |
Commitments (Details)
Commitments (Details) | Feb. 17, 2016USD ($)MMcfMMBbls | Dec. 31, 2015USD ($)MMcfMMBbls | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Commitments and Contingencies | |||||
Contractual Obligation, Due in Next Twelve Months | [1] | $ 132,747,000 | |||
Contractual Obligation, Due in Second Year | [1] | 128,074,000 | |||
Contractual Obligation, Due in Third Year | [1] | 131,489,000 | |||
Contractual Obligation, Due in Fourth Year | [1] | 142,161,000 | |||
Contractual Obligation, Due in Fifth Year | [1] | 141,854,000 | |||
Contractual Obligation, Due after Fifth Year | [1] | 288,113,000 | |||
Contractual Obligation | [1] | 964,438,000 | |||
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals | 3,500,000 | ||||
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals, Next Twelve Months | 831,000 | ||||
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals, Due in Two Years | 953,000 | ||||
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals, Due in Three Years | 978,000 | ||||
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals, Due in Four Years | 741,000 | ||||
Operating Leases, Rent Expense | $ 6,100,000 | $ 6,500,000 | $ 5,700,000 | ||
Natural Gas Transportation Commitment [Member] | |||||
Commitments and Contingencies | |||||
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMcf | 2,277,000 | ||||
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume, Volumes Not Subject To Deficiency Fee | MMcf | 1,059,000 | ||||
Crude Oil Transportation Commitment [Member] | |||||
Commitments and Contingencies | |||||
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls | 36 | ||||
Subsequent Event [Member] | Natural Gas Transportation Commitment [Member] | |||||
Commitments and Contingencies | |||||
Oil and Gas Delivery Commitments and Contracts, Decrease in Remaining Contractual Volume | MMcf | 829,000 | ||||
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMcf | 310,000 | ||||
Subsequent Event [Member] | Crude Oil Transportation Commitment [Member] | |||||
Commitments and Contingencies | |||||
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls | 41 | ||||
Drilling Rig Leasing Contracts [Member] | |||||
Commitments and Contingencies | |||||
Contractual Obligation | $ 35,300,000 | ||||
Early Termination Penalty For Rig Contract Cancellation | 26,000,000 | ||||
Gain (Loss) on Contract Termination | (13,700,000) | ||||
Gas gathering and Oil and Gas Through-put Commitments [Member] | |||||
Commitments and Contingencies | |||||
Contractual Obligation | 864,000,000 | ||||
Gas gathering and Oil and Gas Through-put Commitments [Member] | Subsequent Event [Member] | |||||
Commitments and Contingencies | |||||
Contractual Obligation | $ 360,800,000 | ||||
Decrease in Contractual Obligation | $ 118,200,000 | ||||
Office Space Leases [Member] | |||||
Commitments and Contingencies | |||||
Contractual Obligation | 59,400,000 | ||||
Other miscellaneous contracts and leases [Member] | |||||
Commitments and Contingencies | |||||
Contractual Obligation | $ 5,700,000 | ||||
[1] | During the third quarter of 2015, the Company vacated its office space in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive $3.5 million of sublease income as follows: $831,000 in 2016, $953,000 in 2017, $978,000 in 2018, and $741,000 in 2019. |
Commitments and Contingencies L
Commitments and Contingencies Loss Contingency (Details) $ in Millions | Dec. 31, 2015USD ($) |
Royalty Dispute [Domain] | |
Loss Contingencies [Line Items] | |
Loss Contingency Accrual | $ 5.3 |
Compensation Plans_ Stock Based
Compensation Plans: Stock Based (Details) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2015USD ($)shares$ / shares | Dec. 31, 2014USD ($)$ / sharesshares | Dec. 31, 2013USD ($)$ / sharesshares | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Number of shares available for grant | 2,800,000 | |||
Impact outright issuance of one share has on number of available shares | 1 | |||
Director Shares | ||||
Minimum Service Requirement for Immediate Vesting of Granted Shares | 5 years | |||
Shares Issued to the Board of Directors [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Award Vesting Period | 1 year | |||
Stock-based compensation expense | $ | $ 1.6 | $ 1.6 | $ 1.4 | |
Director Shares | ||||
Stock Issued During Period, Shares, Share-based Compensation, Gross | 37,950 | 27,677 | 28,169 | |
Shares Issued to Former CEO for Service As Director [Member] | ||||
Director Shares | ||||
Stock Issued During Period, Shares, Share-based Compensation, Gross | 1,953 | |||
Performance Shares [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Maximum Impact of issuance of one performance share award on available shares under the equity incentive plan | 2 | |||
Multiplier Applied to PSU Awards at Settlement | 1 | 0.55 | 1.725 | |
Award Vesting Period | 3 years | |||
Stock-based compensation expense | $ | $ 10.6 | $ 16 | $ 16.8 | |
Unrecognized stock based compensation expense | $ | 18.4 | |||
Fair value of PSUs/RSUs Granted in Period | $ | $ 14.5 | 19.2 | 17.6 | |
Multiplier assumed | 1 | |||
Fair value of PSUs/RSUs Vested in Period | $ | $ 4 | $ 13.4 | $ 20.7 | |
Shares Issued in Period | 188,279 | 85,121 | 387,461 | |
Shares held for settlement of income and payroll tax obligations (in shares) | 100,683 | 45,042 | 200,050 | |
Weighted Average Grant Date Fair Value | ||||
Non-vested at beginning of year (in shares) | [1] | 433,660 | 572,469 | 669,308 |
Granted (in shares) | [1] | 320,753 | 202,404 | 274,831 |
Vested (in shares) | [1] | (76,438) | (206,830) | (345,005) |
Forfeited (in shares) | [1] | (51,647) | (134,383) | (26,665) |
Non-vested at end of year (in shares) | [1] | 626,328 | 433,660 | 572,469 |
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares | [1] | $ 73.63 | $ 66.07 | $ 63.91 |
Granted (in dollars per share) | $ / shares | [1] | 45.34 | 94.66 | 64.13 |
Vested (in dollars per share) | $ / shares | [1] | 51.76 | 64.79 | 60.06 |
Forfeited (in dollars per share) | $ / shares | [1] | 73.62 | 86.72 | 69.74 |
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares | [1] | $ 61.81 | $ 73.63 | $ 66.07 |
Restricted Stock Units (RSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Award Vesting Period | 3 years | |||
Stock-based compensation expense | $ | $ 13.4 | $ 13.9 | $ 13.1 | |
Unrecognized stock based compensation expense | $ | 19.3 | |||
Fair value of PSUs/RSUs Granted in Period | $ | $ 15.6 | $ 19.7 | $ 19.8 | |
PSU/RSU Vesting Increment | 0.33 | 0.33 | 0.33 | |
Fair value of PSUs/RSUs Vested in Period | $ | $ 17.6 | $ 14.7 | $ 10.3 | |
Restricted Stock, Shares Settled Gross of Shares for Tax Withholdings | 278,289 | 253,031 | 207,378 | |
Shares held for settlement of income and payroll tax obligations (in shares) | 91,045 | 81,434 | 67,987 | |
Number of Shares Represented by Each RSU | 1 | |||
Restricted Stock, Shares Issued Net of Shares for Tax Withholdings | 187,244 | 171,597 | 139,391 | |
Weighted Average Grant Date Fair Value | ||||
Non-vested at beginning of year (in shares) | 515,724 | 580,431 | 496,244 | |
Granted (in shares) | 356,246 | 234,560 | 329,939 | |
Vested (in shares) | (278,289) | (253,031) | (207,376) | |
Forfeited (in shares) | (49,944) | (46,236) | (38,376) | |
Non-vested at end of year (in shares) | 543,737 | 515,724 | 580,431 | |
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares | $ 68.29 | $ 57.05 | $ 51.81 | |
Granted (in dollars per share) | $ / shares | 43.72 | 83.98 | 60.01 | |
Vested (in dollars per share) | $ / shares | 63.12 | 58.19 | 49.73 | |
Forfeited (in dollars per share) | $ / shares | 66.53 | 62.06 | 54.37 | |
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares | $ 55.01 | $ 68.29 | $ 57.05 | |
Minimum [Member] | Performance Shares [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Multiplier Applied to PSU Awards at Settlement | 0 | |||
Maximum [Member] | Performance Shares [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Multiplier Applied to PSU Awards at Settlement | 2 | |||
[1] | The number of awards assumes a multiplier of one. The final number of shares of common stock issued may vary depending on the three-year performance multiplier, which ranges from zero to two. |
Compensation Plans Stock Option
Compensation Plans Stock Option Grants Under the Equity Incentive Compensation Plan (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Compensation plans | |||
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options | $ 0 | $ 0 | |
Proceeds from Stock Options Exercised | 4,000,000 | $ 3,200,000 | |
Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options | $ 0 | $ 0 | $ 0 |
Shares | |||
Outstanding, start of year | 0 | 39,088 | 267,846 |
Exercised | (39,088) | (228,758) | |
Forfeited | 0 | 0 | |
Outstanding, end of year | 0 | 39,088 | |
Vested and exercisable at end of year | 0 | 39,088 | |
Weighted Average Exercise Price | |||
Outstanding, start of year (in dollars per share) | $ 0 | $ 20.87 | $ 14.95 |
Exercised (in dollars per share) | 20.87 | 13.92 | |
Forfeited (in dollars per share) | 0 | 0 | |
Outstanding, end of year (in dollars per share) | 0 | 20.87 | |
Vested and exercisable at end of year (in dollars per share) | $ 0 | $ 20.87 | |
Aggregate Intrinsic Value | |||
Exercised | $ 1,993,726 | $ 12,326,994 | |
Outstanding | 0 | 2,432,837 | |
Vested and exercisable at end of year | $ 0 | $ 2,432,837 | |
Employee Stock Option [Member] | |||
Compensation plans | |||
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period | 10 years |
Compensation Plans Employee Sto
Compensation Plans Employee Stock Purchase Plan (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Compensation plans | |||
Number of shares available for grant | 2,800,000 | ||
Employee Stock Purchase Plan [Member] | |||
Compensation plans | |||
Maximum employee subscription rate | 15.00% | ||
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Employee Subscription | $ 25,000 | ||
Percent of offering date price paid | 85.00% | ||
Number of shares available for grant | 900,000 | ||
Issuance of common stock under Employee Stock Purchase Plan (in shares) | 197,214 | 83,136 | 77,427 |
Proceeds from Issuance of Shares under Incentive and Share-based Compensation Plans, Excluding Stock Options | $ 4,800,000 | $ 4,100,000 | $ 3,700,000 |
Risk free interest rate | 0.10% | 0.10% | 0.10% |
Dividend yield | 0.20% | 0.10% | 0.20% |
Volatility factor of the expected market price of the Company's common stock | 61.20% | 33.00% | 41.10% |
Expected life (in years) | 6 months | 6 months | 6 months |
Stock-based compensation expense | $ 1,800,000 | $ 1,100,000 | $ 1,100,000 |
Compensation Plans Non Stock-Ba
Compensation Plans Non Stock-Based Compensation (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Net Profits Plan [Member] | |||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | |||
Minimum Percentage of Oil and Gas Wells, Costs Recovered for Payment to Employees from Net Profit Plan | 100.00% | ||
Percentage of Future Net Cash Flow Received by Participants from Net Profit Plan | 10.00% | ||
Percentage Of Future Net Cash Flow Received By Participants From Net Profit Plan Increased To | 20.00% | ||
Percentage of Oil and Gas Wells Costs Recovered for Additional Payment Employees from Net Profit Plan | 200.00% | ||
Cash Payments Made or Accrued under Profit Sharing Plan Allocated to General and Administrative Expense | $ 3,239,000 | $ 8,326,000 | $ 13,734,000 |
Cash Payments Made or Accrued under Profit Sharing Plan Allocated to Oil and Gas Exploration Expense | 259,000 | 690,000 | 1,310,000 |
Total Cash Payments, Made or Accrued under Profit Sharing Plan | 3,498,000 | 9,016,000 | 15,044,000 |
Cash Payments Made or Accrued under Profit Sharing Plan Related to Divested Property | $ 3,800,000 | 8,300,000 | 10,300,000 |
401K Plan [Member] | |||
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items] | |||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent | 60.00% | ||
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay, Employees Hired December 31, 2014 and Prior | 6.00% | ||
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay, Employees Hired After December 31, 2014 | 9.00% | ||
Defined Contribution Plan, Employer Matching Contribution, Percent of Bonus, Employees Hired December 31, 2014 and Prior | 6.00% | ||
Defined Contribution Plan, Employer Matching Contribution, Percent of Bonus, Employees Hired After December 31, 2014 | 9.00% | ||
Defined Contribution Plan, Cost Recognized | $ 5,600,000 | 6,400,000 | 4,200,000 |
Defined Contribution Plan, Employer Discretionary Contribution Amount | $ 0 | $ 0 | $ 0 |
Pension Benefits (Details)
Pension Benefits (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||
Defined Benefit Plan, Benefit Obligation Beginning of Year | $ 57,867,000 | $ 43,285,000 | ||
Defined Benefit Plan, Service Cost | 7,949,000 | 6,335,000 | $ 6,291,000 | |
Defined Benefit Plan, Interest Cost | 2,496,000 | 2,191,000 | 1,627,000 | |
Defined Benefit Plan, Actuarial Gain (Loss) | 2,397,000 | 8,821,000 | ||
Defined Benefit Plan, Benefits Paid | (8,162,000) | (2,765,000) | (3,300,000) | |
Defined Benefit Plan, Benefit Obligation End of Year | 62,547,000 | 57,867,000 | 43,285,000 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Defined Benefit Plan, Fair Value of Plan Assets Beginning of Year | 27,940,000 | 24,658,000 | ||
Defined Benefit Plan, Actual Return on Plan Assets | (410,000) | 737,000 | ||
Defined Benefit Plan, Employer Contribution | 6,401,000 | 5,310,000 | 5,000,000 | |
Defined Benefit Plan, Fair Value of Plan Assets End of Year | 25,769,000 | 27,940,000 | 24,658,000 | |
Defined Benefit Plan, Funded Status of Plan | (36,778,000) | (29,927,000) | ||
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year | 5,800,000 | |||
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract] | ||||
Defined Benefit Plan, Benefit Obligation End of Year | 62,547,000 | 57,867,000 | 43,285,000 | |
Defined Benefit Plan, Accumulated Benefit Obligation | 46,439,000 | 43,205,000 | ||
Defined Benefit Plan, Fair Value of Plan Assets Beginning of Year | (25,769,000) | (27,940,000) | (24,658,000) | |
Defined Benefit Plan, Accumulated Unfunded Benefit Obligation | 20,670,000 | 15,265,000 | ||
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income | ||||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | 20,966,000 | 17,812,000 | ||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax | 101,000 | 118,000 | ||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Transition Assets (Obligations), before Tax | 0 | 0 | ||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax | (21,067,000) | (17,930,000) | ||
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year | 1,500,000 | |||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax | (4,990,000) | (10,062,000) | 2,766,000 | |
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax | 0 | 0 | 0 | |
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax | (17,000) | (17,000) | (17,000) | |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax | 1,486,000 | 689,000 | 1,222,000 | |
Other Comprehensive Income (Loss), Finalization of Pension and Other Postretirement Benefit Plan Valuation, before Tax | (350,000) | 0 | 0 | |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax | 3,137,000 | 9,356,000 | (4,005,000) | |
Components of Net Periodic Benefit Costs for Both Pension Plans | ||||
Defined Benefit Plan, Service Cost | 7,949,000 | 6,335,000 | 6,291,000 | |
Defined Benefit Plan, Interest Cost | 2,496,000 | 2,191,000 | 1,627,000 | |
Defined Benefit Plan, Expected Return on Plan Assets | (2,182,000) | (1,978,000) | (1,538,000) | |
Defined Benefit Plan, Amortization of Prior Service Cost (Credit) | 17,000 | 17,000 | 17,000 | |
Defined Benefit Plan, Amortization of Gains (Losses) | 1,486,000 | 689,000 | 1,222,000 | |
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements | 350,000 | 0 | 0 | |
Defined Benefit Plan, Net Periodic Benefit Cost | $ 10,116,000 | $ 7,254,000 | $ 7,619,000 | |
Pension And Other Post-retirement Benefit Plans, Gain (Loss) Amortization Threshold | 10.00% | |||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 4.70% | 4.30% | 5.00% | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase | 6.20% | 6.20% | 6.20% | |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.30% | 5.00% | 3.90% | |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | [1] | 7.50% | 7.50% | 7.50% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 6.20% | 6.20% | 6.20% | |
Future Benefit Payments | ||||
Defined Benefit Plan, Expected Future Benefit Payments in Year One | $ 3,618,000 | |||
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 4,350,000 | |||
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 4,605,000 | |||
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 6,057,000 | |||
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 6,846,000 | |||
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 47,188,000 | |||
Qualified Plan [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Defined Benefit Plan Plan Assets Returned | 0 | |||
Non Qualified Plan [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Defined Benefit Plan, Fair Value of Plan Assets Beginning of Year | 0 | $ 0 | ||
Defined Benefit Plan, Fair Value of Plan Assets End of Year | 0 | 0 | $ 0 | |
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract] | ||||
Defined Benefit Plan, Fair Value of Plan Assets Beginning of Year | $ 0 | $ 0 | $ 0 | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 0.00% | 0.00% | 0.00% | |
[1] | There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan. |
Pension Benefits Fair Value of
Pension Benefits Fair Value of Plan Assets in Heirarchy (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities | 100.00% | |||
Defined Benefit Plan, Asset Allocation | 100.00% | 100.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 25,769 | $ 27,940 | $ 24,658 | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value | 5,045 | 4,864 | $ 3,421 | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases | 0 | 1,232 | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings | 165 | 144 | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss) | 16 | 67 | ||
Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 17,754 | 19,908 | ||
Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 2,970 | 3,168 | ||
Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | $ 5,045 | $ 4,864 | ||
Cash and Cash Equivalents [Member] | ||||
Defined Benefit Plan, Asset Allocation | 0.00% | 0.00% | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | ||
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | ||
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | ||
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | ||
Domestic Equity Securities [Member] | ||||
Defined Benefit Plan, Asset Allocation | [1] | 26.10% | 27.10% | |
Defined Benefit Plan, Fair Value of Plan Assets | [1] | $ 6,729 | $ 7,569 | |
Domestic Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [1] | 4,943 | 5,550 | |
Domestic Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [1] | 1,786 | 2,019 | |
Domestic Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [1] | $ 0 | $ 0 | |
International Equity Securities [Member] | ||||
Defined Benefit Plan, Asset Allocation | [2] | 13.00% | 12.50% | |
Defined Benefit Plan, Fair Value of Plan Assets | [2] | $ 3,353 | $ 3,498 | |
International Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [2] | 3,353 | 3,498 | |
International Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [2] | 0 | 0 | |
International Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [2] | $ 0 | $ 0 | |
Equity Securities [Member] | ||||
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities | 42.00% | |||
Defined Benefit Plan, Asset Allocation | 39.10% | 39.60% | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 10,082 | $ 11,067 | ||
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 8,296 | 9,048 | ||
Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 1,786 | 2,019 | ||
Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | ||
High-yield Bonds [Member] | ||||
Defined Benefit Plan, Asset Allocation | [3] | 2.80% | 2.90% | |
Defined Benefit Plan, Fair Value of Plan Assets | [3] | $ 722 | $ 797 | |
High-yield Bonds [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [3] | 722 | 797 | |
High-yield Bonds [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [3] | 0 | 0 | |
High-yield Bonds [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [3] | $ 0 | $ 0 | |
Fixed Income Investments [Member] | ||||
Defined Benefit Plan, Asset Allocation | [4] | 22.50% | 22.40% | |
Defined Benefit Plan, Fair Value of Plan Assets | [4] | $ 5,789 | $ 6,247 | |
Fixed Income Investments [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [4] | 5,789 | 6,247 | |
Fixed Income Investments [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [4] | 0 | 0 | |
Fixed Income Investments [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [4] | $ 0 | $ 0 | |
Floating Rate Corporate Debt [Member] | ||||
Defined Benefit Plan, Asset Allocation | [5] | 8.70% | 8.60% | |
Defined Benefit Plan, Fair Value of Plan Assets | [5] | $ 2,247 | $ 2,413 | |
Floating Rate Corporate Debt [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [5] | 2,247 | 2,413 | |
Floating Rate Corporate Debt [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [5] | 0 | 0 | |
Floating Rate Corporate Debt [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [5] | $ 0 | $ 0 | |
Fixed Income Securities [Member] | ||||
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities | 35.00% | |||
Defined Benefit Plan, Asset Allocation | 34.00% | 33.90% | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 8,758 | $ 9,457 | ||
Fixed Income Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 8,758 | 9,457 | ||
Fixed Income Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | ||
Fixed Income Securities [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 | ||
Commodity Contract [Member] | ||||
Defined Benefit Plan, Asset Allocation | [6] | 2.70% | 2.90% | |
Defined Benefit Plan, Fair Value of Plan Assets | [6] | $ 700 | $ 810 | |
Commodity Contract [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [6] | 700 | 810 | |
Commodity Contract [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [6] | 0 | 0 | |
Commodity Contract [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [6] | $ 0 | $ 0 | |
Real Estate [Member] | ||||
Defined Benefit Plan, Asset Allocation | [7] | 5.80% | 4.70% | |
Defined Benefit Plan, Fair Value of Plan Assets | [7] | $ 1,499 | $ 1,327 | |
Real Estate [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [7] | 0 | 0 | |
Real Estate [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [7] | 0 | 0 | |
Real Estate [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [7] | $ 1,499 | $ 1,327 | |
Hedge Funds [Member] | ||||
Defined Benefit Plan, Asset Allocation | [8] | 13.80% | 14.80% | |
Defined Benefit Plan, Fair Value of Plan Assets | [8] | $ 3,546 | $ 4,130 | |
Hedge Funds [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [8] | 0 | 593 | |
Hedge Funds [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [8] | 0 | 0 | |
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [8] | $ 3,546 | $ 3,537 | |
Collective Investment Trust [Member] | ||||
Defined Benefit Plan, Asset Allocation | [9] | 4.60% | 4.10% | |
Defined Benefit Plan, Fair Value of Plan Assets | [9] | $ 1,184 | $ 1,149 | |
Collective Investment Trust [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [9] | 0 | 0 | |
Collective Investment Trust [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [9] | 1,184 | 1,149 | |
Collective Investment Trust [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | [9] | $ 0 | $ 0 | |
Other Securities [Member] | ||||
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities | 23.00% | |||
Defined Benefit Plan, Asset Allocation | 26.90% | 26.50% | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 6,929 | $ 7,416 | ||
Other Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 700 | 1,403 | ||
Other Securities [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 1,184 | 1,149 | ||
Other Securities [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Fair Value of Plan Assets | $ 5,045 | $ 4,864 | ||
[1] | Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of this fund is to approximate the S&P 500 by investing in one or more collective investment funds. | |||
[2] | International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations. | |||
[3] | High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis. | |||
[4] | The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index. | |||
[5] | Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. | |||
[6] | Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities. | |||
[7] | The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. | |||
[8] | The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies. | |||
[9] | Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities. |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligations [Line Items] | ||
Asset Retirement Obligation, Current | $ 3,300 | $ 1,300 |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligation: Beginning of Year | 122,124 | 121,186 |
Asset Retirement Obligation, Liabilities Incurred | 14,471 | 13,506 |
Asset Retirement Obligation, Liabilities Settled | (24,781) | (11,372) |
Asset Retirement Obligation, Accretion Expense | 5,091 | 6,090 |
Asset Retirement Obligation, Revision of Estimate | 23,969 | (7,286) |
Asset Retirement Obligation: End of Year | $ 140,874 | $ 122,124 |
Minimum [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Fair Value Assumptions, Risk Free Interest Rate | 5.50% | |
Maximum [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Fair Value Assumptions, Risk Free Interest Rate | 12.00% |
Derivative Financial Instrume59
Derivative Financial Instruments (Details) | Feb. 17, 2016MMBTU$ / EnergyContent$ / Barrelsbbl | Jan. 14, 2016MMBTU$ / EnergyContent | Dec. 31, 2015MMBTU$ / EnergyContent$ / Barrelsbbl |
NYMEX Oil Contracts [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 5,600,000 | ||
Gas Contracts [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 172,700,000 | ||
NGL Contracts [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 13,000,000 | ||
NYMEX Oil Swap Contract First Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 1,868,000 | ||
Weighted- Average Contract Price | $ / Barrels | 86.93 | ||
NYMEX Oil Swap Contract Second Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 1,752,000 | ||
Weighted- Average Contract Price | $ / Barrels | 86.73 | ||
NYMEX Oil Swap Contract Third Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 1,170,000 | ||
Weighted- Average Contract Price | $ / Barrels | 90.29 | ||
NYMEX Oil Swap Contract Fourth Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 780,000 | ||
Weighted- Average Contract Price | $ / Barrels | 90.05 | ||
NYMEX Oil Swap Contracts [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 5,570,000 | ||
Gas Swaps Contract First Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 3.82 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 23,341,000 | ||
Gas Swaps Contract Second Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 3.40 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 20,780,000 | ||
Gas Swaps Contract Third Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 3.38 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 18,829,000 | ||
Gas Swaps Contract Fourth Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 3.82 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 17,236,000 | ||
Gas Swaps Contract 2017 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 4.09 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 37,528,000 | ||
Gas Swaps Contract 2018 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 4.27 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 30,606,000 | ||
Gas Swaps Contract 2019 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 4.34 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 24,415,000 | ||
Gas Swaps Contracts [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 172,735,000 | ||
IF El Paso Permian [Member] | |||
Derivative Financial Instruments | |||
Index percent of natural gas fixed swaps | 2.00% | ||
IF NNG Ventura [Member] | |||
Derivative Financial Instruments | |||
Index percent of natural gas fixed swaps | 2.00% | ||
IF NGPL TXOK [Member] | |||
Derivative Financial Instruments | |||
Index percent of natural gas fixed swaps | 1.00% | ||
IF HSC [Member] | |||
Derivative Financial Instruments | |||
Index percent of natural gas fixed swaps | 95.00% | ||
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract First Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 926,000 | ||
Weighted- Average Contract Price | $ / Barrels | 8.29 | ||
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Second Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 828,000 | ||
Weighted- Average Contract Price | $ / Barrels | 8.28 | ||
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Third Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 751,000 | ||
Weighted- Average Contract Price | $ / Barrels | 8.70 | ||
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Fourth Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 688,000 | ||
Weighted- Average Contract Price | $ / Barrels | 8.71 | ||
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2017 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 2,271,000 | ||
Weighted- Average Contract Price | $ / Barrels | 9.16 | ||
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2018 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 1,671,000 | ||
Weighted- Average Contract Price | $ / Barrels | 10.65 | ||
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2019 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 1,200,000 | ||
Weighted- Average Contract Price | $ / Barrels | 10.92 | ||
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2020 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 539,000 | ||
Weighted- Average Contract Price | $ / Barrels | 11.13 | ||
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contracts [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 8,874,000 | ||
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 1,059,000 | ||
Weighted- Average Contract Price | $ / Barrels | 19.60 | ||
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 949,000 | ||
Weighted- Average Contract Price | $ / Barrels | 19.64 | ||
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 862,000 | ||
Weighted- Average Contract Price | $ / Barrels | 19.03 | ||
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 791,000 | ||
Weighted- Average Contract Price | $ / Barrels | 18.53 | ||
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2017 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 3,661,000 | ||
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 143,000 | ||
Weighted- Average Contract Price | $ / Barrels | 25.62 | ||
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 130,000 | ||
Weighted- Average Contract Price | $ / Barrels | 25.62 | ||
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2017 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 273,000 | ||
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 122,000 | ||
Weighted- Average Contract Price | $ / Barrels | 25.87 | ||
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 111,000 | ||
Weighted- Average Contract Price | $ / Barrels | 25.87 | ||
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2017 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 0 | ||
Weighted- Average Contract Price | $ / Barrels | 0 | ||
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 233,000 | ||
Subsequent Event [Member] | Gas Swaps Contract First Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 3.82 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 23,341,000 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU | 0 | ||
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent | 0 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU | 23,341,000 | ||
Subsequent Event [Member] | Gas Swaps Contract Second Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 3.40 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 20,780,000 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU | 0 | ||
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent | 0 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU | 20,780,000 | ||
Subsequent Event [Member] | Gas Swaps Contract Third Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 3.38 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 18,829,000 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU | 0 | ||
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent | 0 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU | 18,829,000 | ||
Subsequent Event [Member] | Gas Swaps Contract Fourth Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 3.82 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 17,236,000 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU | 0 | ||
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent | 0 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU | 17,236,000 | ||
Subsequent Event [Member] | Gas Swaps Contract 2017 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 4.26 | 4.43 | |
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 76,135,000 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Sold Volumes on Subsequent Date | MMBTU | 38,600,000 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU | 0 | ||
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent | 0 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU | 76,135,000 | ||
Subsequent Event [Member] | Gas Swaps Contract 2018 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 4.27 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 30,606,000 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU | (30,606,000) | ||
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent | 4.27 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU | 0 | ||
Subsequent Event [Member] | Gas Swaps Contract 2019 [Member] | |||
Derivative Financial Instruments | |||
Weighted- Average Contract Price | $ / EnergyContent | 4.34 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 24,415,000 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU | (24,415,000) | ||
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent | 4.34 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU | 0 | ||
Subsequent Event [Member] | Gas Swaps Contracts [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 211,342,000 | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU | (55,021,000) | ||
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU | 156,321,000 | ||
Subsequent Event [Member] | IF El Paso Permian [Member] | |||
Derivative Financial Instruments | |||
Index percent of natural gas fixed swaps | 2.00% | ||
Subsequent Event [Member] | IF NNG Ventura [Member] | |||
Derivative Financial Instruments | |||
Index percent of natural gas fixed swaps | 1.00% | ||
Subsequent Event [Member] | IF NGPL TXOK [Member] | |||
Derivative Financial Instruments | |||
Index percent of natural gas fixed swaps | 1.00% | ||
Subsequent Event [Member] | IF HSC [Member] | |||
Derivative Financial Instruments | |||
Index percent of natural gas fixed swaps | 96.00% | ||
Subsequent Event [Member] | OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2018 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 1,600,000 | ||
Weighted- Average Contract Price | $ / Barrels | 8.67 | ||
Subsequent Event [Member] | OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2016 [Member] | |||
Derivative Financial Instruments | |||
Derivative, Nonmonetary Notional Amount, Volume | 235,000 | ||
Weighted- Average Contract Price | $ / Barrels | 22.58 |
Derivative Financial Instrume60
Derivative Financial Instruments Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | ||
Fair value of derivative assets and liabilities | ||||
Derivative, Fair Value, Net | $ 488,403 | $ 592,138 | ||
Derivative Assets, Current | 367,710 | 402,668 | ||
Derivative Liabilities, Current | 8 | 0 | ||
Derivative Assets, Noncurrent | 120,701 | 189,540 | ||
Derivative Liabilities, Noncurrent | 0 | 70 | ||
Derivative Asset, Fair Value, Gross Asset | 488,411 | 592,208 | ||
Derivative Liability, Fair Value, Gross Liability | 8 | 70 | ||
Derivative Asset, Not Offset, Policy Election Deduction | (8) | (70) | ||
Derivative Liability, Not Offset, Policy Election Deduction | 8 | 70 | ||
Derivative Asset, Fair Value, Amount Offset Against Collateral, Net | 488,403 | 592,138 | ||
Derivative Liability, Fair Value, Amount Offset Against Collateral, Net | 0 | 0 | ||
Not Designated as Hedging Instrument [Member] | ||||
Fair value of derivative assets and liabilities | ||||
Derivative Assets, Current | 402,668 | |||
Derivative Liabilities, Current | 0 | |||
Derivative Assets, Noncurrent | 189,540 | |||
Derivative Liabilities, Noncurrent | 70 | |||
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Fair value of derivative assets and liabilities | ||||
Derivative Asset, Fair Value, Gross Asset | 488,411 | [1] | 592,208 | [2] |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Not Designated as Hedging Instrument [Member] | ||||
Fair value of derivative assets and liabilities | ||||
Derivative Asset, Fair Value, Gross Asset | 488,411 | 592,208 | ||
Derivative Liability, Fair Value, Gross Liability | $ 8 | [1] | $ 70 | [2] |
[1] | This represents a financial asset or liability that is measured at fair value on a recurring basis. | |||
[2] | This represents a financial asset or liability that is measured at fair value on a recurring basis. |
Derivative Financial Instrume61
Derivative Financial Instruments Gains and Losses (Details) | 12 Months Ended | |||
Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | $ 0 | $ 0 | $ 0 | |
Derivative, (Gain) Loss on Derivative, Net [Abstract] | ||||
Derivative Settlement Gain (Loss) | 512,566,000 | 12,615,000 | 22,062,000 | |
Derivative gain | 408,831,000 | 583,264,000 | 3,080,000 | |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | [1] | 0 | 0 | (1,115,000) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax | [2] | 0 | 0 | 1,777,000 |
NYMEX Oil Contracts [Member] | ||||
Derivative, (Gain) Loss on Derivative, Net [Abstract] | ||||
Derivative Settlement Gain (Loss) | 362,219,000 | 28,410,000 | (15,161,000) | |
Derivative gain | 191,165,000 | 457,082,000 | (14,665,000) | |
Gas Contracts [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain on Early Settlement of Derivatives | 15,300,000 | 5,600,000 | ||
Derivative, (Gain) Loss on Derivative, Net [Abstract] | ||||
Derivative Settlement Gain (Loss) | [3] | 123,180,000 | (26,706,000) | 30,338,000 |
Derivative gain | 189,734,000 | 93,267,000 | 14,053,000 | |
NGL Contracts [Member] | ||||
Derivative, (Gain) Loss on Derivative, Net [Abstract] | ||||
Derivative Settlement Gain (Loss) | 27,167,000 | 10,911,000 | 6,885,000 | |
Derivative gain | $ 27,932,000 | $ 32,915,000 | $ 3,692,000 | |
Cash Flow Hedging [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Number of Instruments Held | 0 | 0 | 0 | |
[1] | Reclassification from accumulated other comprehensive loss related to de-designated hedges. Refer to Note 10 - Derivative Financial Instruments for further information. | |||
[2] | As of December 31, 2013, all commodity derivative contracts that had been previously designated as cash flow hedges had settled and had been reclassified into earnings from AOCL. | |||
[3] | Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million, respectively, of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region. |
Derivative Financial Instrume62
Derivative Financial Instruments Credit Facility and Derivative Counterparties (Details) | Dec. 31, 2015 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Percentage of Proved Oil and Gas Properties Secured for Credit Facility Borrowing | 75.00% |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |||
Assets: | |||||
Derivatives | $ 488,411 | $ 592,208 | |||
Proved oil and gas properties | 7,606,405 | 7,348,436 | |||
Property, Plant and Equipment, Other, Net | 153,100 | 334,356 | |||
Oil and gas properties held for sale | 641 | 17,891 | |||
Liabilities [Abstract] | |||||
Derivative Liability, Fair Value, Gross Liability | 8 | 70 | |||
Net Profits Plan Liability Noncurrent | 7,611 | 27,136 | |||
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | |||||
Assets: | |||||
Derivatives | 0 | [1] | 0 | [2] | |
Liabilities [Abstract] | |||||
Net Profits Plan Liability Noncurrent | 0 | [1] | 0 | [2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Not Designated as Hedging Instrument [Member] | |||||
Liabilities [Abstract] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | 0 | [2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | |||||
Assets: | |||||
Derivatives | 488,411 | [2] | 592,208 | [1] | |
Liabilities [Abstract] | |||||
Net Profits Plan Liability Noncurrent | 0 | [1] | 0 | [2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Not Designated as Hedging Instrument [Member] | |||||
Assets: | |||||
Derivatives | 488,411 | 592,208 | |||
Liabilities [Abstract] | |||||
Derivative Liability, Fair Value, Gross Liability | 8 | [2] | 70 | [1] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | |||||
Assets: | |||||
Derivatives | 0 | [1] | 0 | [2] | |
Liabilities [Abstract] | |||||
Net Profits Plan Liability Noncurrent | 7,611 | [1] | 27,136 | [2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Not Designated as Hedging Instrument [Member] | |||||
Liabilities [Abstract] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | 0 | [2] | |
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member] | |||||
Assets: | |||||
Proved oil and gas properties | 0 | [3] | 0 | [4] | |
Property, Plant and Equipment, Other, Net | [4] | 0 | |||
Oil and gas properties held for sale | [4] | 0 | |||
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member] | |||||
Assets: | |||||
Proved oil and gas properties | 0 | [3] | 0 | [4] | |
Property, Plant and Equipment, Other, Net | [4] | 0 | |||
Oil and gas properties held for sale | [4] | 0 | |||
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | |||||
Assets: | |||||
Proved oil and gas properties | 124,184 | [3] | 33,423 | [4] | |
Property, Plant and Equipment, Other, Net | [4] | $ 629 | |||
Oil and gas properties held for sale | [4] | $ 17,891 | |||
[1] | This represents a financial asset or liability that is measured at fair value on a recurring basis. | ||||
[2] | This represents a financial asset or liability that is measured at fair value on a recurring basis. | ||||
[3] | This represents a non-financial asset that is measured at fair value on a nonrecurring basis. | ||||
[4] | This represents a non-financial asset that is measured at fair value on a nonrecurring basis. |
Fair Value Measurements (Deta64
Fair Value Measurements (Details 2) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast | 5 years | |||||
Proved Oil and Gas Properties | ||||||
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast | 5 years | |||||
Impairment of proved properties | $ 468,679 | $ 84,480 | $ 172,641 | |||
Proved Oil and Gas Property, Successful Effort Method | 7,606,405 | 7,348,436 | ||||
Unproved Oil and Gas Property, Successful Effort Method | 284,538 | 532,498 | ||||
Impairment of other property and equipment | 49,369 | 0 | 0 | |||
Property, Plant and Equipment, Other, Net | 153,100 | 334,356 | ||||
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down | 98,600 | 27,600 | ||||
Oil and gas properties held for sale | $ 641 | $ 17,891 | ||||
Net Profit Plan liability [Member] | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value Inputs, Discount Rate | 10.00% | 12.00% | ||||
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast | 5 years | |||||
Period Used for Price Assumptions of Strip Prices of Liabilities | 1 year | |||||
Percentage change in commodity prices (as a percent) | 5.00% | |||||
Change in liability due to change in commodity prices by 5 percent | $ 1,100 | |||||
Percent Change in Discount Rate for Sensitivity Analysis | 1.00% | |||||
Sensitivity Analysis Change in Liability Due to Change in Discount Rate | $ 300 | |||||
Fair Value, NPP Reconciliation, Calculation [Roll Forward] | ||||||
Net Profits Plan Liability: Beginning Balance | 27,136 | $ 56,985 | 78,827 | |||
Net increase (decrease) in liability | [1] | (12,238) | (12,492) | 3,527 | ||
Net settlements | [1],[2] | (7,287) | (17,357) | (25,369) | ||
Transfers in (out) of Level 3 | 0 | 0 | 0 | |||
Net Profits Plan Liability: Ending balance | 7,611 | 27,136 | 56,985 | |||
Cash Payments Made or Accrued under Profit Sharing Plan Related to Divested Property | $ 3,800 | 8,300 | $ 10,300 | |||
Proved Oil and Gas Properties | ||||||
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast | 5 years | |||||
6.625% Senior Notes Due 2019 [Member] | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Long-term Debt, Fair Value | [3] | $ 0 | 350,018 | |||
6.50% Senior Notes Due 2021 [Member] | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Long-term Debt, Fair Value | 262,938 | 343,000 | ||||
6.125% Senior Notes Due 2022 [Member] | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Long-term Debt, Fair Value | 440,250 | 556,500 | ||||
6.50% Senior Notes Due 2023 [Member] | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Long-term Debt, Fair Value | 296,000 | 379,000 | ||||
5% Senior Notes Due 2024 [Member] | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Long-term Debt, Fair Value | 334,065 | 435,000 | ||||
5.625% Senior Notes Due 2025 [Member] | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Long-term Debt, Fair Value | [3] | 326,875 | $ 0 | |||
Oil and Gas Properties [Member] | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value Inputs, Discount Rate | 12.00% | |||||
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | ||||||
Proved Oil and Gas Properties | ||||||
Proved Oil and Gas Property, Successful Effort Method | 124,184 | [4] | $ 33,423 | [5] | ||
Unproved Oil and Gas Property, Successful Effort Method | [4] | 0 | 0 | |||
Property, Plant and Equipment, Other, Net | [5] | $ 629 | ||||
Oil and gas properties held for sale | [5] | $ 17,891 | ||||
Minimum [Member] | Oil and Gas Properties [Member] | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value Inputs, Discount Rate | 10.00% | |||||
Maximum [Member] | Oil and Gas Properties [Member] | ||||||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value Inputs, Discount Rate | 15.00% | |||||
[1] | Net changes in the Company’s Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations. | |||||
[2] | Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash payments made or accrued under the Net Profits Plan of $3.8 million, $8.3 million, and $10.3 million for the years ended December 31, 2015, 2014, and 2013, respectively, as a result of the divestitures of properties subject to the Net Profits Plan. | |||||
[3] | The 2019 Notes were fully redeemed on June 22, 2015 and the 2025 Notes were issued on May 21, 2015. | |||||
[4] | This represents a non-financial asset that is measured at fair value on a nonrecurring basis. | |||||
[5] | This represents a non-financial asset that is measured at fair value on a nonrecurring basis. |
Acquisition and Development A65
Acquisition and Development Agreement and Carry and Earning Agreement (Details) - Mitsui E&P Texas LP $ in Millions | Jun. 30, 2011USD ($) |
Acquisition and Development Agreement [Abstract] | |
Percentage of Working Interests Transferred to Acquirer Entity | 12.50% |
Acreage of Working Interests Transferred to Acquirer Entity | 39,000 |
Percentage of the entity's costs and expenses during the first three years following the closing of the transaction, borne by the acquirer entity (as a percent) | 90.00% |
Costs and expenses incurred by acquiree entity on behalf of entity that the acquirer entity has agreed to pay | $ 680 |
Portion of Drilling and Completion Costs Not Carried by Acquirer | 10.00% |
Suspended Well Costs (Details)
Suspended Well Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | |||
Capitalized Exploratory Well Costs Beginning Balance | $ 43,589 | $ 34,527 | $ 9,100 |
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves | 11,952 | 43,589 | 34,527 |
Capitalized Exploratory Well Cost, Divestitures | (809) | 0 | 0 |
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves | (18,485) | (33,340) | (9,100) |
Capitalized Exploratory Well Cost, Charged to Expense | (24,295) | (1,187) | 0 |
Capitalized Exploratory Well Costs Ending Balance | 11,952 | $ 43,589 | $ 34,527 |
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year | $ 0 |