Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2018 | Oct. 30, 2018 | |
Document and Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q3 | |
Entity Registrant Name | ENERGEN CORP | |
Entity Central Index Key | 277,595 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Emerging Growth Company | false | |
Entity Small Business | false | |
Entity Common Stock, Shares Outstanding (in shares) | 97,527,659 |
Consolidated Balance Sheets (Un
Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Current Assets | ||
Cash and cash equivalents | $ 17,057 | $ 439 |
Accounts receivable, net | 183,816 | 158,787 |
Inventories, net | 28,652 | 13,177 |
Derivative instruments | 4,226 | 0 |
Income tax receivable | 6,762 | 6,905 |
Prepayments and other | 5,999 | 12,085 |
Total current assets | 246,512 | 191,393 |
Oil and natural gas properties, successful efforts method | ||
Proved properties | 9,387,502 | 8,466,708 |
Unproved properties | 551,217 | 453,028 |
Less accumulated depreciation, depletion and amortization | (4,587,082) | (4,200,797) |
Oil and natural gas properties, net | 5,351,637 | 4,718,939 |
Other property and equipment, net | 43,471 | 44,581 |
Total property, plant and equipment, net | 5,395,108 | 4,763,520 |
Other postretirement assets | 2,590 | 2,646 |
Noncurrent income tax receivable, net | 70,716 | 70,716 |
Other assets | 9,112 | 5,620 |
TOTAL ASSETS | 5,724,038 | 5,033,895 |
Current Liabilities | ||
Accounts payable | 129,602 | 75,167 |
Accrued taxes | 23,509 | 2,631 |
Accrued wages and benefits | 15,416 | 26,170 |
Accrued capital costs | 150,600 | 74,909 |
Revenue and royalty payable | 65,023 | 54,072 |
Derivative instruments | 172,772 | 71,379 |
Other | 12,635 | 17,916 |
Total current liabilities | 569,557 | 322,244 |
Long-term debt | 953,173 | 782,861 |
Asset retirement obligations | 94,722 | 88,378 |
Noncurrent derivative instruments | 57,457 | 8,886 |
Deferred income taxes | 435,848 | 387,807 |
Other long-term liabilities | 5,398 | 5,262 |
Total liabilities | 2,116,155 | 1,595,438 |
Commitments and Contingencies | ||
Shareholders’ Equity | ||
Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized | 0 | 0 |
Common shareholders’ equity | ||
Common stock, $0.01 par value; 150,000,000 shares authorized; 100,799,082 shares and 100,327,433 shares issued at September 30, 2018 and December 31, 2017, respectively | 1,008 | 1,003 |
Premium on capital stock | 1,405,227 | 1,388,082 |
Retained earnings | 2,345,491 | 2,185,161 |
Accumulated other comprehensive income, net of tax | ||
Postretirement plans | 482 | 380 |
Deferred compensation plan | 3,311 | 2,681 |
Treasury stock, at cost; 3,350,023 shares and 3,192,252 shares at September 30, 2018 and December 31, 2017, respectively | (147,636) | (138,850) |
Total shareholders’ equity | 3,607,883 | 3,438,457 |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ 5,724,038 | $ 5,033,895 |
Consolidated Balance Sheets (_2
Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares | Sep. 30, 2018 | Dec. 31, 2017 |
Shareholders’ Equity | ||
Preferred stock, cumulative, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, cumulative, shares authorized (in shares) | 5,000,000 | 5,000,000 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 150,000,000 | 150,000,000 |
Common stock, shares issued (in shares) | 100,799,082 | 100,327,433 |
Treasury stock, at cost, shares (in shares) | 3,350,023 | 3,192,252 |
Consolidated Statements of Oper
Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues | ||||
Oil, natural gas liquids and natural gas sales | $ 380,884 | $ 249,114 | $ 1,110,317 | $ 644,212 |
Gain (loss) on derivative instruments, net | (154,628) | (57,610) | (188,242) | 45,037 |
Total revenues | 226,256 | 191,504 | 922,075 | 689,249 |
Operating Costs and Expenses | ||||
Oil, natural gas liquids and natural gas production | 55,078 | 44,549 | 165,671 | 129,746 |
Production and ad valorem taxes | 25,204 | 15,326 | 72,505 | 41,364 |
Depreciation, depletion and amortization | 134,177 | 131,756 | 392,398 | 352,957 |
Asset impairment | 178 | 100 | 428 | 1,589 |
Exploration | 963 | 625 | 3,420 | 6,259 |
General and administrative (including stock-based compensation of $5,076 and $4,713 for the three months ended September 30, 2018 and 2017, respectively, and $13,839 and $11,101 for the nine months ended September 30, 2018 and 2017, respectively) | 29,566 | 21,590 | 73,756 | 62,014 |
Accretion of discount on asset retirement obligations | 1,604 | 1,473 | 4,704 | 4,330 |
Gain on sale of assets and other, net | (191) | (5,977) | (34,027) | (6,980) |
Total operating costs and expenses | 246,579 | 209,442 | 678,855 | 591,279 |
Operating Income (Loss) | (20,323) | (17,938) | 243,220 | 97,970 |
Other Income (Expense) | ||||
Interest expense | (11,550) | (9,985) | (32,601) | (28,210) |
Other income | 1 | 231 | 693 | 1,006 |
Total other expense | (11,549) | (9,754) | (31,908) | (27,204) |
Income (Loss) Before Income Taxes | (31,872) | (27,692) | 211,312 | 70,766 |
Income tax expense (benefit) | (5,300) | (9,206) | 50,695 | 26,368 |
Net Income (Loss) | $ (26,572) | $ (18,486) | $ 160,617 | $ 44,398 |
Diluted Earnings Per Average Common Share (in dollars per share) | $ (0.27) | $ (0.19) | $ 1.64 | $ 0.45 |
Basic Earnings Per Average Common Share (in dollars per share) | $ (0.27) | $ (0.19) | $ 1.65 | $ 0.46 |
Diluted Average Common Shares Outstanding (in shares) | 97,485 | 97,198 | 98,013 | 97,678 |
Basic Average Common Shares Outstanding (in shares) | 97,485 | 97,198 | 97,413 | 97,176 |
Consolidated Statements of Op_2
Consolidated Statements of Operations (Unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Income Statement [Abstract] | ||||
Stock-based compensation | $ 5,076 | $ 4,713 | $ 13,839 | $ 11,101 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Statement of Comprehensive Income [Abstract] | ||||
Net income | $ (26,572) | $ (18,486) | $ 160,617 | $ 44,398 |
Postretirement plans | ||||
Amortization of prior service cost, net of tax of ($28), ($42), ($85) and ($129), respectively | (85) | (71) | (255) | (212) |
Amortization of net loss, net of tax of $8, $0, $23 and $3, respectively | 23 | 2 | 71 | 4 |
Total postretirement plans | (62) | (69) | (184) | (208) |
Comprehensive Income (Loss) | $ (26,634) | $ (18,555) | $ 160,433 | $ 44,190 |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Statement of Comprehensive Income [Abstract] | ||||
Amortization of prior service cost, tax | $ (28) | $ (42) | $ (85) | $ (129) |
Amortization of net loss, tax | $ 8 | $ 0 | $ 23 | $ 3 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Operating Activities | ||
Net income | $ 160,617 | $ 44,398 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 392,398 | 352,957 |
Asset impairment | 428 | 1,589 |
Accretion of discount on asset retirement obligations | 4,704 | 4,330 |
Deferred income taxes | 48,103 | 39,240 |
Change in derivative fair value | 152,120 | (47,030) |
Gain on sale of assets | (34,474) | (3,972) |
Stock-based compensation expense | 13,839 | 11,101 |
Exploration, including dry holes | 712 | 0 |
Other, net | (3,086) | (3,491) |
Net change in: | ||
Accounts receivable | (25,029) | (55,897) |
Inventories | (15,475) | (316) |
Accounts payable | 48,169 | 31,614 |
Accrued taxes/income tax receivable | 21,021 | 24,888 |
Other current assets and liabilities | (939) | (16,634) |
Net cash provided by operating activities | 763,108 | 382,777 |
Investing Activities | ||
Additions to oil and natural gas properties | (833,284) | (720,243) |
Acquisitions | (81,135) | (263,364) |
Proceeds on the sale of assets, net | 1,051 | 4,009 |
Net cash used in investing activities | (913,368) | (979,598) |
Financing Activities | ||
Issuance of common stock, net | 5,034 | 273 |
Taxes paid for shares withheld | (8,156) | (3,293) |
Reduction of long-term debt | 0 | (24,000) |
Net change in credit facility | 170,000 | 238,000 |
Net cash provided by financing activities | 166,878 | 210,980 |
Net change in cash and cash equivalents | 16,618 | (385,841) |
Cash and cash equivalents at beginning of period | 439 | 386,093 |
Cash and cash equivalents at end of period | $ 17,057 | $ 252 |
Organization and Basis of Prese
Organization and Basis of Presentation | 9 Months Ended |
Sep. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Basis of Presentation | ORGANIZATION AND BASIS OF PRESENTATION Energen Corporation (Energen or the Company) is an oil and natural gas exploration and production company engaged in the exploration, development and production of oil, natural gas liquids and natural gas. Our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources) and primarily occur within the Midland Basin, the Delaware Basin and the Central Basin Platform areas of the Permian Basin in west Texas and New Mexico. Our corporate headquarters is located in Birmingham, Alabama. The unaudited consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes thereto included in the 2017 Annual Report of Energen on Form 10-K. Our accompanying unaudited consolidated financial statements include Energen and its subsidiaries, principally Energen Resources, and have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present a fair statement of our financial position, results of operations, and cash flows for the periods and as of the dates shown. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior periods’ financial statements to the current-quarter presentation. Proposed Merger of Energen with Diamondback Energy, Inc. (Diamondback) On August 14, 2018, Energen entered into an Agreement and Plan of Merger (the Merger Agreement) with Diamondback and Sidewinder Merger Sub Inc., a wholly owned subsidiary of Diamondback (Merger Sub). The closing of the Merger (as defined below) is expected to occur in the fourth quarter of 2018. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, (1) Merger Sub will be merged with and into Energen (the Merger), with Energen surviving and continuing as the surviving corporation in the Merger, and, (2) at the effective time of the Merger (the Effective Time), each outstanding share of common stock of Energen (other than shares held in treasury by Energen, shares owned by Diamondback or Merger Sub or shares with respect to which dissenters’ rights have been validly exercised in accordance with Alabama law) will be converted into the right to receive 0.6442 of a share of common stock of Diamondback, plus cash in lieu of any fractional shares that otherwise would have been issued (the Merger Consideration). Diamondback’s common stock is listed and traded on NASDAQ under the ticker symbol FANG. The completion of the Merger is subject to satisfaction or waiver of certain customary mutual closing conditions, including (1) the receipt of the required approvals from Energen shareholders and Diamondback stockholders, (2) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, as amended (which termination was received on September 10, 2018), (3) the absence of any governmental order or law that makes consummation of the Merger illegal or otherwise prohibited, (4) the effectiveness of the registration statement on Form S-4 to be filed by Diamondback pursuant to which the shares of Diamondback common stock to be issued in connection with the merger are registered with the Securities and Exchange Commission (the SEC), (5) the authorization for listing of Diamondback common stock to be issued in connection with the merger on the NASDAQ and (6) the receipt by each party of a customary opinion that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the U.S. tax code. The obligation of each party to consummate the Merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions) and the other party having performed in all material respects its obligations under the Merger Agreement. The Merger Agreement contains termination rights for each of Diamondback and Energen, including, among others, (1) if the consummation of the Merger does not occur on or before March 31, 2019, subject to extension to June 30, 2019 for the sole purpose of obtaining regulatory clearances and (2) subject to certain conditions, if such party wishes to terminate the Merger Agreement to enter into a definitive agreement with respect to a Parent Superior Proposal or a Company Superior Proposal (in each case, as such term is defined in the Merger Agreement), as applicable. Upon termination of the Merger Agreement under specified circumstances, including the termination by Energen in the event of a change of recommendation by the Diamondback board of directors or by Diamondback to enter into an agreement providing for a Parent Superior Proposal (as such term is defined in the Merger Agreement), Diamondback would be required to pay Energen a termination fee of $400 million . In addition, upon termination of the Merger Agreement under specified circumstances, including the termination by Diamondback in the event of a change of recommendation by the Energen board of directors or by Energen to enter into an agreement providing for a Company Superior Proposal (as such term is defined in the Merger Agreement), Energen would be required to pay Diamondback a termination fee of $250 million . In addition, if the Merger Agreement is terminated because of a failure of Energen’s shareholders or Diamondback’s stockholders to approve the proposals required to complete the Merger, Energen and Diamondback, as applicable, may be required to reimburse the other party for its actual transaction expenses in an amount not to exceed $40 million , in the case of Energen’s expenses, and $25 million , in the case of Diamondback’s expenses. In no event will either party be entitled to receive more than one termination fee, net of any expense reimbursement. In connection with the Merger, Diamondback filed with the SEC, on October 18, 2018, an amendment to the registration statement on Form S-4 that was originally filed on September 13, 2018, that includes a joint proxy statement of Energen and Diamondback. The joint proxy statement also constitutes a prospectus for Diamondback with respect to the shares of Diamondback common stock to be issued as Merger Consideration. The registration statement was declared effective by the SEC on October 24, 2018, and Energen and Diamondback commenced mailing the definitive joint proxy statement/prospectus to Energen shareholders and Diamondback stockholders on or about October 26, 2018. Additional information on the proposed Merger is included in the registration statement on Form S-4/A filed by Diamondback with the SEC on October 18, 2018. |
Derivative Commodity Instrument
Derivative Commodity Instruments | 9 Months Ended |
Sep. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Commodity Instruments | DERIVATIVE COMMODITY INSTRUMENTS We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas liquids and natural gas production. These derivative commodity instruments are accounted for as mark-to-market transactions with gains or losses recognized in the period of change in gain (loss) on derivative instruments, net. Such instruments may include over-the-counter (OTC) swaps, options and basis swaps typically executed with investment and commercial banks and energy-trading firms. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the consolidated balance sheets: (in thousands) September 30, 2018 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amounts Presented in the Balance Sheets Financial Instruments Cash Collateral Received Net Fair Value Presented in the Balance Sheets Derivatives not designated as hedging instruments Assets Derivative instruments $ 55,455 $ (51,229 ) $ 4,226 $ — $ — $ 4,226 Noncurrent derivative instruments 3,592 (3,592 ) — — — — Total derivative assets 59,047 (54,821 ) 4,226 — — 4,226 Liabilities Derivative instruments 224,001 (51,229 ) 172,772 — — 172,772 Noncurrent derivative instruments 61,049 (3,592 ) 57,457 — — 57,457 Total derivative liabilities 285,050 (54,821 ) 230,229 — — 230,229 Total derivatives $ (226,003 ) $ — $ (226,003 ) $ — $ — $ (226,003 ) (in thousands) December 31, 2017 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amounts Presented in the Balance Sheets Financial Instruments Cash Collateral Received Net Fair Value Presented in the Balance Sheets Derivatives not designated as hedging instruments Assets Derivative instruments $ 1,758 $ (1,758 ) $ — $ — $ — $ — Noncurrent derivative instruments 42 (42 ) — — — — Total derivative assets 1,800 (1,800 ) — — — — Liabilities Derivative instruments 73,137 (1,758 ) 71,379 — — 71,379 Noncurrent derivative instruments 8,928 (42 ) 8,886 — — 8,886 Total derivative liabilities 82,065 (1,800 ) 80,265 — — 80,265 Total derivatives $ (80,265 ) $ — $ (80,265 ) $ — $ — $ (80,265 ) Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. Additionally, Energen is at risk of economic loss based upon the creditworthiness of our counterparties. We were in a net loss position with all thirteen our active counterparties at September 30, 2018 . The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the consolidated statements of operations: Location on Statement of Operations Three months ended September 30, (in thousands) 2018 2017 Gain (loss) recognized in income on derivatives Gain (loss) on derivative instruments, net $ (154,628 ) $ (57,610 ) Location on Statement of Operations Nine months ended September 30, (in thousands) 2018 2017 Gain (loss) recognized in income on derivatives Gain (loss) on derivative instruments, net $ (188,242 ) 45,037 As of September 30, 2018, Energen had entered into the following derivative transactions for the remainder of 2018 and subsequent years: Production Period Description Total Hedged Volumes Weighted Average Contract Price Oil 2018 NYMEX Swaps 540 MBbl $60.25 Bbl NYMEX Three-Way Collars 3,375 MBbl Ceiling sold price (call) $60.04 Bbl Floor purchased price (put) $45.47 Bbl Floor sold price (put) $35.47 Bbl 2019 NYMEX Swaps 8,280 MBbl $61.66 Bbl NYMEX Three-Way Collars 5,760 MBbl Ceiling sold price (call) $61.65 Bbl Floor purchased price (put) $45.94 Bbl Floor sold price (put) $35.94 Bbl Oil Basis Differential 2018 WTI/WTI Basis Swaps 3,150 MBbl $(1.46) Bbl 2019 WTI/WTI Basis Swaps 16,560 MBbl $(5.52) Bbl 2020 WTI/WTI Basis Swaps 15,120 MBbl $(1.20) Bbl Natural Gas Liquids 2018 Liquids Swaps 34.0 MMGal $0.61 Gal 2019 Liquids Swaps 115.9 MMGal $0.65 Gal Natural Gas 2018 Basin Specific Swaps - West Texas/Waha 1.8 Bcf $1.70 Mcf 2018 Basin Specific Swaps - Permian 0.9 Bcf $2.56 Mcf WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing As of September 30, 2018 , the maximum term over which Energen has hedged exposures to the variability of cash flows is through December 31, 2020. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). In determining fair value, we use various valuation approaches and classify all assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own considerations about the assumptions other market participants would use in pricing the asset or liability based on the best information available in the circumstances. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The hierarchy is broken down into three levels based on the observability of inputs as follows: Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities; Level 2 - Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date; and Level 3 - Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumptions that market participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints. No transfers between fair value hierarchy levels occurred during the three months and nine months ended September 30, 2018 . Assets and Liabilities Measured at Fair Value on a Recurring Basis Energen classifies the fair value of multiple derivative instruments executed under master netting arrangements as net derivative assets and liabilities. The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis: September 30, 2018 (in thousands) Level 2 Level 3 Total Assets: Derivative instruments $ (4,645 ) $ 8,871 $ 4,226 Total assets (4,645 ) 8,871 4,226 Liabilities: Derivative instruments 167,065 5,707 172,772 Noncurrent derivative instruments 30,787 26,670 57,457 Total liabilities 197,852 32,377 230,229 Net derivative liability $ (202,497 ) $ (23,506 ) $ (226,003 ) December 31, 2017 (in thousands) Level 2 Level 3 Total Liabilities: Derivative instruments $ 43,241 $ 28,138 $ 71,379 Noncurrent derivative instruments 7,736 1,150 8,886 Total liabilities 50,977 29,288 80,265 Net derivative liability $ (50,977 ) $ (29,288 ) $ (80,265 ) Derivative Instruments: The fair value of Energen’s derivative commodity instruments is determined using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. Our OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which we are able to substantiate fair value through direct or indirect observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps and options priced in reference to NYMEX oil and natural gas prices. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include oil basis and natural gas liquids swaps. We consider the frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While Energen does not have access to the specific assumptions used in its counterparties’ valuation models, Energen maintains communications with its counterparties and discusses pricing practices. Further, we corroborate the fair value of our transactions by comparison of market-based price sources. Level 3 Fair Value Instruments: Energen prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its Level 3 instruments. We estimate that a 10 percent increase or decrease in commodity prices would result in an approximate $0.3 million change in the fair value of open Level 3 derivative contracts and to our results of operations. The table below sets forth a summary of changes in the fair value of Energen’s Level 3 derivative commodity instruments as follows: Three months ended September 30, (in thousands) 2018 2017 Balance at beginning of period $ 90,303 $ 7,645 Realized gains (losses) 22,603 (1,548 ) Unrealized losses relating to instruments held at the reporting date* (109,528 ) (24,112 ) Settlements during period (26,884 ) 398 Balance at end of period $ (23,506 ) $ (17,617 ) Nine months ended September 30, (in thousands) 2018 2017 Balance at beginning of period $ (29,288 ) $ (8,852 ) Realized gains (losses) 21,618 (4,588 ) Unrealized gains (losses) relating to instruments held at the reporting date* 10,064 (7,616 ) Settlements during period (25,900 ) 3,439 Balance at end of period $ (23,506 ) $ (17,617 ) *Includes $88.8 million and $13.0 million in losses related to open contracts held at the reporting date for the three months and nine months ended September 30, 2018, respectively. Includes $23.0 million and $14.2 million in losses related to open contracts held at the reporting date for the three months and nine months ended September 30, 2017, respectively. The table below sets forth quantitative information about Energen’s Level 3 fair value measurements of derivative commodity instruments as follows: (in thousands, except price data) Fair Value as of September 30, 2018 Valuation Technique* Unobservable Input* Range Oil Basis - WTI/WTI 2018 $ 24,790 Discounted Cash Flow Forward Basis ($9.50) - ($9.23) Bbl 2019 $ 7,417 Discounted Cash Flow Forward Basis ($6.76) - ($5.83) Bbl 2020 $ (11,350 ) Discounted Cash Flow Forward Basis ($0.53) - ($0.26) Bbl Natural Gas Liquids 2018 $ (17,870 ) Discounted Cash Flow Forward Basis $1.00 - $1.01 Gal 2019 $ (26,493 ) Discounted Cash Flow Forward Basis $0.89 Gal *Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis in Energen’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values of these assets and liabilities. Asset retirement obligations: Energen’s asset retirement obligations (ARO) primarily relate to the future plugging, abandonment and reclamation of wells and facilities. We recognize a liability for the fair value of the ARO in the periods incurred. See Note 10, Asset Retirement Obligations, for further discussion related to these AROs. These assumptions are classified as Level 3 fair value measurements. Asset Impairments: We monitor our oil and natural gas properties as well as the market and business environments in which we operate and make assessments about events that could result in potential impairment. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected field production performance. If a material event occurs, Energen makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, we will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows and values derived from purchase and sale agreements and similar support as applicable. Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These assumptions are classified as Level 3 fair value measurements. Impairments recognized by Energen during the three months and nine months ended September 30, 2018 and 2017 were immaterial. Financial Instruments not Carried at Fair Value The stated value of cash and cash equivalents, short-term investments, accounts receivable (net of allowance for doubtful accounts), and short-term debt approximates fair value due to the short maturity of the instruments. The Company invested in certain short-term investments that qualify and were classified as cash and cash equivalents. Energen had an allowance for doubtful accounts of $0.6 million at both September 30, 2018 and December 31, 2017, respectively. The fair value of Energen’s long-term debt, including the current portion, was approximately $972.8 million and $798.9 million and had a carrying value of $955.0 million and $785.0 million at September 30, 2018 and December 31, 2017 , respectively. The fair values are based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as a Level 1 fair value measurement and long-term debt is classified as a Level 2 fair value measurement. |
Long-Term Debt
Long-Term Debt | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | LONG-TERM DEBT Long-term debt consisted of the following: (in thousands) September 30, 2018 December 31, 2017 Credit facility, due April 30, 2023 $ 425,000 $ 255,000 4.625% Notes, due September 1, 2021 400,000 400,000 7.32% Medium-term Notes, Series A, due July 28, 2022 20,000 20,000 7.35% Medium-term Notes, Series A, due July 28, 2027 10,000 10,000 7.125% Medium-term Notes, Series B, due February 15, 2028 100,000 100,000 Total 955,000 785,000 Less unamortized debt discount 339 360 Less unamortized debt issuance costs 1,488 1,779 Total $ 953,173 $ 782,861 The aggregate maturities of Energen’s long-term debt outstanding at September 30, 2018 are as follows: (in thousands) Remaining 2018 2019 2020 2021 2022 2023 and thereafter $ — $ — $ — $ 400,000 $ 20,000 $ 535,000 The debt agreements of Energen contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. None of the debt agreements have events of default based on credit ratings. As of September 30, 2018, we were in compliance with our covenants. Under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee, a cross default provision provides that any debt default of more than $10 million by Energen or Energen Resources will constitute an event of default by Energen. The Indenture does not include a restriction on the payment of dividends. Our 4.625% Notes due September 1, 2021 include change in control provisions that may be triggered in a variety of change in control events including, but not limited to, the election to our Board of a majority of directors who are not Continuing Directors. As defined in the notes, a Continuing Director is a director who (1) was a member of the Board on the date of the initial issuance of the notes; or (ii) was nominated for election or elected to the Board with the approval of a majority of the Continuing Directors who were members of the Board at the time of such nomination or election. Credit Facility: On September 2, 2014, Energen entered into a five -year syndicated secured credit facility with domestic and foreign lenders. On November 9, 2017, the borrowing base was increased to $1.7 billion . The aggregate commitments under the credit facility did not change and remained at $1.05 billion . On April 30, 2018, we entered into an amendment to our credit facility which extended the maturity to April 30, 2023, increased the borrowing base to $2.15 billion and increased the aggregate commitments to $1.25 billion . Energen’s obligations under the syndicated credit facility are unconditionally guaranteed by Energen Resources. The credit facility is collateralized by certain assets of Energen and Energen Resources, including a pledge of equity interests in subsidiaries of Energen other than Energen Resources, by mortgages on substantially all of Energen Resources’ oil and natural gas properties and by the pledge of Energen’s and Energen Resources’ deposit accounts, securities accounts and commodity accounts (other than de minimus accounts and excluded accounts). The current credit facility qualifies for classification as long-term debt on the consolidated balance sheets. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other non-cash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0; and to maintain a ratio of consolidated current assets (adjusted to include amounts available for borrowings and exclude non-cash derivative instruments) to consolidated current liabilities (adjusted to exclude maturities under the credit facility and non-cash derivative instruments) greater than or equal to 1.0 to 1.0. We are also bound by covenants which limit our ability to incur additional indebtedness, make certain distributions or alter our corporate structure. Energen may not pay dividends if an event of default exists, if the payment would result in an event of default, or if availability is less than 10 percent of the loan limit under the credit facility. Under the credit facility, a cross default provision provides that any debt default of more than $75 million by Energen or Energen Resources will constitute an event of default by Energen. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes. In addition, the terms of our credit facility limit the amount we can borrow to a borrowing base amount which is determined by our lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria including commodity price outlook. The borrowing base amount is subject to redetermination semi-annually and for event-driven unscheduled redeterminations. Due to the pending Merger of Energen with Diamondback, our scheduled redetermination on October 1, 2018 was postponed to occur on or about January 15, 2019. Completion of the Merger would give rise to an event of default under the terms of the Energen credit facility. To avoid an event of default, Diamondback will need to either obtain waivers or consents from the lenders under the Energen credit facility or the Energen credit facility will need to be repaid in full and terminated in connection with the Merger. Upon an uncured event of default under the credit facility, all amounts owing under the credit facility depending on the nature of the event of default, will automatically or may, upon notice by the administrative agent or the requisite lenders thereunder, become immediately due and payable and the lenders may terminate their commitments under the defaulted facility. The following is a summary of information relating to Energen’s credit facility: (in thousands) September 30, 2018 December 31, 2017 Credit facility outstanding $ 425,000 $ 255,000 Available for borrowings 825,000 795,000 Total borrowing commitments $ 1,250,000 $ 1,050,000 Three months ended Nine months ended (in thousands) 2018 2017 2018 2017 Maximum amount outstanding at any month-end $ 425,000 $ 238,000 $ 425,000 $ 238,000 Average daily amount outstanding $ 386,978 $ 191,810 $ 309,514 $ 80,476 Weighted average interest rates based on: Average daily amount outstanding 3.39 % 2.51 % 3.21 % 2.49 % Amount outstanding at period-end 3.42 % 2.49 % 3.42 % 2.49 % The following is a summary of information relating to Energen’s interest expense: Three months ended Nine months ended (in thousands) 2018 2017 2018 2017 Interest expense $ 11,550 $ 9,985 $ 32,601 $ 28,210 Amortization of debt issuance costs related to long-term debt, including our credit facility* $ 541 $ 830 $ 2,106 $ 2,503 Commitment fees* $ 681 $ 674 $ 2,005 $ 2,236 *Included in Energen’s total interest expense. Energen had no capitalized interest for the three months and nine months ended September 30, 2018 and 2017. For the nine months ended September 30, 2018, Energen paid commitment fees on the unused portion of the available credit facility at a current annual rate of 30 basis points. |
Reconciliation of Earnings Per
Reconciliation of Earnings Per Share (EPS) | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Reconciliation of Earnings Per Share (EPS) | RECONCILIATION OF EARNINGS PER SHARE (EPS) Three months ended Three months ended (in thousands, except per share amounts) September 30, 2018 September 30, 2017 Net Per Share Net Per Share Loss Shares Amount Loss Shares Amount Basic EPS $ (26,572 ) 97,485 $ (0.27 ) $ (18,486 ) 97,198 $ (0.19 ) Effect of dilutive securities Stock options — — Non-vested restricted stock — — Performance share awards — — Diluted EPS $ (26,572 ) 97,485 $ (0.27 ) $ (18,486 ) 97,198 $ (0.19 ) Nine months ended Nine months ended (in thousands, except per share amounts) September 30, 2018 September 30, 2017 Net Per Share Net Per Share Income Shares Amount Income Shares Amount Basic EPS $ 160,617 97,413 $ 1.65 $ 44,398 97,176 $ 0.46 Effect of dilutive securities Stock options 92 25 Non-vested restricted stock 293 284 Performance share awards 215 193 Diluted EPS $ 160,617 98,013 $ 1.64 $ 44,398 97,678 $ 0.45 In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. The Company had 742,290 and 547,793 of excluded shares for the three months ended September 30, 2018 and 2017, respectively. Energen had the following shares that were excluded from the computation of diluted EPS, as inclusion would be anti-dilutive: Three months ended Nine months ended (in thousands) 2018 2017 2018 2017 Stock options 6 512 94 512 Non-vested restricted stock — — 3 — Performance share awards — 139 — 139 |
Stock Compensation
Stock Compensation | 9 Months Ended |
Sep. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock Compensation | STOCK COMPENSATION Stock Incentive Plan Restricted Stock: The Stock Incentive Plan provides for the grant of restricted stock and restricted stock units (restricted stock awards) which have been valued based on the quoted market price of Energen’s common stock at the date of grant. Restricted stock awards vest within three years from the grant date. A summary of restricted stock award activity during the nine months ended September 30, 2018 is presented below: Shares Weighted Average Price Nonvested at December 31, 2017 405,536 $ 44.58 Restricted stock units granted 133,920 52.21 Vested (148,041 ) 56.83 Forfeited (2,716 ) 49.15 Nonvested at September 30, 2018 388,699 $ 42.51 Performance Share Awards: In addition, the Stock Incentive Plan provides for the grant of performance share awards to eligible employees based on predetermined Energen performance criteria at the end of an award period. The Stock Incentive Plan provides that payment of earned performance share awards be made in the form of Energen common stock. Performance share awards are valued using the Monte Carlo model which uses historical volatility and other assumptions to estimate the probability of satisfying the market condition of the award and have a two to three -year vesting period. A summary of performance share award activity during the nine months ended September 30, 2018 is presented below: Shares Weighted Average Price Nonvested at December 31, 2017 400,037 $ 55.65 Granted (three-year vesting period) 158,262 68.08 Vested and paid (112,710 ) 83.94 Forfeited (3,129 ) 60.98 Nonvested at September 30, 2018 442,460 $ 52.85 Stock Repurchase Program During the three months and nine months ended September 30, 2018 , Energen had non-cash purchases of approximately $1.3 million and $8.2 million , respectively, of Energen common stock in conjunction with tax withholdings on other stock compensation and our non-qualified deferred compensation plan. Energen had non-cash purchases of Energen common stock of $0.1 million and $3.3 million during the three months and nine months September 30, 2017. Energen utilized internally generated cash flows in payment of the related tax withholdings. |
Employee Benefit Plans
Employee Benefit Plans | 9 Months Ended |
Sep. 30, 2018 | |
Retirement Benefits [Abstract] | |
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS Postretirement Benefit Plans Energen provides certain postretirement benefits for all eligible employees hired prior to January 1, 2010. These postretirement benefits are available upon retirement as defined by the plan. The components of net periodic postretirement benefit income for Energen’s postretirement benefit plan were as follows: Three months ended (in thousands) 2018 2017 Line item where presented Components of net periodic benefit cost: Service cost $ 16 $ 18 General and administrative Interest cost 53 57 Interest expense Expected long-term return on assets (51 ) (62 ) Other income Prior service cost amortization (113 ) (114 ) Other income Actuarial loss amortization 31 2 Other income Net periodic income $ (64 ) $ (99 ) Nine months ended (in thousands) 2018 2017 Line item where presented Components of net periodic benefit cost: Service cost $ 48 $ 53 General and administrative Interest cost 160 170 Interest expense Expected long-term return on assets (152 ) (187 ) Other income Prior service cost amortization (340 ) (340 ) Other income Actuarial loss amortization 93 7 Other income Net periodic income $ (191 ) $ (297 ) There are no required contributions to the postretirement benefit plan during 2018. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES Legal Matters: Energen and its subsidiaries are, from time to time, parties to various pending or threatened legal proceedings and we have accrued a provision for our estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. We recognize a liability for contingencies, including an estimate of legal costs to be incurred, when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its subsidiaries. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results. On November 4, 2015, Energen Resources filed a quiet title action against Endeavor Energy Resources, L.P. (Endeavor) in the District Court of Howard County, Texas, to remove a cloud on the title to approximately 10,000 acres leased by Energen Resources in that county. Energen Resources believes the cloud on title arises from a prior, unreleased but partially terminated oil and gas lease covering the leased lands. The trial judge ruled with respect to the acreage not held by production that Endeavor’s lease terminated prior to the date Energen Resources entered into its lease. In November 2016, the trial judge entered a final judgment to that effect and that judgment was appealed by Endeavor in April 2017. On October 25, 2018, the Texas Eleventh Circuit Court of Appeals entered a judgment affirming the trial court’s final judgment in favor of Energen Resources. The judgment is subject to rehearing before the Eleventh Circuit Court of Appeals and may be appealed to the Supreme Court of Texas. In connection with the Merger Agreement and the transactions contemplated thereby, two purported class action lawsuits and an individual lawsuit have been filed. Two of the complaints, captioned Melvin Gross v. Energen Corporation, et al., Case No. 2:18-cv-01711-RDP (filed October 17, 2018) and Shiva Stein v. Energen Corporation, et al., Case 2:18-cv-01746-JHE (filed October 22, 2018), were filed in the United States District Court for the Northern District of Alabama. One complaint, captioned Jordan Rosenblatt v. Energen Corporation, et al., Case No. 01-CV-2018-9043232100 (filed October 26, 2018), was filed in the Circuit Court of Jefferson County, Alabama. The complaints assert claims against Energen and its directors. In general, the complaints allege that the defendants violated Sections 14(a) and 20(a) of the Exchange Act because the joint proxy statement/prospectus with respect to the Merger filed with the SEC allegedly misrepresents or omits material information or assert state law breaches of fiduciary duty based on such alleged misrepresentations or omissions. The complaints generally seek, among other things, injunctive relief preventing the consummation of the Merger, rescission in the event the Merger is consummated, and damages. The defendants believe that the actions are without merit. Environmental Matters: Various environmental laws and regulations apply to the operations of Energen and Energen Resources. Historically, the cost of environmental compliance has not materially affected our financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs. During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency regarding the Reef Environmental Site (the Site) in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 for the cleanup of the Site. In 2008, Energen hired a third party to transport approximately 3,000 gallons of non-hazardous wastewater to Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Because it used Reef Environmental only one time for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site. New Mexico Audits: In 2011, Energen Resources received an Order to Perform Restructured Accounting and Pay Additional Royalties (the Order), following an audit performed by the Taxation and Revenue Department (the Department) of the State of New Mexico on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The Order addressed ONRR’s efforts to change accounting and reporting practices, and to unbundle fees charged by third parties that gather, compress and transport natural gas production. ONRR now maintains that all or some of such fees are not deductible. Energen Resources appealed the Order in 2011, and in July 2012, on a motion from ONRR, the Order was remanded. In August 2014, ONRR issued its Revised Order and Energen Resources appealed the Revised Order. In the Revised Order, ONRR ordered that Energen pay additional royalties on production from certain federal leases in the amount of $129,700 . At ONRR’s request, the Revised Order was also remanded in August 2015. On April 15, 2016, ONRR issued its Second Revised Order. The Second Revised Order directs Energen Resources to pay additional royalties of $189,000 , replacing the previous demand of $129,700 . Energen estimates that application of the ONRR position to all of the Company’s federal leases would result in ONRR claims up to approximately $24 million , plus interest and penalties from 2004 forward. ONRR began implementing its unbundling initiative in 2010, but seeks to implement its revisions retroactively, despite the fact that they conflict with previous audits, allowances and industry practice. Energen is contesting the Second Revised Order, the predecessor orders and the findings. Management is unable, at this time, to determine a range of reasonably possible losses, and no amount has been accrued as of September 30, 2018 . Income Taxes: In March 2018, the Company executed a statute of limitation extension for its 2014 federal consolidated income tax return until September 10, 2019. This extension was granted as part of the Company’s ongoing IRS examination of its 2014 and 2016 federal consolidated income tax returns. In June 2018, the Company received notice that the state of Alabama initiated an income tax audit for the 2014 tax year for all subsidiaries. Under SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), provisional amounts must be recorded for certain income tax effects of the 2017 Tax Cuts and Jobs Act for which the accounting under ASC 740 is incomplete, but a reasonable estimate can be determined. Energen recorded a provisional estimate of $0.4 million deferred income tax expense at December 31, 2017 with respect to the IRC Section 162(m) limitation and associated compensation-related deferred tax assets. As of September 30, 2018, the accounting for this income tax effect has been completed and no changes have been made to the provisional estimate recorded at December 31, 2017. |
Exploratory Costs
Exploratory Costs | 9 Months Ended |
Sep. 30, 2018 | |
Extractive Industries [Abstract] | |
Exploratory Costs | EXPLORATORY COSTS Energen capitalizes exploratory drilling costs until a determination is made that the well or project has either found proved reserves or is impaired. After an exploratory well has been drilled and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas quantities can be classified as proved. In those circumstances, Energen continues to capitalize the drilling costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) Energen is making sufficient progress assessing the reserves and the economic and operating viability of the project. Capitalized exploratory drilling costs are presented in proved properties in the consolidated balance sheets. If the exploratory well is determined to be a dry hole, the costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred. The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense: Three months ended Nine months ended (in thousands) 2018 2017 2018 2017 Capitalized exploratory well costs at beginning of period $ 128,234 $ 141,401 $ 132,200 $ 164,996 Additions pending determination of proved reserves 202,743 168,965 578,784 504,668 Reclassifications due to determination of proved reserves (206,031 ) (174,270 ) (586,038 ) (533,568 ) Capitalized exploratory well costs at end of period $ 124,946 $ 136,096 $ 124,946 $ 136,096 The following table sets forth capitalized exploratory well costs: (in thousands) September 30, 2018 December 31, 2017 Exploratory wells in progress (drilling rig not released) $ 17,578 $ 10,879 Capitalized exploratory well costs capitalized for a period of one year or less 107,368 121,321 Total capitalized exploratory well costs $ 124,946 $ 132,200 At September 30, 2018 , Energen had 49 gross exploratory wells either drilling or waiting on results from completion and testing. Substantially all these wells are located in the Permian Basin. As of September 30, 2018 and December 31, 2017, the Company had no wells capitalized greater than a year. |
Asset Retirement Obligations
Asset Retirement Obligations | 9 Months Ended |
Sep. 30, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS Energen’s asset retirement obligations (ARO) primarily relate to the future plugging, abandonment and reclamation of wells and facilities. We recognize a liability for the fair value of the ARO in the periods incurred. The ARO fair value liability is determined by calculating the present value of the estimated future cash outflows, adjusted for inflation, we expect to incur to plug, abandon and reclaim our producing properties at the end of their productive lives, and is recognized on a discounted basis incorporating an estimate of performance risk specific to Energen. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful lives of the related assets. Upon settlement of the liability, Energen may recognize a gain or loss for differences between estimated and actual settlement costs. The following table reflects the components of the change in Energen’s ARO balance: (in thousands) Balance as of December 31, 2017 $ 88,378 Liabilities incurred 1,743 Liabilities settled (103 ) Accretion expense 4,704 Balance as of September 30, 2018 $ 94,722 |
Revenue Recognition
Revenue Recognition | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue Recognition | REVENUE RECOGNITION On January 1, 2018, the Company adopted Accounting Standard Codification (ASC) 606, Revenue from Contracts with Customers, using the modified retrospective method. The adoption of ASC 606 superseded the revenue recognition requirements in ASC 605, Revenue Recognition, and had the following impact on the Company’s results of operations for the three months and nine months ended September 30, 2018: Three months ended September 30, 2018 (in thousands) As reported under ASC 606 As computed under ASC 605 Increase (Decrease) Revenues Oil, natural gas liquids and natural gas sales $ 380,884 $ 382,611 $ (1,727 ) Operating Costs and Expenses Oil, natural gas liquids and natural gas production $ 55,078 $ 56,805 $ (1,727 ) Net Loss $ (26,572 ) $ (26,572 ) $ — Nine months ended September 30, 2018 (in thousands) As reported under ASC 606 As computed under ASC 605 Increase (Decrease) Revenues Oil, natural gas liquids and natural gas sales $ 1,110,317 $ 1,114,892 $ (4,575 ) Operating Costs and Expenses Oil, natural gas liquids and natural gas production $ 165,671 $ 170,246 $ (4,575 ) Net Income $ 160,617 $ 160,617 $ — The changes in revenues and operating costs and expenses are due to certain marketing and transportation costs determined to have occurred after transfer of control to the purchaser. Accordingly, under ASC 606 these marketing and transportation costs are reported as a deduction to revenues. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers, as it applies the practical exemption in accordance with ASC 606. The exemption applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to our remaining performance obligations is not required. Performance obligations for the sale of oil, natural gas liquids and natural gas are satisfied at a point in time because the customer obtains control and title of the asset when the oil, natural gas liquids and natural gas is delivered to the designated sales point. Because the Company's performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company has recognized amounts due from contracts with customers of $150.1 million and $131.9 million at September 30, 2018 and December 31, 2017, respectively, as accounts receivable within the consolidated balance sheets. Revenues are predominantly derived from the sale of oil, natural gas liquids and natural gas. Revenues are recognized when obligations under the terms of a contract with our customers are satisfied; generally, this occurs with the transfer of control of the promised goods or services in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed under ASC 606. Payment is generally made on these oil, natural gas liquids and natural gas sales contracts within 30 days of the end of the calendar month in which product is delivered. The sale of oil, natural gas liquids and natural gas as presented on the consolidated statements of operations represents the Company's share of revenues net of royalties and excludes revenue interests owned by others. When selling oil, natural gas liquids and natural gas on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. Taxes are not included in the transaction costs. In accordance with ASC 606, the Company disaggregates revenues from contracts with customers by product type. The following table summarizes our revenue by major product: Three months ended Nine months ended (in thousands) September 30, 2018 September 30, 2018 Oil $ 316,059 $ 936,136 Natural gas liquids 49,407 125,591 Natural gas 15,418 48,590 Total $ 380,884 $ 1,110,317 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 9 Months Ended |
Sep. 30, 2018 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects. (in thousands) Balance as of December 31, 2017 $ 380 Amounts reclassified from accumulated other comprehensive income (loss) (184 ) Amounts reclassified to accumulated other comprehensive income (loss) from retained earnings due to the stranded tax effects of the 2017 Tax Cuts and Jobs Act 286 Change in accumulated other comprehensive income (loss) 102 Balance as of September 30, 2018 $ 482 The following table provides details of the reclassifications out of accumulated other comprehensive income (loss). Three months ended September 30, 2018 2017 (in thousands) Amounts Reclassified Line Item Where Presented Postretirement plans: Prior service cost $ 113 $ 113 Other income Actuarial losses (31 ) (2 ) Other income Total postretirement plans 82 111 Income tax expense (20 ) (42 ) Total reclassifications for the period, net of tax $ 62 $ 69 Nine months ended September 30, 2018 2017 (in thousands) Amounts Reclassified Line Item Where Presented Postretirement plans: Prior service cost $ 340 $ 341 Other income Actuarial losses (94 ) (7 ) Other income Total postretirement plans 246 334 Income tax expense (62 ) (126 ) Total reclassifications for the period, net of tax $ 184 $ 208 |
Acquisition and Disposition of
Acquisition and Disposition of Properties | 9 Months Ended |
Sep. 30, 2018 | |
Business Combinations [Abstract] | |
Acquisition and Disposition of Properties | ACQUISITION AND DISPOSITION OF PROPERTIES In the first quarter of 2018, Energen completed acreage swaps which delivered 1,922.4 net acres in the Midland Basin to a third party, while it received 1,230.7 net acres in the Delaware Basin along with $0.7 million cash. Energen recognized a pre-tax gain of $33.4 million based on the fair value of the asset surrendered in the acreage trade. In the second quarter of 2018, Energen completed an acreage swap which delivered 240 net acres in the Central Basin platform to a third party, while it received 129.23 net acres in the Midland Basin. Energen recognized a pre-tax gain of $0.7 million based on the fair value of the asset surrendered in the acreage trade. During the third quarter of 2018, Energen completed acreage swaps which delivered 612 net acres in the Midland Basin to a third party, while it received 608 net acres in the Midland Basin. Energen recognized a pre-tax gain of $0.1 million based on the fair value of the assets surrendered in the acreage trades. During the nine months ended September 30, 2018, Energen completed an estimated total of $75.3 million in various purchases and renewals of unproved acquisitions, which are accounted for as asset acquisitions, including approximately $67.7 million in the Delaware Basin and approximately $7.7 million in the Midland Basin for unproved leasehold. During the nine months ended September 30, 2017, Energen completed an estimated $259.3 million in various purchases and renewals of unproved acquisitions, including approximately $208.1 million in the Delaware Basin and approximately $32.4 million in the Midland Basin for unproved leasehold and $18.8 million for mineral purchases in the Delaware Basin. In addition, during the year-to-date September 30, 2018, Energen completed $5.8 million in various proved property acquisitions. |
Recently Issued Accounting Stan
Recently Issued Accounting Standards | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Changes and Error Corrections [Abstract] | |
Recently Issued Accounting Standards | RECENTLY ISSUED ACCOUNTING STANDARDS Recently Adopted Accounting Standards In February 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) No. 2018-02, Reporting Comprehensive Income - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. Consequently, the amendments eliminate the stranded tax effects resulting from the Tax Cuts and Jobs Act and will improve the usefulness of information reported to financial statement users. However, because the amendments only relate to the reclassification of the income tax effects of the Tax Cuts and Jobs Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. The amendment is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years with early adoption permitted. The Company adopted this amendment for its postretirement plans with respect to the disproportionate effect of the Tax Cuts and Jobs Act to clear the effect as of January 1, 2018 that otherwise would not be cleared under current guidance until the postretirement plans have terminated. The Company had an associated $286,000 decrease to retained earnings for the adoption of this amendment. In May 2017, the FASB issued ASU No. 2017-09, Stock Compensation - Scope of Modification Accounting. The amendments in this update provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The amendment is effective for annual periods beginning after December 15, 2017, and interim periods within those annual years. The adoption of this amendment did not impact the Company’s financial position or results of operations. In March 2017, the FASB issued ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments in this update require that the service cost component of net periodic postretirement benefit expense be presented in the same statement of operations line item as other employee compensation costs, while the remaining components of net periodic postretirement benefit expense are to be presented outside operating income. The amendment is effective for annual periods beginning after December 15, 2017, and interim periods within those annual years. The adoption of this amendment did not have a material impact to the Company’s financial position or results of operations. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. This update was effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update was applied using the retrospective transition method. The adoption of this standard did not impact the Company’s consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, which makes a number of changes meant to simplify and improve accounting for share-based payments. The amendment was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The adoption of this ASU effective January 1, 2017 did not have a material impact on our consolidated financial statements. Upon adoption of this new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in our consolidated statements of operations as a discrete item in the reporting period in which they occur. The presentation requirements for cash flows related to employee taxes paid for withheld shares were adjusted retrospectively. These cash outflows, which were historically presented as an operating activity, were classified as a financing activity under taxes paid for shares withheld on the consolidated statements of cash flows. The Company also had an approximate $170,000 decrease to retained earnings associated with our election to recognize forfeitures as they occur. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, ASC 606, which supersedes the revenue recognition requirements in ASC 605, Revenue Recognition. This update is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. The Company adopted this standard as of January 1, 2018 using the modified retrospective approach, which only applies to contracts that were not complete as of the date of initial application. Adoption of this standard did not require an adjustment to beginning retained earnings. See Note 11, Revenue Recognition, for further discussion of the impact of the adoption of ASC 606 on the Company’s consolidated financial statements and the Company’s revenue recognition policies. Recently Issued But Not Yet Adopted Accounting Standards In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). This update requires lessees to recognize a lease liability and a right-of-use (ROU) asset for all leases with a term greater than 12 months on the balance sheet. This standard is not applicable to oil and natural gas leases. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation and disclosure of leasing arrangement by both lessees and lessors. The Company plans to make certain elections allowing the Company not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements until adoption and not to recognize ROU assets or lease liabilities for short-term leases. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842), Targeted Improvements, which would allow entities to apply the transition provisions of the new standard at its adoption date instead of at the earliest comparative period presented in the consolidated financial statements. The ASU will allow entities to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather than in the earliest period presented. The Company will adopt ASU No. 2016-02 on January 1, 2019 using the modified retrospective transition method. In preparation for adoption, we have substantially completed a process to identify a complete population of our leases, including the review of various contracts to identify whether such arrangements convey the right to control the use of an identified asset. Based on our portfolio of leases as of September 30, 2018, we estimate the impact of the adoption to be an increase in lease-related assets and liabilities of approximately $5 million on Energen’s consolidated balance sheet with no material impact on the results of operations, equity or cash flows. The impact to our consolidated financial statements will depend on the population of leases in effect at the date of adoption. We have additionally begun implementing new business processes and developing new controls and the expanded disclosures of our leasing arrangements. |
Recently Issued Accounting St_2
Recently Issued Accounting Standards (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Changes and Error Corrections [Abstract] | |
Revenue | The changes in revenues and operating costs and expenses are due to certain marketing and transportation costs determined to have occurred after transfer of control to the purchaser. Accordingly, under ASC 606 these marketing and transportation costs are reported as a deduction to revenues. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers, as it applies the practical exemption in accordance with ASC 606. The exemption applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to our remaining performance obligations is not required. Performance obligations for the sale of oil, natural gas liquids and natural gas are satisfied at a point in time because the customer obtains control and title of the asset when the oil, natural gas liquids and natural gas is delivered to the designated sales point. Because the Company's performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company has recognized amounts due from contracts with customers of $150.1 million and $131.9 million at September 30, 2018 and December 31, 2017, respectively, as accounts receivable within the consolidated balance sheets. Revenues are predominantly derived from the sale of oil, natural gas liquids and natural gas. Revenues are recognized when obligations under the terms of a contract with our customers are satisfied; generally, this occurs with the transfer of control of the promised goods or services in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed under ASC 606. Payment is generally made on these oil, natural gas liquids and natural gas sales contracts within 30 days of the end of the calendar month in which product is delivered. The sale of oil, natural gas liquids and natural gas as presented on the consolidated statements of operations represents the Company's share of revenues net of royalties and excludes revenue interests owned by others. When selling oil, natural gas liquids and natural gas on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. Taxes are not included in the transaction costs. In accordance with ASC 606, the Company disaggregates revenues from contracts with customers by product type. |
Recently Adopted Accounting Standards and Recently Issued But Not Yet Adopted Accounting Standards | Recently Adopted Accounting Standards In February 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) No. 2018-02, Reporting Comprehensive Income - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. Consequently, the amendments eliminate the stranded tax effects resulting from the Tax Cuts and Jobs Act and will improve the usefulness of information reported to financial statement users. However, because the amendments only relate to the reclassification of the income tax effects of the Tax Cuts and Jobs Act, the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. The amendment is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years with early adoption permitted. The Company adopted this amendment for its postretirement plans with respect to the disproportionate effect of the Tax Cuts and Jobs Act to clear the effect as of January 1, 2018 that otherwise would not be cleared under current guidance until the postretirement plans have terminated. The Company had an associated $286,000 decrease to retained earnings for the adoption of this amendment. In May 2017, the FASB issued ASU No. 2017-09, Stock Compensation - Scope of Modification Accounting. The amendments in this update provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The amendment is effective for annual periods beginning after December 15, 2017, and interim periods within those annual years. The adoption of this amendment did not impact the Company’s financial position or results of operations. In March 2017, the FASB issued ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments in this update require that the service cost component of net periodic postretirement benefit expense be presented in the same statement of operations line item as other employee compensation costs, while the remaining components of net periodic postretirement benefit expense are to be presented outside operating income. The amendment is effective for annual periods beginning after December 15, 2017, and interim periods within those annual years. The adoption of this amendment did not have a material impact to the Company’s financial position or results of operations. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. This update was effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update was applied using the retrospective transition method. The adoption of this standard did not impact the Company’s consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, which makes a number of changes meant to simplify and improve accounting for share-based payments. The amendment was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The adoption of this ASU effective January 1, 2017 did not have a material impact on our consolidated financial statements. Upon adoption of this new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in our consolidated statements of operations as a discrete item in the reporting period in which they occur. The presentation requirements for cash flows related to employee taxes paid for withheld shares were adjusted retrospectively. These cash outflows, which were historically presented as an operating activity, were classified as a financing activity under taxes paid for shares withheld on the consolidated statements of cash flows. The Company also had an approximate $170,000 decrease to retained earnings associated with our election to recognize forfeitures as they occur. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, ASC 606, which supersedes the revenue recognition requirements in ASC 605, Revenue Recognition. This update is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. The Company adopted this standard as of January 1, 2018 using the modified retrospective approach, which only applies to contracts that were not complete as of the date of initial application. Adoption of this standard did not require an adjustment to beginning retained earnings. See Note 11, Revenue Recognition, for further discussion of the impact of the adoption of ASC 606 on the Company’s consolidated financial statements and the Company’s revenue recognition policies. Recently Issued But Not Yet Adopted Accounting Standards In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). This update requires lessees to recognize a lease liability and a right-of-use (ROU) asset for all leases with a term greater than 12 months on the balance sheet. This standard is not applicable to oil and natural gas leases. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation and disclosure of leasing arrangement by both lessees and lessors. The Company plans to make certain elections allowing the Company not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for land easements until adoption and not to recognize ROU assets or lease liabilities for short-term leases. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842), Targeted Improvements, which would allow entities to apply the transition provisions of the new standard at its adoption date instead of at the earliest comparative period presented in the consolidated financial statements. The ASU will allow entities to continue to apply the legacy guidance in Topic 840, including its disclosure requirements, in the comparative periods presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather than in the earliest period presented. The Company will adopt ASU No. 2016-02 on January 1, 2019 using the modified retrospective transition method. In preparation for adoption, we have substantially completed a process to identify a complete population of our leases, including the review of various contracts to identify whether such arrangements convey the right to control the use of an identified asset. Based on our portfolio of leases as of September 30, 2018, we estimate the impact of the adoption to be an increase in lease-related assets and liabilities of approximately $5 million on Energen’s consolidated balance sheet with no material impact on the results of operations, equity or cash flows. The impact to our consolidated financial statements will depend on the population of leases in effect at the date of adoption. We have additionally begun implementing new business processes and developing new controls and the expanded disclosures of our leasing arrangements. |
Derivative Commodity Instrume_2
Derivative Commodity Instruments (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Offsetting Liabilities | The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the consolidated balance sheets: (in thousands) September 30, 2018 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amounts Presented in the Balance Sheets Financial Instruments Cash Collateral Received Net Fair Value Presented in the Balance Sheets Derivatives not designated as hedging instruments Assets Derivative instruments $ 55,455 $ (51,229 ) $ 4,226 $ — $ — $ 4,226 Noncurrent derivative instruments 3,592 (3,592 ) — — — — Total derivative assets 59,047 (54,821 ) 4,226 — — 4,226 Liabilities Derivative instruments 224,001 (51,229 ) 172,772 — — 172,772 Noncurrent derivative instruments 61,049 (3,592 ) 57,457 — — 57,457 Total derivative liabilities 285,050 (54,821 ) 230,229 — — 230,229 Total derivatives $ (226,003 ) $ — $ (226,003 ) $ — $ — $ (226,003 ) (in thousands) December 31, 2017 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amounts Presented in the Balance Sheets Financial Instruments Cash Collateral Received Net Fair Value Presented in the Balance Sheets Derivatives not designated as hedging instruments Assets Derivative instruments $ 1,758 $ (1,758 ) $ — $ — $ — $ — Noncurrent derivative instruments 42 (42 ) — — — — Total derivative assets 1,800 (1,800 ) — — — — Liabilities Derivative instruments 73,137 (1,758 ) 71,379 — — 71,379 Noncurrent derivative instruments 8,928 (42 ) 8,886 — — 8,886 Total derivative liabilities 82,065 (1,800 ) 80,265 — — 80,265 Total derivatives $ (80,265 ) $ — $ (80,265 ) $ — $ — $ (80,265 ) |
Schedule of Offsetting Assets | The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the consolidated balance sheets: (in thousands) September 30, 2018 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amounts Presented in the Balance Sheets Financial Instruments Cash Collateral Received Net Fair Value Presented in the Balance Sheets Derivatives not designated as hedging instruments Assets Derivative instruments $ 55,455 $ (51,229 ) $ 4,226 $ — $ — $ 4,226 Noncurrent derivative instruments 3,592 (3,592 ) — — — — Total derivative assets 59,047 (54,821 ) 4,226 — — 4,226 Liabilities Derivative instruments 224,001 (51,229 ) 172,772 — — 172,772 Noncurrent derivative instruments 61,049 (3,592 ) 57,457 — — 57,457 Total derivative liabilities 285,050 (54,821 ) 230,229 — — 230,229 Total derivatives $ (226,003 ) $ — $ (226,003 ) $ — $ — $ (226,003 ) (in thousands) December 31, 2017 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amounts Presented in the Balance Sheets Financial Instruments Cash Collateral Received Net Fair Value Presented in the Balance Sheets Derivatives not designated as hedging instruments Assets Derivative instruments $ 1,758 $ (1,758 ) $ — $ — $ — $ — Noncurrent derivative instruments 42 (42 ) — — — — Total derivative assets 1,800 (1,800 ) — — — — Liabilities Derivative instruments 73,137 (1,758 ) 71,379 — — 71,379 Noncurrent derivative instruments 8,928 (42 ) 8,886 — — 8,886 Total derivative liabilities 82,065 (1,800 ) 80,265 — — 80,265 Total derivatives $ (80,265 ) $ — $ (80,265 ) $ — $ — $ (80,265 ) |
Effects of Open and Closed Derivative Commodity Instruments Not Designated as Hedging Instruments | The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the consolidated statements of operations: Location on Statement of Operations Three months ended September 30, (in thousands) 2018 2017 Gain (loss) recognized in income on derivatives Gain (loss) on derivative instruments, net $ (154,628 ) $ (57,610 ) Location on Statement of Operations Nine months ended September 30, (in thousands) 2018 2017 Gain (loss) recognized in income on derivatives Gain (loss) on derivative instruments, net $ (188,242 ) 45,037 |
Schedule of Hedging Transactions | As of September 30, 2018, Energen had entered into the following derivative transactions for the remainder of 2018 and subsequent years: Production Period Description Total Hedged Volumes Weighted Average Contract Price Oil 2018 NYMEX Swaps 540 MBbl $60.25 Bbl NYMEX Three-Way Collars 3,375 MBbl Ceiling sold price (call) $60.04 Bbl Floor purchased price (put) $45.47 Bbl Floor sold price (put) $35.47 Bbl 2019 NYMEX Swaps 8,280 MBbl $61.66 Bbl NYMEX Three-Way Collars 5,760 MBbl Ceiling sold price (call) $61.65 Bbl Floor purchased price (put) $45.94 Bbl Floor sold price (put) $35.94 Bbl Oil Basis Differential 2018 WTI/WTI Basis Swaps 3,150 MBbl $(1.46) Bbl 2019 WTI/WTI Basis Swaps 16,560 MBbl $(5.52) Bbl 2020 WTI/WTI Basis Swaps 15,120 MBbl $(1.20) Bbl Natural Gas Liquids 2018 Liquids Swaps 34.0 MMGal $0.61 Gal 2019 Liquids Swaps 115.9 MMGal $0.65 Gal Natural Gas 2018 Basin Specific Swaps - West Texas/Waha 1.8 Bcf $1.70 Mcf 2018 Basin Specific Swaps - Permian 0.9 Bcf $2.56 Mcf WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis: September 30, 2018 (in thousands) Level 2 Level 3 Total Assets: Derivative instruments $ (4,645 ) $ 8,871 $ 4,226 Total assets (4,645 ) 8,871 4,226 Liabilities: Derivative instruments 167,065 5,707 172,772 Noncurrent derivative instruments 30,787 26,670 57,457 Total liabilities 197,852 32,377 230,229 Net derivative liability $ (202,497 ) $ (23,506 ) $ (226,003 ) December 31, 2017 (in thousands) Level 2 Level 3 Total Liabilities: Derivative instruments $ 43,241 $ 28,138 $ 71,379 Noncurrent derivative instruments 7,736 1,150 8,886 Total liabilities 50,977 29,288 80,265 Net derivative liability $ (50,977 ) $ (29,288 ) $ (80,265 ) |
Schedule of Changes in Fair Value of Derivative Commodity Instruments | The table below sets forth a summary of changes in the fair value of Energen’s Level 3 derivative commodity instruments as follows: Three months ended September 30, (in thousands) 2018 2017 Balance at beginning of period $ 90,303 $ 7,645 Realized gains (losses) 22,603 (1,548 ) Unrealized losses relating to instruments held at the reporting date* (109,528 ) (24,112 ) Settlements during period (26,884 ) 398 Balance at end of period $ (23,506 ) $ (17,617 ) Nine months ended September 30, (in thousands) 2018 2017 Balance at beginning of period $ (29,288 ) $ (8,852 ) Realized gains (losses) 21,618 (4,588 ) Unrealized gains (losses) relating to instruments held at the reporting date* 10,064 (7,616 ) Settlements during period (25,900 ) 3,439 Balance at end of period $ (23,506 ) $ (17,617 ) *Includes $88.8 million and $13.0 million in losses related to open contracts held at the reporting date for the three months and nine months ended September 30, 2018, respectively. Includes $23.0 million and $14.2 million in losses related to open contracts held at the reporting date for the three months and nine months ended September 30, 2017, respectively. |
Quantitative Information About Level 3 Fair Value Measurements of Derivative Commodity Instruments | The table below sets forth quantitative information about Energen’s Level 3 fair value measurements of derivative commodity instruments as follows: (in thousands, except price data) Fair Value as of September 30, 2018 Valuation Technique* Unobservable Input* Range Oil Basis - WTI/WTI 2018 $ 24,790 Discounted Cash Flow Forward Basis ($9.50) - ($9.23) Bbl 2019 $ 7,417 Discounted Cash Flow Forward Basis ($6.76) - ($5.83) Bbl 2020 $ (11,350 ) Discounted Cash Flow Forward Basis ($0.53) - ($0.26) Bbl Natural Gas Liquids 2018 $ (17,870 ) Discounted Cash Flow Forward Basis $1.00 - $1.01 Gal 2019 $ (26,493 ) Discounted Cash Flow Forward Basis $0.89 Gal *Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty. |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Long-Term Debt | Long-term debt consisted of the following: (in thousands) September 30, 2018 December 31, 2017 Credit facility, due April 30, 2023 $ 425,000 $ 255,000 4.625% Notes, due September 1, 2021 400,000 400,000 7.32% Medium-term Notes, Series A, due July 28, 2022 20,000 20,000 7.35% Medium-term Notes, Series A, due July 28, 2027 10,000 10,000 7.125% Medium-term Notes, Series B, due February 15, 2028 100,000 100,000 Total 955,000 785,000 Less unamortized debt discount 339 360 Less unamortized debt issuance costs 1,488 1,779 Total $ 953,173 $ 782,861 The following is a summary of information relating to Energen’s interest expense: Three months ended Nine months ended (in thousands) 2018 2017 2018 2017 Interest expense $ 11,550 $ 9,985 $ 32,601 $ 28,210 Amortization of debt issuance costs related to long-term debt, including our credit facility* $ 541 $ 830 $ 2,106 $ 2,503 Commitment fees* $ 681 $ 674 $ 2,005 $ 2,236 *Included in Energen’s total interest expense. Energen had no capitalized interest for the three months and nine months ended September 30, 2018 and 2017. For the nine months ended September 30, 2018, Energen paid commitment fees on the unused portion of the available credit facility at a current annual rate of 30 basis points. |
Schedule of Aggregate Maturities of Long-Term Debt | The aggregate maturities of Energen’s long-term debt outstanding at September 30, 2018 are as follows: (in thousands) Remaining 2018 2019 2020 2021 2022 2023 and thereafter $ — $ — $ — $ 400,000 $ 20,000 $ 535,000 |
Summary of Credit Facilities | The following is a summary of information relating to Energen’s credit facility: (in thousands) September 30, 2018 December 31, 2017 Credit facility outstanding $ 425,000 $ 255,000 Available for borrowings 825,000 795,000 Total borrowing commitments $ 1,250,000 $ 1,050,000 Three months ended Nine months ended (in thousands) 2018 2017 2018 2017 Maximum amount outstanding at any month-end $ 425,000 $ 238,000 $ 425,000 $ 238,000 Average daily amount outstanding $ 386,978 $ 191,810 $ 309,514 $ 80,476 Weighted average interest rates based on: Average daily amount outstanding 3.39 % 2.51 % 3.21 % 2.49 % Amount outstanding at period-end 3.42 % 2.49 % 3.42 % 2.49 % |
Reconciliation of Earnings Pe_2
Reconciliation of Earnings Per Share (EPS) (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share Reconciliation | Three months ended Three months ended (in thousands, except per share amounts) September 30, 2018 September 30, 2017 Net Per Share Net Per Share Loss Shares Amount Loss Shares Amount Basic EPS $ (26,572 ) 97,485 $ (0.27 ) $ (18,486 ) 97,198 $ (0.19 ) Effect of dilutive securities Stock options — — Non-vested restricted stock — — Performance share awards — — Diluted EPS $ (26,572 ) 97,485 $ (0.27 ) $ (18,486 ) 97,198 $ (0.19 ) Nine months ended Nine months ended (in thousands, except per share amounts) September 30, 2018 September 30, 2017 Net Per Share Net Per Share Income Shares Amount Income Shares Amount Basic EPS $ 160,617 97,413 $ 1.65 $ 44,398 97,176 $ 0.46 Effect of dilutive securities Stock options 92 25 Non-vested restricted stock 293 284 Performance share awards 215 193 Diluted EPS $ 160,617 98,013 $ 1.64 $ 44,398 97,678 $ 0.45 |
Schedule of Shares Excluded from the Computation of Diluted EPS | Energen had the following shares that were excluded from the computation of diluted EPS, as inclusion would be anti-dilutive: Three months ended Nine months ended (in thousands) 2018 2017 2018 2017 Stock options 6 512 94 512 Non-vested restricted stock — — 3 — Performance share awards — 139 — 139 |
Stock Compensation (Tables)
Stock Compensation (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Summary of Restricted Stock Award Activity | A summary of restricted stock award activity during the nine months ended September 30, 2018 is presented below: Shares Weighted Average Price Nonvested at December 31, 2017 405,536 $ 44.58 Restricted stock units granted 133,920 52.21 Vested (148,041 ) 56.83 Forfeited (2,716 ) 49.15 Nonvested at September 30, 2018 388,699 $ 42.51 A summary of performance share award activity during the nine months ended September 30, 2018 is presented below: Shares Weighted Average Price Nonvested at December 31, 2017 400,037 $ 55.65 Granted (three-year vesting period) 158,262 68.08 Vested and paid (112,710 ) 83.94 Forfeited (3,129 ) 60.98 Nonvested at September 30, 2018 442,460 $ 52.85 |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Retirement Benefits [Abstract] | |
Schedule of Net Periodic Benefit Costs | The components of net periodic postretirement benefit income for Energen’s postretirement benefit plan were as follows: Three months ended (in thousands) 2018 2017 Line item where presented Components of net periodic benefit cost: Service cost $ 16 $ 18 General and administrative Interest cost 53 57 Interest expense Expected long-term return on assets (51 ) (62 ) Other income Prior service cost amortization (113 ) (114 ) Other income Actuarial loss amortization 31 2 Other income Net periodic income $ (64 ) $ (99 ) Nine months ended (in thousands) 2018 2017 Line item where presented Components of net periodic benefit cost: Service cost $ 48 $ 53 General and administrative Interest cost 160 170 Interest expense Expected long-term return on assets (152 ) (187 ) Other income Prior service cost amortization (340 ) (340 ) Other income Actuarial loss amortization 93 7 Other income Net periodic income $ (191 ) $ (297 ) |
Exploratory Costs (Tables)
Exploratory Costs (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Extractive Industries [Abstract] | |
Schedule of Capitalized Exploratory Wells | The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense: Three months ended Nine months ended (in thousands) 2018 2017 2018 2017 Capitalized exploratory well costs at beginning of period $ 128,234 $ 141,401 $ 132,200 $ 164,996 Additions pending determination of proved reserves 202,743 168,965 578,784 504,668 Reclassifications due to determination of proved reserves (206,031 ) (174,270 ) (586,038 ) (533,568 ) Capitalized exploratory well costs at end of period $ 124,946 $ 136,096 $ 124,946 $ 136,096 The following table sets forth capitalized exploratory well costs: (in thousands) September 30, 2018 December 31, 2017 Exploratory wells in progress (drilling rig not released) $ 17,578 $ 10,879 Capitalized exploratory well costs capitalized for a period of one year or less 107,368 121,321 Total capitalized exploratory well costs $ 124,946 $ 132,200 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Components of the Change in the ARO Balance | The following table reflects the components of the change in Energen’s ARO balance: (in thousands) Balance as of December 31, 2017 $ 88,378 Liabilities incurred 1,743 Liabilities settled (103 ) Accretion expense 4,704 Balance as of September 30, 2018 $ 94,722 |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Adoption of ASC 606 | The adoption of ASC 606 superseded the revenue recognition requirements in ASC 605, Revenue Recognition, and had the following impact on the Company’s results of operations for the three months and nine months ended September 30, 2018: Three months ended September 30, 2018 (in thousands) As reported under ASC 606 As computed under ASC 605 Increase (Decrease) Revenues Oil, natural gas liquids and natural gas sales $ 380,884 $ 382,611 $ (1,727 ) Operating Costs and Expenses Oil, natural gas liquids and natural gas production $ 55,078 $ 56,805 $ (1,727 ) Net Loss $ (26,572 ) $ (26,572 ) $ — Nine months ended September 30, 2018 (in thousands) As reported under ASC 606 As computed under ASC 605 Increase (Decrease) Revenues Oil, natural gas liquids and natural gas sales $ 1,110,317 $ 1,114,892 $ (4,575 ) Operating Costs and Expenses Oil, natural gas liquids and natural gas production $ 165,671 $ 170,246 $ (4,575 ) Net Income $ 160,617 $ 160,617 $ — |
Disaggregation of Revenue by Major Product | The following table summarizes our revenue by major product: Three months ended Nine months ended (in thousands) September 30, 2018 September 30, 2018 Oil $ 316,059 $ 936,136 Natural gas liquids 49,407 125,591 Natural gas 15,418 48,590 Total $ 380,884 $ 1,110,317 |
Accumulated Other Comprehensi_2
Accumulated Other Comprehensive Income (Loss) (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Equity [Abstract] | |
Schedule of Changes in Components of Accumulated Other Comprehensive Income (Loss), Net of Related Income Tax Effects | The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects. (in thousands) Balance as of December 31, 2017 $ 380 Amounts reclassified from accumulated other comprehensive income (loss) (184 ) Amounts reclassified to accumulated other comprehensive income (loss) from retained earnings due to the stranded tax effects of the 2017 Tax Cuts and Jobs Act 286 Change in accumulated other comprehensive income (loss) 102 Balance as of September 30, 2018 $ 482 |
Reclassification Out of Accumulated Other Comprehensive Income (Loss) | The following table provides details of the reclassifications out of accumulated other comprehensive income (loss). Three months ended September 30, 2018 2017 (in thousands) Amounts Reclassified Line Item Where Presented Postretirement plans: Prior service cost $ 113 $ 113 Other income Actuarial losses (31 ) (2 ) Other income Total postretirement plans 82 111 Income tax expense (20 ) (42 ) Total reclassifications for the period, net of tax $ 62 $ 69 Nine months ended September 30, 2018 2017 (in thousands) Amounts Reclassified Line Item Where Presented Postretirement plans: Prior service cost $ 340 $ 341 Other income Actuarial losses (94 ) (7 ) Other income Total postretirement plans 246 334 Income tax expense (62 ) (126 ) Total reclassifications for the period, net of tax $ 184 $ 208 |
Organization and Basis of Pre_2
Organization and Basis of Presentation (Details) - Merger Agreement $ in Millions | Mar. 31, 2019USD ($) | Aug. 14, 2018 |
Diamondback Energy, Inc. | ||
Business Acquisition [Line Items] | ||
Consideration transferred, common stock portion, number of shares converted (in shares) | 0.6442 | |
Scenario, Forecast | ||
Business Acquisition [Line Items] | ||
Termination fee | $ 250 | |
Maximum termination fee | 40 | |
Scenario, Forecast | Diamondback Energy, Inc. | ||
Business Acquisition [Line Items] | ||
Termination fee | 400 | |
Maximum termination fee | $ 25 |
Derivative Commodity Instrume_3
Derivative Commodity Instruments - Offsetting Assets and Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Assets | ||
Gross Amounts Recognized at Fair Value | $ 59,047 | $ 1,800 |
Gross Amounts Offset in the Balance Sheets | (54,821) | (1,800) |
Net Amounts Presented in the Balance Sheets | 4,226 | 0 |
Financial Instruments | 0 | 0 |
Cash Collateral Received | 0 | 0 |
Net Fair Value Presented in the Balance Sheets | 4,226 | 0 |
Liabilities | ||
Gross Amounts Recognized at Fair Value | 285,050 | 82,065 |
Gross Amounts Offset in the Balance Sheets | (54,821) | (1,800) |
Net Amount Presented in the Balance Sheets | 230,229 | 80,265 |
Financial Instruments | 0 | 0 |
Cash Collateral Received | 0 | 0 |
Net Fair Value Presented in the Balance Sheets | 230,229 | 80,265 |
Total Derivatives | (226,003) | (80,265) |
Derivative instruments | ||
Assets | ||
Gross Amounts Recognized at Fair Value | 55,455 | 1,758 |
Gross Amounts Offset in the Balance Sheets | (51,229) | (1,758) |
Net Amounts Presented in the Balance Sheets | 4,226 | 0 |
Financial Instruments | 0 | 0 |
Cash Collateral Received | 0 | 0 |
Net Fair Value Presented in the Balance Sheets | 4,226 | 0 |
Noncurrent derivative instruments | ||
Assets | ||
Gross Amounts Recognized at Fair Value | 3,592 | 42 |
Gross Amounts Offset in the Balance Sheets | (3,592) | (42) |
Net Amounts Presented in the Balance Sheets | 0 | 0 |
Financial Instruments | 0 | 0 |
Cash Collateral Received | 0 | 0 |
Net Fair Value Presented in the Balance Sheets | 0 | 0 |
Derivative instruments | ||
Liabilities | ||
Gross Amounts Recognized at Fair Value | 224,001 | 73,137 |
Gross Amounts Offset in the Balance Sheets | (51,229) | (1,758) |
Net Amount Presented in the Balance Sheets | 172,772 | 71,379 |
Financial Instruments | 0 | 0 |
Cash Collateral Received | 0 | 0 |
Net Fair Value Presented in the Balance Sheets | 172,772 | 71,379 |
Noncurrent derivative instruments | ||
Liabilities | ||
Gross Amounts Recognized at Fair Value | 61,049 | 8,928 |
Gross Amounts Offset in the Balance Sheets | (3,592) | (42) |
Net Amount Presented in the Balance Sheets | 57,457 | 8,886 |
Financial Instruments | 0 | 0 |
Cash Collateral Received | 0 | 0 |
Net Fair Value Presented in the Balance Sheets | $ 57,457 | $ 8,886 |
Derivative Commodity Instrume_4
Derivative Commodity Instruments - Not Designated as Hedging Instruments on the Income Statement (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Gain (loss) recognized in income on derivatives | $ (154,628) | $ (57,610) | $ (188,242) | $ 45,037 |
Gain (loss) on derivative instruments, net | ||||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||||
Gain (loss) recognized in income on derivatives | $ (154,628) | $ (57,610) | $ (188,242) | $ 45,037 |
Derivative Commodity Instrume_5
Derivative Commodity Instruments - Derivative Transactions (Details) gal in Millions | 9 Months Ended |
Sep. 30, 2018mbblgalBcf$ / bbl$ / Mcf$ / gal | |
2018 | NYMEX Swaps | Oil | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | mbbl | 540 |
Weighted Average Contract Price (in dollars per Bbl, Gal and Mcf) | 60.25 |
2018 | NYMEX Three-Way Collars | Oil | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | mbbl | 3,375 |
2018 | Ceiling sold price (call) | Oil | Short | |
Derivatives, Fair Value [Line Items] | |
Ceiling sold price (call) (in dollars per Bbl) | 60.04 |
2018 | Floor Purchased and Sold Price (Put) | Oil | Short | |
Derivatives, Fair Value [Line Items] | |
Floor purchased and sold price (in dollars per Bbl) | 35.47 |
2018 | Floor Purchased and Sold Price (Put) | Oil | Long | |
Derivatives, Fair Value [Line Items] | |
Floor purchased and sold price (in dollars per Bbl) | 45.47 |
2018 | WTI/WTI Basis Swaps | Oil | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | mbbl | 3,150 |
Weighted Average Contract Price (in dollars per Bbl, Gal and Mcf) | (1.46) |
2018 | Liquids Swaps | Natural Gas Liquids | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | gal | 34 |
Weighted Average Contract Price (in dollars per Bbl, Gal and Mcf) | $ / gal | 0.61 |
2018 | Basin Specific Swaps - West Texas/Waha | Natural Gas | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | Bcf | 1.8 |
Weighted Average Contract Price (in dollars per Bbl, Gal and Mcf) | $ / Mcf | 1.70 |
2018 | Basin Specific Swaps - Permian | Natural Gas | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | Bcf | 0.9 |
Weighted Average Contract Price (in dollars per Bbl, Gal and Mcf) | $ / Mcf | 2.56 |
2019 | NYMEX Swaps | Oil | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | mbbl | 8,280 |
Weighted Average Contract Price (in dollars per Bbl, Gal and Mcf) | 61.66 |
2019 | NYMEX Three-Way Collars | Oil | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | mbbl | 5,760 |
2019 | Ceiling sold price (call) | Oil | Short | |
Derivatives, Fair Value [Line Items] | |
Ceiling sold price (call) (in dollars per Bbl) | 61.65 |
2019 | Floor Purchased and Sold Price (Put) | Oil | Short | |
Derivatives, Fair Value [Line Items] | |
Floor purchased and sold price (in dollars per Bbl) | 35.94 |
2019 | Floor Purchased and Sold Price (Put) | Oil | Long | |
Derivatives, Fair Value [Line Items] | |
Floor purchased and sold price (in dollars per Bbl) | 45.94 |
2019 | WTI/WTI Basis Swaps | Oil | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | mbbl | 16,560 |
Weighted Average Contract Price (in dollars per Bbl, Gal and Mcf) | (5.52) |
2019 | Liquids Swaps | Natural Gas Liquids | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | gal | 115.9 |
Weighted Average Contract Price (in dollars per Bbl, Gal and Mcf) | $ / gal | 0.65 |
2020 | WTI/WTI Basis Swaps | Oil | |
Derivatives, Fair Value [Line Items] | |
Total Hedged Volumes (in MBbl, MMGal and Bcf) | mbbl | 15,120 |
Weighted Average Contract Price (in dollars per Bbl, Gal and Mcf) | (1.20) |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Assets: | ||
Derivative instruments | $ 4,226 | $ 0 |
Net Amounts Presented in the Balance Sheets | 4,226 | 0 |
Liabilities: | ||
Net Amount Presented in the Balance Sheets | 230,229 | 80,265 |
Recurring | ||
Assets: | ||
Derivative instruments | 4,226 | |
Net Amounts Presented in the Balance Sheets | 4,226 | |
Liabilities: | ||
Derivative instruments | 172,772 | 71,379 |
Noncurrent derivative instruments | 57,457 | 8,886 |
Net Amount Presented in the Balance Sheets | 230,229 | 80,265 |
Net derivative liability | (226,003) | (80,265) |
Recurring | Level 2 | ||
Assets: | ||
Derivative instruments | (4,645) | |
Net Amounts Presented in the Balance Sheets | (4,645) | |
Liabilities: | ||
Derivative instruments | 167,065 | 43,241 |
Noncurrent derivative instruments | 30,787 | 7,736 |
Net Amount Presented in the Balance Sheets | 197,852 | 50,977 |
Net derivative liability | (202,497) | (50,977) |
Recurring | Level 3 | ||
Assets: | ||
Derivative instruments | 8,871 | |
Net Amounts Presented in the Balance Sheets | 8,871 | |
Liabilities: | ||
Derivative instruments | 5,707 | 28,138 |
Noncurrent derivative instruments | 26,670 | 1,150 |
Net Amount Presented in the Balance Sheets | 32,377 | 29,288 |
Net derivative liability | $ (23,506) | $ (29,288) |
Fair Value Measurements - Narra
Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Allowance for doubtful accounts | $ 600 | $ 600 |
Long-term debt carrying value | 955,000 | 785,000 |
Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Sensitivity analysis of fair value of 10 percent change in commodity prices | 300 | |
Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt fair value | 972,800 | 798,900 |
Reported Value Measurement | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term debt carrying value | $ 955,000 | $ 785,000 |
Fair Value Measurements - Summa
Fair Value Measurements - Summary of Changes of Derivative Commodity Instruments in Fair Value (Details) - Derivative Commodity Instruments - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Balance at beginning of period | $ 90,303 | $ 7,645 | $ (29,288) | $ (8,852) |
Realized gains (losses) | 22,603 | (1,548) | 21,618 | (4,588) |
Unrealized gains (losses) relating to instruments held at the reporting date | (109,528) | (24,112) | 10,064 | (7,616) |
Settlements during period | (26,884) | 398 | (25,900) | 3,439 |
Balance at end of period | (23,506) | (17,617) | (23,506) | (17,617) |
Mark-to-market gain (loss) included in earnings | $ 88,800 | $ 23,000 | $ 13,000 | $ 14,200 |
Fair Value Measurements - Level
Fair Value Measurements - Level 3 Measurements of Derivative Commodity Instruments (Details) $ in Thousands | Sep. 30, 2018USD ($)$ / bbl$ / gal | Dec. 31, 2017USD ($) |
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Derivative asset | $ 4,226 | $ 0 |
Derivative liabilities | (230,229) | $ (80,265) |
Oil Basis - WTI/WTI | 2018 | Discounted Cash Flow Valuation Technique | Level 3 | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Derivative asset | $ 24,790 | |
Oil Basis - WTI/WTI | 2018 | Minimum | Discounted Cash Flow Valuation Technique | Level 3 | Measurement Input, Commodity Forward Price | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Price per barrel (in dollars per Bbl) | $ / bbl | (9.50) | |
Oil Basis - WTI/WTI | 2018 | Maximum | Discounted Cash Flow Valuation Technique | Level 3 | Measurement Input, Commodity Forward Price | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Price per barrel (in dollars per Bbl) | $ / bbl | (9.23) | |
Oil Basis - WTI/WTI | 2019 | Discounted Cash Flow Valuation Technique | Level 3 | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Derivative asset | $ 7,417 | |
Oil Basis - WTI/WTI | 2019 | Minimum | Discounted Cash Flow Valuation Technique | Level 3 | Measurement Input, Commodity Forward Price | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Price per barrel (in dollars per Bbl) | $ / bbl | (6.76) | |
Oil Basis - WTI/WTI | 2019 | Maximum | Discounted Cash Flow Valuation Technique | Level 3 | Measurement Input, Commodity Forward Price | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Price per barrel (in dollars per Bbl) | $ / bbl | (5.83) | |
Oil Basis - WTI/WTI | 2020 | Discounted Cash Flow Valuation Technique | Level 3 | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Derivative asset | $ (11,350) | |
Oil Basis - WTI/WTI | 2020 | Minimum | Discounted Cash Flow Valuation Technique | Level 3 | Measurement Input, Commodity Forward Price | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Price per barrel (in dollars per Bbl) | $ / bbl | (0.53) | |
Oil Basis - WTI/WTI | 2020 | Maximum | Discounted Cash Flow Valuation Technique | Level 3 | Measurement Input, Commodity Forward Price | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Price per barrel (in dollars per Bbl) | $ / bbl | (0.26) | |
Natural Gas Liquids | 2018 | Discounted Cash Flow Valuation Technique | Level 3 | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Derivative liabilities | $ (17,870) | |
Natural Gas Liquids | 2018 | Minimum | Discounted Cash Flow Valuation Technique | Level 3 | Measurement Input, Commodity Forward Price | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Price per gallon (in dollars per gal) | $ / gal | (1) | |
Natural Gas Liquids | 2018 | Maximum | Discounted Cash Flow Valuation Technique | Level 3 | Measurement Input, Commodity Forward Price | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Price per gallon (in dollars per gal) | $ / gal | (1.01) | |
Natural Gas Liquids | 2019 | Discounted Cash Flow Valuation Technique | Level 3 | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Derivative liabilities | $ (26,493) | |
Natural Gas Liquids | 2019 | Discounted Cash Flow Valuation Technique | Level 3 | Measurement Input, Commodity Forward Price | ||
Fair Value Measurement Inputs and Valuation Techniques [Line Items] | ||
Price per gallon (in dollars per gal) | $ / gal | 0.89 |
Long-Term Debt - Schedule of Lo
Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Gross amount | $ 955,000 | $ 785,000 |
Less unamortized debt discount | 339 | 360 |
Less unamortized debt issuance costs | 1,488 | 1,779 |
Total | 953,173 | 782,861 |
Credit facility, due April 30, 2023 | ||
Debt Instrument [Line Items] | ||
Gross amount | 425,000 | 255,000 |
Notes Payable | 4.625% Notes, due September 1, 2021 | ||
Debt Instrument [Line Items] | ||
Gross amount | $ 400,000 | 400,000 |
Stated interest rate | 4.625% | |
Medium-term Notes | 7.32% Medium-term Notes, Series A, due July 28, 2022 | ||
Debt Instrument [Line Items] | ||
Gross amount | $ 20,000 | 20,000 |
Stated interest rate | 7.32% | |
Medium-term Notes | 7.35% Medium-term Notes, Series A, due July 28, 2027 | ||
Debt Instrument [Line Items] | ||
Gross amount | $ 10,000 | 10,000 |
Stated interest rate | 7.35% | |
Medium-term Notes | 7.125% Medium-term Notes, Series B, due February 15, 2028 | ||
Debt Instrument [Line Items] | ||
Gross amount | $ 100,000 | $ 100,000 |
Stated interest rate | 7.125% |
Long-Term Debt - Maturities of
Long-Term Debt - Maturities of Long-Term Debt (Details) $ in Thousands | Sep. 30, 2018USD ($) |
Debt Disclosure [Abstract] | |
Remaining 2,018 | $ 0 |
2,019 | 0 |
2,020 | 0 |
2,021 | 400,000 |
2,022 | 20,000 |
2023 and thereafter | $ 535,000 |
Long-Term Debt - Narrative (Det
Long-Term Debt - Narrative (Details) - USD ($) | Sep. 02, 2014 | Sep. 30, 2018 | Apr. 30, 2018 | Dec. 31, 2017 | Nov. 09, 2017 |
Debt Instrument [Line Items] | |||||
Cross default provision, threshold amount | $ 10,000,000 | ||||
Initial borrowing base | 1,250,000,000 | $ 1,050,000,000 | |||
Credit facility cross default provision, threshold amount (more than) | $ 75,000,000 | ||||
Notes | 4.625% Notes, due September 1, 2021 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 4.625% | ||||
Credit facility | |||||
Debt Instrument [Line Items] | |||||
Initial borrowing base | $ 1,050,000,000 | ||||
Syndicated Credit Facility | Credit Facility, September 2, 2014 | |||||
Debt Instrument [Line Items] | |||||
Term of credit facility | 5 years | ||||
Debt covenant, debt to EBITDAX ratio (less than or equal to) | 4 | ||||
Debt covenant, current assets to current liabilities ratio (greater than or equal to) | 1 | ||||
Loan limit percentage (less than) | 10.00% | ||||
Syndicated Credit Facility | Credit facility | |||||
Debt Instrument [Line Items] | |||||
Maximum borrowing capacity | $ 2,150,000,000 | $ 1,700,000,000 | |||
Initial borrowing base | $ 1,250,000,000 |
Long-Term Debt - Credit Facilit
Long-Term Debt - Credit Facilities (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |||||
Credit facility outstanding | $ 425,000 | $ 425,000 | $ 255,000 | ||
Available for borrowings | 825,000 | 825,000 | 795,000 | ||
Total borrowing commitments | 1,250,000 | 1,250,000 | $ 1,050,000 | ||
Maximum amount outstanding at any month-end | 425,000 | $ 238,000 | 425,000 | $ 238,000 | |
Average daily amount outstanding | $ 386,978 | $ 191,810 | $ 309,514 | $ 80,476 | |
Average daily amount outstanding | 3.39% | 2.51% | 3.21% | 2.49% | |
Amount outstanding at period-end | 3.42% | 2.49% | 3.42% | 2.49% |
Long-Term Debt - Schedule of In
Long-Term Debt - Schedule of Interest Expense Related To Debt (Details) - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Debt Disclosure [Abstract] | ||||
Interest expense | $ 11,550,000 | $ 9,985,000 | $ 32,601,000 | $ 28,210,000 |
Amortization of debt issuance costs related to long-term debt, including our credit facility | 541,000 | 830,000 | 2,106,000 | 2,503,000 |
Commitment fees | 681,000 | 674,000 | 2,005,000 | 2,236,000 |
Interest costs capitalized | $ 0 | $ 0 | $ 0 | $ 0 |
Unused capacity, commitment fee percentage | 0.30% |
Reconciliation of Earnings Pe_3
Reconciliation of Earnings Per Share (EPS) - Earnings Per Share Reconciliation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Net Income (Loss) | $ (26,572) | $ (18,486) | $ 160,617 | $ 44,398 |
Basic EPS, Shares (in shares) | 97,485 | 97,198 | 97,413 | 97,176 |
Basic EPS, Per Share Amount (in dollars per share) | $ (0.27) | $ (0.19) | $ 1.65 | $ 0.46 |
Effect of dilutive securities | ||||
Net Income (Loss) | $ (26,572) | $ (18,486) | $ 160,617 | $ 44,398 |
Diluted EPS, Shares (in shares) | 97,485 | 97,198 | 98,013 | 97,678 |
Diluted EPS, Per Share Amount (in dollars per share) | $ (0.27) | $ (0.19) | $ 1.64 | $ 0.45 |
Stock options | ||||
Effect of dilutive securities | ||||
Effect of dilutive securities (in shares) | 0 | 0 | 92 | 25 |
Non-vested restricted stock | ||||
Effect of dilutive securities | ||||
Effect of dilutive securities (in shares) | 0 | 0 | 293 | 284 |
Performance share awards | ||||
Effect of dilutive securities | ||||
Effect of dilutive securities (in shares) | 0 | 0 | 215 | 193 |
Reconciliation of Earnings Pe_4
Reconciliation of Earnings Per Share (EPS) - Narrative (Details) - shares | 3 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Earnings Per Share [Abstract] | ||
Antidilutive securities excluded from computation of earnings per share (in shares) | 742,290 | 547,793 |
Reconciliation of Earnings Pe_5
Reconciliation of Earnings Per Share (EPS) - Antidilutive Securities (Details) - shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 742,290 | 547,793 | ||
Stock options | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 6,000 | 512,000 | 94,000 | 512,000 |
Non-vested restricted stock | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 0 | 0 | 3,000 | 0 |
Performance share awards | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Antidilutive securities excluded from computation of earnings per share (in shares) | 0 | 139,000 | 0 | 139,000 |
Stock Compensation - Summary of
Stock Compensation - Summary of Stock Option Activity (Details) | 9 Months Ended |
Sep. 30, 2018$ / sharesshares | |
Non-vested restricted stock | |
Shares | |
Beginning balance (in shares) | shares | 405,536 |
Restricted stock units granted (in shares) | shares | 133,920 |
Vested and paid (in shares) | shares | (148,041) |
Forfeited (in shares) | shares | (2,716) |
Ending balance (in shares) | shares | 388,699 |
Weighted Average Price | |
Beginning balance (in dollars per share) | $ / shares | $ 44.58 |
Granted (in dollars per share) | $ / shares | 52.21 |
Vested (in dollars per share) | $ / shares | 56.83 |
Forfeited (in dollars per share) | $ / shares | 49.15 |
Ending balance (in dollars per share) | $ / shares | $ 42.51 |
Performance share awards | |
Shares | |
Beginning balance (in shares) | shares | 400,037 |
Restricted stock units granted (in shares) | shares | 158,262 |
Vested and paid (in shares) | shares | (112,710) |
Forfeited (in shares) | shares | (3,129) |
Ending balance (in shares) | shares | 442,460 |
Weighted Average Price | |
Beginning balance (in dollars per share) | $ / shares | $ 55.65 |
Granted (in dollars per share) | $ / shares | 68.08 |
Vested (in dollars per share) | $ / shares | 83.94 |
Forfeited (in dollars per share) | $ / shares | 60.98 |
Ending balance (in dollars per share) | $ / shares | $ 52.85 |
Stock Compensation - Narrative
Stock Compensation - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Noncash payments for repurchase of common stock | $ 1.3 | $ 0.1 | $ 8.2 | $ 3.3 |
Minimum | Stock Incentive Plan | Performance share awards | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Vesting period | 2 years | |||
Maximum | Stock Incentive Plan | Performance share awards | ||||
Share-based Compensation Arrangement by Share-based Payment Award | ||||
Vesting period | 3 years |
Employee Benefit Plans - Compon
Employee Benefit Plans - Components of Net Periodic Benefit Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Components of net periodic benefit cost: | ||||
Net periodic income | $ (64) | $ (99) | $ (191) | $ (297) |
General and administrative | ||||
Components of net periodic benefit cost: | ||||
Service cost | 16 | 18 | 48 | 53 |
Interest expense | ||||
Components of net periodic benefit cost: | ||||
Interest cost | 53 | 57 | 160 | 170 |
Other income | ||||
Components of net periodic benefit cost: | ||||
Expected long-term return on assets | (51) | (62) | (152) | (187) |
Prior service cost amortization | (113) | (114) | (340) | (340) |
Actuarial loss amortization | $ 31 | $ 2 | $ 93 | $ 7 |
Commitments and Contingencies -
Commitments and Contingencies - Legal and Environmental Matters (Details) gal in Thousands, a in Thousands | Nov. 04, 2015a | Dec. 31, 2008gal |
Sylacauga, Talladega County, Alabama | ||
Long-term Purchase Commitment [Line Items] | ||
Gallons of wastewater transported | gal | 3 | |
Endeavor Energy Resources | Pending Litigation | ||
Long-term Purchase Commitment [Line Items] | ||
Number of acres with cloud on the title | a | 10 |
Commitments and Contingencies_2
Commitments and Contingencies - New Mexico Audits (Details) - USD ($) | Sep. 30, 2018 | Apr. 15, 2016 | Aug. 31, 2014 |
Unfavorable Regulatory Action | |||
Loss Contingencies [Line Items] | |||
Loss contingency, estimate of possible loss | $ 24,000,000 | $ 189,000 | $ 129,700 |
Commitments and Contingencies_3
Commitments and Contingencies - Income Taxes (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Commitments and Contingencies Disclosure [Abstract] | |
Provisional estimate | $ 0.4 |
Exploratory Costs - Exploratory
Exploratory Costs - Exploratory Well Costs (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2018USD ($)well | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($)well | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($)well | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | |||||
Capitalized exploratory well costs at beginning of period | $ 128,234 | $ 141,401 | $ 132,200 | $ 164,996 | $ 164,996 |
Additions pending determination of proved reserves | 202,743 | 168,965 | 578,784 | 504,668 | |
Reclassifications due to determination of proved reserves | (206,031) | (174,270) | (586,038) | (533,568) | |
Capitalized exploratory well costs at end of period | 124,946 | $ 136,096 | 124,946 | $ 136,096 | 132,200 |
Capitalized Costs, Oil and Gas Producing Activities, Gross [Abstract] | |||||
Exploratory wells in progress (drilling rig not released) | 17,578 | 17,578 | 10,879 | ||
Capitalized exploratory well costs capitalized for a period of one year or less | 107,368 | 107,368 | 121,321 | ||
Total capitalized exploratory well costs | $ 124,946 | $ 124,946 | $ 132,200 | ||
Restructuring Cost and Reserve [Line Items] | |||||
Number of wells capitalized | well | 0 | 0 | |||
Permian Basin | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Number of wells in process of drilling | well | 49 | 49 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Balance as of December 31, 2017 | $ 88,378 | |||
Liabilities incurred | 1,743 | |||
Liabilities settled | (103) | |||
Accretion expense | $ 1,604 | $ 1,473 | 4,704 | $ 4,330 |
Balance as of September 30, 2018 | $ 94,722 | $ 94,722 |
Revenue Recognition - Adoption
Revenue Recognition - Adoption of ASC 606 (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues | ||||
Oil, natural gas liquids and natural gas sales | $ 380,884 | $ 249,114 | $ 1,110,317 | $ 644,212 |
Operating Costs and Expenses [Abstract] | ||||
Oil, natural gas liquids and natural gas production | 55,078 | 44,549 | 165,671 | 129,746 |
Net income | (26,572) | $ (18,486) | 160,617 | $ 44,398 |
As computed under ASC 605 | ||||
Revenues | ||||
Oil, natural gas liquids and natural gas sales | 382,611 | 1,114,892 | ||
Operating Costs and Expenses [Abstract] | ||||
Oil, natural gas liquids and natural gas production | 56,805 | 170,246 | ||
Net income | (26,572) | 160,617 | ||
Accounting Standards Update 2014-09 | Increase (Decrease) | ||||
Revenues | ||||
Oil, natural gas liquids and natural gas sales | (1,727) | (4,575) | ||
Operating Costs and Expenses [Abstract] | ||||
Oil, natural gas liquids and natural gas production | (1,727) | (4,575) | ||
Net income | $ 0 | $ 0 |
Revenue Recognition - Narrative
Revenue Recognition - Narrative (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2018 | Dec. 31, 2017 | |
Revenue from Contract with Customer [Abstract] | ||
Recognized amounts due from contracts with customer | $ 150.1 | $ 131.9 |
Payment terms | 30 days |
Revenue Recognition - Disaggreg
Revenue Recognition - Disaggregation of Revenue by Product (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Disaggregation of Revenue [Line Items] | ||||
Oil, natural gas liquids and natural gas sales | $ 380,884 | $ 249,114 | $ 1,110,317 | $ 644,212 |
Oil | ||||
Disaggregation of Revenue [Line Items] | ||||
Oil, natural gas liquids and natural gas sales | 316,059 | 936,136 | ||
Natural gas liquids | ||||
Disaggregation of Revenue [Line Items] | ||||
Oil, natural gas liquids and natural gas sales | 49,407 | 125,591 | ||
Natural gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Oil, natural gas liquids and natural gas sales | $ 15,418 | $ 48,590 |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Loss) - Rollforward of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | Jan. 01, 2018 | Sep. 30, 2018 |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Amounts reclassified from accumulated other comprehensive income (loss) | $ (184) | |
Amounts reclassified to accumulated other comprehensive income (loss) from retained earnings due to the stranded tax effects of the 2017 Tax Cuts and Jobs Act | $ 286 | 286 |
Change in accumulated other comprehensive income (loss) | 102 | |
AOCI Including Portion Attributable to Noncontrolling Interest | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Balance as of December 31, 2017 | $ 380 | 380 |
Balance as of September 30, 2018 | $ 482 |
Accumulated Other Comprehensi_4
Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Income tax expense | $ 5,300 | $ 9,206 | $ (50,695) | $ (26,368) |
Amounts Reclassified | Prior service cost | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Other income | 113 | 113 | 340 | 341 |
Amounts Reclassified | Actuarial losses | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Other income | (31) | (2) | (94) | (7) |
Amounts Reclassified | Adjustments | ||||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | ||||
Total postretirement plans | 82 | 111 | 246 | 334 |
Income tax expense | (20) | (42) | (62) | (126) |
Total reclassifications for the period, net of tax | $ 62 | $ 69 | $ 184 | $ 208 |
Acquisition and Disposition o_2
Acquisition and Disposition of Properties (Details) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018USD ($)a | Jun. 30, 2018USD ($)a | Mar. 31, 2018USD ($)a | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | |
Gas and Oil Acreage [Line Items] | |||||
Payment for unproved leasehold | $ 75.3 | $ 259.3 | |||
Payments for proved properties | 5.8 | ||||
Midland Basin | |||||
Gas and Oil Acreage [Line Items] | |||||
Number of net acres received | a | 608 | 129.23 | |||
Payment for unproved leasehold | 7.7 | 32.4 | |||
Delaware Basin | |||||
Gas and Oil Acreage [Line Items] | |||||
Number of net acres received | a | 1,230.7 | ||||
Cash received in acquiring acreage in unproved leasehold properties | $ 0.7 | ||||
Payment for unproved leasehold | $ 67.7 | 208.1 | |||
Delaware Basin - Mineral Purchases | |||||
Gas and Oil Acreage [Line Items] | |||||
Payment for unproved leasehold | $ 18.8 | ||||
Midland Basin | |||||
Gas and Oil Acreage [Line Items] | |||||
Number of net acres delivered | a | 1,922.4 | ||||
Pre-tax gain on disposal | $ 33.4 | ||||
Central Basin Platform | |||||
Gas and Oil Acreage [Line Items] | |||||
Number of net acres delivered | a | 612 | 240 | |||
Pre-tax gain on disposal | $ 0.1 | $ 0.7 |
Recently Issued Accounting St_3
Recently Issued Accounting Standards (Details) - USD ($) $ in Thousands | Jan. 01, 2018 | Sep. 30, 2018 | Jan. 01, 2019 | Jan. 01, 2017 |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||
Amounts reclassified to accumulated other comprehensive income (loss) from retained earnings due to the stranded tax effects of the 2017 Tax Cuts and Jobs Act | $ 286 | $ 286 | ||
Retained Earnings | Accounting Standards Update 2016-09, Forfeiture Rate Component | ||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||
Cumulative effect of new accounting principle in period of adoption | $ 170 | |||
Scenario, Forecast | Accounting Standards Update 2016-02 [Member] | ||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||||
Operating lease, liability | $ 5,000 | |||
Operating lease, right-of-use asset | $ 5,000 |