Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 05, 2016 | Jun. 30, 2015 | |
Document and Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
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 Common Stock, Shares Outstanding | 78,791,451 | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Public Float | $ 5,283,012,351 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current Assets | ||
Cash and cash equivalents | $ 1,272 | $ 1,852 |
Accounts receivable, net | 63,097 | 157,678 |
Inventories | 11,255 | 14,251 |
Assets held for sale | 93,739 | 395,797 |
Derivative instruments | 56,963 | 322,337 |
Prepayments and other | 20,014 | 27,445 |
Total current assets | 246,340 | 919,360 |
Oil and natural gas properties, successful efforts method | ||
Proved properties | 7,611,118 | 6,903,514 |
Unproved properties | 145,724 | 142,340 |
Less accumulated depreciation, depletion and amortization | 3,454,510 | 1,893,106 |
Oil and natural gas properties, net | 4,302,332 | 5,152,748 |
Other property and equipment, net | 48,358 | 46,389 |
Total property, plant and equipment, net | 4,350,690 | 5,199,137 |
Other postretirement assets | 3,881 | 0 |
Other assets | 12,782 | 19,761 |
TOTAL ASSETS | 4,613,693 | 6,138,258 |
Current Liabilities | ||
Accounts payable | 64,742 | 101,453 |
Accrued taxes | 5,801 | 5,530 |
Accrued wages and benefits | 28,563 | 21,553 |
Accrued capital costs | 79,206 | 207,461 |
Revenue and royalty payable | 60,493 | 72,047 |
Liabilities related to assets held for sale | 12,789 | 24,230 |
Pension liabilities | 15,685 | 24,609 |
Deferred income taxes | 0 | 79,164 |
Derivative instruments | 459 | 988 |
Other | 19,783 | 23,288 |
Total current liabilities | 287,521 | 560,323 |
Long-term debt | 776,087 | 1,038,563 |
Asset retirement obligations | 89,990 | 94,060 |
Pension and other postretirement liabilities | 0 | 15,935 |
Deferred income taxes | 552,369 | 1,000,486 |
Other | 11,866 | 14,287 |
Total liabilities | $ 1,717,833 | $ 2,723,654 |
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; 81,770,161 shares issued at December 31, 2015 and 75,875,711 shares issued at December 31, 2014 | 818 | 759 |
Premium on capital stock | 979,030 | 564,438 |
Retained earnings | 2,046,016 | 2,997,821 |
Accumulated other comprehensive income (loss), net of tax | ||
Pension and postretirement plans | 263 | (22,870) |
Deferred compensation plan | 1,965 | 2,862 |
Treasury stock, at cost; 3,026,350 shares and 2,980,598 shares at December 31, 2015 and 2014, respectively | (132,232) | (128,406) |
Total shareholders’ equity | 2,895,860 | 3,414,604 |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ 4,613,693 | $ 6,138,258 |
CONSOLIDATED BALANCE SHEETS (PA
CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - $ / shares | Dec. 31, 2015 | Dec. 31, 2014 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 5,000,000 | 5,000,000 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 150,000,000 | 150,000,000 |
Common stock, shares issued | 81,770,161 | 75,875,711 |
Treasury stock, shares | 3,026,350 | 2,980,598 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues | |||
Oil, natural gas liquids and natural gas sales | $ 763,261 | $ 1,344,194 | $ 1,256,317 |
Gain (loss) on derivative instruments, net | 115,293 | 335,019 | (50,024) |
Total revenues | 878,554 | 1,679,213 | 1,206,293 |
Operating Costs and Expenses | |||
Oil, natural gas liquids and natural gas production | 228,380 | 274,432 | 257,438 |
Production and ad valorem taxes | 57,380 | 102,063 | 94,103 |
Depreciation, depletion and amortization | 593,789 | 548,564 | 452,876 |
Asset impairment | 1,292,308 | 416,801 | 13,906 |
Exploration | 14,878 | 28,090 | 14,036 |
General and administrative | 149,132 | 122,052 | 113,821 |
Accretion of discount on asset retirement obligations | 7,108 | 7,608 | 6,995 |
(Gain) loss on sale of assets and other, net | (26,570) | 2,642 | 981 |
Total operating costs and expenses | 2,316,405 | 1,502,252 | 954,156 |
Operating Income (Loss) | (1,437,851) | 176,961 | 252,137 |
Other Income (Expense) | |||
Interest expense | (43,108) | (37,771) | (39,736) |
Other income | 223 | 1,181 | 3,803 |
Total other expense | (42,885) | (36,590) | (35,933) |
Income (Loss) From Continuing Operations Before Income Taxes | (1,480,736) | 140,371 | 216,204 |
Income tax expense (benefit) | (535,005) | 40,728 | 74,323 |
Income (Loss) From Continuing Operations | (945,731) | 99,643 | 141,881 |
Discontinued Operations, net of tax | |||
Income from discontinued operations | 0 | 29,292 | 59,079 |
Gain on disposal of discontinued operations, net | 0 | 439,097 | 3,594 |
Income From Discontinued Operations | 0 | 468,389 | 62,673 |
Net Income (Loss) | $ (945,731) | $ 568,032 | $ 204,554 |
Diluted Earnings Per Average Common Share | |||
Continuing operations (in dollars per share) | $ (12.43) | $ 1.36 | $ 1.96 |
Discontinued operations (in dollars per share) | 0 | 6.39 | 0.86 |
Net Income (Loss) (in dollars per share) | (12.43) | 7.75 | 2.82 |
Basic Earnings Per Average Common Share | |||
Continuing operations (in dollars per share) | (12.43) | 1.37 | 1.96 |
Discontinued operations (in dollars per share) | 0 | 6.42 | 0.87 |
Net Income (Loss) (in dollars per share) | $ (12.43) | $ 7.79 | $ 2.83 |
Diluted Average Common Shares Outstanding (in shares) | 76,078,371 | 73,274,631 | 72,470,622 |
Basic Average Common Shares Outstanding (in shares) | 76,078,371 | 72,896,579 | 72,317,865 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Net Income (Loss) | $ (945,731) | $ 568,032 | $ 204,554 |
Cash flow hedges: | |||
Total cash flow hedges | 0 | (12,178) | (32,018) |
Pension and postretirement plans: | |||
Amortization of net benefit obligation at transition, net of tax of $0, $8 and $112, respectively | 0 | 14 | 207 |
Amortization of prior service cost, net of tax of $0, $87 and $90, respectively | 0 | 161 | 167 |
Amortization of net loss, net of tax of $10,676, $7,676 and $4,472, respectively | 19,828 | 14,256 | 8,306 |
Current period change in fair value of pension and postretirement plans, net of tax of $1,779, ($2,722), and $6,237, respectively | 3,305 | (5,056) | 11,582 |
Total pension and postretirement plans | 23,133 | 9,375 | 20,262 |
Comprehensive Income (Loss) | (922,598) | 565,229 | 192,798 |
Commodity contracts | |||
Cash flow hedges: | |||
Current period change in fair value value of derivative instruments, net of tax | 0 | 37 | (10,866) |
Reclassification adjustment for derivative instruments, net of tax | 0 | (13,399) | (22,124) |
Interest rate swap | |||
Cash flow hedges: | |||
Current period change in fair value value of derivative instruments, net of tax | 0 | (298) | (148) |
Reclassification adjustment for derivative instruments, net of tax | $ 0 | $ 1,482 | $ 1,120 |
CONSOLIDATED STATEMENTS OF COM6
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Current period change in fair value of interest rate swap, tax | $ 23 | $ (6,660) | |
Amortization of net obligation at transition, tax | $ 0 | 8 | 112 |
Amortization of prior service cost, tax | 0 | 87 | 90 |
Amortization of net loss, tax | 10,676 | 7,676 | 4,472 |
Current period change in fair value of pension and postretirement plans, tax | 1,779 | (2,722) | 6,237 |
Commodity contracts | |||
Current period change in fair value of interest rate swap, tax | 0 | 23 | (6,660) |
Reclassification adjustment for derivative instruments, tax | 0 | (8,212) | (13,560) |
Interest rate swap | |||
Current period change in fair value of interest rate swap, tax | 0 | (160) | (80) |
Reclassification adjustment for derivative instruments, tax | $ 0 | $ 798 | $ 603 |
CONSOLIDATED STATEMENTS OF SHAR
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands | Total | Common Stock | Premium on Capital Stock | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Deferred Compensation Plan | Treasury Stock |
Beginning balance, shares at Dec. 31, 2012 | 75,067,760 | ||||||
Beginning balance, value at Dec. 31, 2012 | $ 2,676,690 | $ 751 | $ 494,910 | $ 2,314,055 | $ (8,311) | $ 2,774 | $ (127,489) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net income (loss) | 204,554 | 204,554 | |||||
Other comprehensive income (loss) | (11,756) | (11,756) | |||||
Purchase of treasury shares, net (73,206 shares in 2015, 32,768 shares in 2014, 14,766 shares in 2013) | (1,038) | (1,038) | |||||
Purchase and retirement of shares, shares | 0 | ||||||
Shares issued for employee benefit plans, shares | 506,396 | ||||||
Shares issued for employee benefit plans | 18,795 | $ 5 | 18,790 | ||||
Deferred compensation obligation | 0 | 485 | (485) | ||||
Stock-based compensation | 9,625 | 6,869 | 2,756 | ||||
Tax benefit from employee stock plans | 3,142 | 3,142 | |||||
Cash dividends, per share - ($0.08 in 2015, $0.47 in 2014, $0.58 in 2013) | (41,993) | (41,993) | |||||
Ending balance, shares at Dec. 31, 2013 | 75,574,156 | ||||||
Ending balance, value at Dec. 31, 2013 | 2,858,019 | $ 756 | 523,711 | 2,476,616 | (20,067) | 3,259 | (126,256) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net income (loss) | 568,032 | 568,032 | |||||
Other comprehensive income (loss) | (2,803) | (2,803) | |||||
Purchase of treasury shares, net (73,206 shares in 2015, 32,768 shares in 2014, 14,766 shares in 2013) | (2,547) | (2,547) | |||||
Purchase and retirement of shares, shares | (226,839) | ||||||
Purchase and retirement of shares, value | (14,913) | $ (2) | (2,388) | (12,523) | |||
Shares issued for employee benefit plans, shares | 528,394 | ||||||
Shares issued for employee benefit plans | 25,501 | $ 5 | 25,496 | ||||
Deferred compensation obligation | 0 | (397) | 397 | ||||
Stock-based compensation | 11,713 | 11,713 | |||||
Tax benefit from employee stock plans | 5,906 | 5,906 | |||||
Cash dividends, per share - ($0.08 in 2015, $0.47 in 2014, $0.58 in 2013) | $ (34,304) | (34,304) | |||||
Ending balance, shares at Dec. 31, 2014 | 75,875,711 | 75,875,711 | |||||
Ending balance, value at Dec. 31, 2014 | $ 3,414,604 | $ 759 | 564,438 | 2,997,821 | (22,870) | 2,862 | (128,406) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net income (loss) | (945,731) | (945,731) | |||||
Other comprehensive income (loss) | 23,133 | 23,133 | |||||
Purchase of treasury shares, net (73,206 shares in 2015, 32,768 shares in 2014, 14,766 shares in 2013) | (4,723) | (4,723) | |||||
Shares issued for stock offering, shares | 5,700,000 | ||||||
Shares issued for stock offering | 398,620 | $ 57 | 398,563 | ||||
Purchase and retirement of shares, shares | 0 | ||||||
Shares issued for employee benefit plans, shares | 194,450 | ||||||
Shares issued for employee benefit plans | 6,739 | $ 2 | 6,737 | ||||
Deferred compensation obligation | 0 | (897) | 897 | ||||
Stock-based compensation | 8,228 | 8,228 | |||||
Tax benefit from employee stock plans | 1,064 | 1,064 | |||||
Cash dividends, per share - ($0.08 in 2015, $0.47 in 2014, $0.58 in 2013) | $ (6,074) | (6,074) | |||||
Ending balance, shares at Dec. 31, 2015 | 81,770,161 | 81,770,161 | |||||
Ending balance, value at Dec. 31, 2015 | $ 2,895,860 | $ 818 | $ 979,030 | $ 2,046,016 | $ 263 | $ 1,965 | $ (132,232) |
CONSLIDATED STATEMENTS OF SHARE
CONSLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (PARENTHETICAL) - $ / shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Statement of Stockholders' Equity [Abstract] | |||
Common stock, cash dividends per share | $ 0.08 | $ 0.47 | $ 0.58 |
Treasury shares | 73,206 | 32,768 | 14,766 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Operating Activities | |||
Net income (loss) | $ (945,731) | $ 568,032 | $ 204,554 |
Income from discontinued operations | 0 | (468,389) | (62,673) |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 593,789 | 548,564 | 452,876 |
Asset impairment | 1,292,308 | 416,801 | 13,906 |
Accretion of discount on asset retirement obligations | 7,108 | 7,608 | 6,995 |
Deferred income taxes | (539,735) | 302,890 | 118,600 |
Change in derivative fair value | 233,315 | (346,646) | 48,029 |
(Gain) loss on sale of assets | (28,077) | 55 | (89) |
Stock-based compensation expense | 8,028 | 11,332 | 13,621 |
Exploration, including dry holes | 7,097 | 9,325 | 2,102 |
Discontinued operations | 0 | 91,510 | 109,318 |
Other, net | 35,641 | 4,166 | 12,284 |
Net change in: | |||
Accounts receivable | 117,486 | 4,812 | 23,785 |
Inventories | (655) | (3,121) | 10,817 |
Accounts payable | (46,283) | 18,695 | (52,946) |
Accrued taxes/income tax receivable | (4,791) | (488,980) | 4,092 |
Pension and other postretirement benefit contributions | (24,848) | (12,483) | (5,677) |
Other current assets and liabilities | 9,940 | 41,312 | 27,783 |
Net cash provided by operating activities | 714,592 | 705,483 | 927,377 |
Investing Activities | |||
Additions to oil and natural gas properties | (1,154,373) | (1,264,059) | (1,109,365) |
Acquisitions, net of cash acquired | (87,410) | (70,730) | (31,331) |
Proceeds from asset sales and sale of Alabama Gas Corporation | 394,521 | 1,347,725 | 160,986 |
Purchase of short-term investments | (919,000) | (473,000) | (310,000) |
Sale of short-term investments | 919,000 | 473,000 | 310,000 |
Discontinued operations | 0 | (51,850) | (73,341) |
Other, net | 0 | 0 | (559) |
Net cash used in investing activities | (847,262) | (38,914) | (1,053,610) |
Financing Activities | |||
Payment of dividends on common stock | (6,074) | (34,304) | (41,993) |
Issuance of common stock, net | 399,600 | 23,053 | 17,780 |
Purchase and retirement of shares | 0 | (14,913) | 0 |
Issuance of long-term debt | 0 | 0 | 600,000 |
Reduction of long-term debt | 0 | (600,000) | (350,000) |
Payment of debt issuance costs | 0 | (10,901) | (2,740) |
Net change in credit facility | (262,500) | (4,000) | (77,000) |
Tax benefit on stock compensation | 1,064 | 5,906 | 3,142 |
Discontinued operations | 0 | (35,113) | (27,105) |
Net cash provided by (used in) financing activities | 132,090 | (670,272) | 122,084 |
Net change in cash and cash equivalents | (580) | (3,703) | (4,149) |
Cash and cash equivalents at beginning of period | 1,852 | 5,555 | 9,704 |
Cash and cash equivalents at end of period | 1,272 | 1,852 | 5,555 |
Less cash and cash equivalents of discontinued operations at end of period | 0 | 0 | (3,032) |
Cash and cash equivalents | $ 1,272 | $ 1,852 | $ 2,523 |
Organization and Basis of Prese
Organization and Basis of Presentation | 12 Months Ended |
Dec. 31, 2015 | |
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-rich properties and natural gas primarily in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Headquartered in Birmingham, Alabama, our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources). Energen may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held for sale are reported at the lower of the carrying amount or estimated fair value. Certain of these held for sale properties also qualify as discontinued operations. The results of operations of these properties are reclassified and reported as discontinued operations for prior periods. Prior to September 2, 2014, Energen owned Alabama Gas Corporation (Alagasco), which was engaged in the purchase, distribution and sale of natural gas principally in central and north Alabama. On September 2, 2014, Energen completed the transaction to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion , less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion resulting in a pre-tax gain of $726.5 million . This sale had an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness. During 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. See Note 16, Discontinued Operations and Held for Sale Properties, for further information regarding the sale of Alagasco. Liquidity At December 31, 2015, we had $1.3 million of cash on hand and $1.2 billion of committed financing available under our credit facilities. To finance our operations, working capital and capital spending, we expect to use internally generated cash flow from operations supplemented by our existing $1.4 billion five -year syndicated credit facility. In addition, we have classified our remaining San Juan Basin properties as held for sale as at December 31, 2015 and, subsequent to year-end, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale. Energen may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. Access to capital is an integral part of Energen’s business plan. As of December 31, 2015, the Company has $222.5 million outstanding under its revolving credit facilities and $554.0 million outstanding under long term note agreements. While we expect to have ongoing access to our credit facility and capital markets, continued access could be adversely affected by current and future economic and business conditions and possible credit rating downgrades. To the extent current market conditions continue for a prolonged period or worsen, we may be forced to reduce or delay capital and operational expenditures, divest assets, seek additional debt or equity financing, or refinance all or a portion of our debt. Our debt facilities are subject to certain financial and non-financial covenants as discussed in Note 3, Long Term Debt. 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 noncash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0. As of December 31, 2015, we were in compliance with our covenants and expect to maintain compliance during 2016 assuming we are able to execute on our business plan which includes property divestitures and/or access to the capital markets and utilization of our credit facility. However, factors including those outside of our control may prevent us from maintaining compliance with the financial and non-financial covenants, including our total debt to EBITDAX covenant, at future measurement dates in 2016 and beyond. Such factors may include further commodity price declines, lack of liquidity in property and capital markets and our continuing ability to execute on our business plan. The borrowing base on our credit facility is scheduled to be redetermined in April and October of 2016. In the event that we are unable to remain in compliance with our financial and non-financial covenants, we would seek covenant relief at a scheduled redetermination date or at an interim date, as appropriate, during 2016. However, no assurances can be given with respect to such relief. If any such covenant violations are not waived by the lenders such violation would result in an event of default that could trigger acceleration of payment of the amounts outstanding under credit facilities and long term note agreements, which is an aggregate balance outstanding of $776.5 million at December 31, 2015. Additionally, the lenders could refuse to make additional loans under the credit facility, take possession of any collateral, and exercise other remedies or rights that may be available to them, all of which could have a material adverse effect on the business and financial condition of the Company. Workforce Reduction On January 22, 2016, we reduced our workforce as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In connection with the reduction, we will incur a total charge of approximately $3.2 million in the first quarter of 2016 for one-time termination benefits. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. Principles of Consolidation The accompanying consolidated financial statements include Energen and its subsidiaries, principally Energen Resources, after elimination of all significant intercompany transactions in consolidation. In the opinion of management, our consolidated financial statements reflect all adjustments necessary to present fairly 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-year presentation. B. Oil and Natural Gas Operations Property and Related Depletion: Energen follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, natural gas liquids and natural gas reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. 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, we continue 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) we are 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 balance sheets. If the exploratory well is determined to be a dry well, the costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves. Operating Revenues: Energen utilizes the sales method of accounting to recognize oil, natural gas liquids and natural gas production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining proved reserves for such property. Energen had no significant production imbalances at December 31, 2015 and 2014 . Derivative Commodity Instruments: We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen. All derivative transactions are included in operating activities on the consolidated statements of cash flows. The majority of our counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Energen formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the nature of the risk being hedged. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes. Effective June 30, 2013, Energen discontinued the use of cash flow hedge accounting and dedesignated all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen in accumulated other comprehensive income until the forecasted transactions actually occurred. Any subsequent gains or losses are accounted for as mark-to-market and recognized immediately through gain (loss) on derivative instruments, net. As a result of Energen’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 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 . Asset Impairments: Oil and natural gas proved properties periodically are assessed for possible impairment on a field-by-field basis using the estimated undiscounted future cash flows. Energen monitors its oil and natural gas properties as well as the market and business environments in which it operates and makes assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected production performance. If a material event occurs, we make an estimate of undiscounted future cash flows to determine whether the asset is impaired. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. If the asset is impaired, Energen 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. 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 variables can, and often do, differ from the estimates and can have a positive or negative impact on our need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact Energen’s original and ongoing assessments of potential impairment. Energen also may recognize impairments of capitalized costs for unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by exploration activities, changes in economic factors and potential shifts in business strategy employed by management. We consider a combination of geologic and economic factors to evaluate the need for impairment of these costs. Long-Lived Assets and Discontinued Operations: Energen may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held for sale are reported at the lower of the carrying amount or estimated fair value. Certain of these held for sale properties also qualify as discontinued operations and the results of operations of these properties are reclassified and reported as discontinued operations for prior periods. Acquisitions: Energen recognizes all acquisitions at fair value. Energen estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen obtained control of the properties for all acquisitions that qualify as business combinations. The 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). Fair value measurements also utilize assumptions of market participants. Energen uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy. Acquisition related costs are expensed as incurred in general and administrative expense on the consolidated income statements. C. Inventory Inventories consist primarily of tubular goods and other oilfield equipment used in our operations and are stated at the lower of cost or market value, on a weighted average cost basis. D. Fair Value Measurements The carrying values of cash and cash equivalents, accounts payable, accounts receivable (net of allowance), derivative commodity instruments, pension and postretirement plan assets and liabilities and other current assets and liabilities approximate fair value. 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 assumptions 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; 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. 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 directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps 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 basin specific, 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, we maintain communications with our counterparties and discuss pricing practices. Further, we corroborate the fair value of our transactions by comparison of market-based price sources. Energen utilizes a discounted cash flow model in valuing its interest rate derivatives, which are comprised of interest rate swap agreements. The fair value attributable to Energen's interest rate derivative contracts is based on (i) the contracted notional amounts, (ii) active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. Pension and postretirement plan assets include cash and mutual funds. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and Level 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds. E. Income Taxes Energen uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. Energen and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method. F. Accounts Receivable and Allowance for Doubtful Accounts Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in the existing accounts receivable. Energen determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered. Energen had allowance for doubtful accounts of $0.7 million at both December 31, 2015 and 2014, respectively. G. Cash and Cash Equivalents Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value. H. Short-term Investments All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments. As of December 31, 2015 and 2014, Energen had no short-term investments. I. Earnings Per Share (EPS) Energen’s basic earnings per share amounts have been computed based on the weighted average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities. J. Stock-Based Compensation Energen recognizes all share-based compensation awards in general and administrative expense on the consolidated income statement over the requisite vesting period. Equity awards are measured at fair value as of the date of grant. Awards that are settled in cash are classified as liabilities and re-measured at fair value at the end of each reporting period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. We recognize all stock-based compensation expense in the period of grant, subject to certain vesting requirements, for retirement eligible employees. Energen utilizes the long-form method of calculating the available pool of windfall tax benefit. For the years ended December 31, 2015 , 2014 and 2013, we recognized an excess tax benefit of $1.1 million , $5.9 million and $3.1 million , respectively, related to our stock-based compensation. K. Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, physical quantities of proved oil and gas reserves, periodic assessments of oil and gas properties for impairment, Energen’s obligations under its employee pension and compensation plans, the valuation of derivative financial instruments, the allowance for doubtful accounts, tax contingency reserves, legal contingency reserves, asset retirement obligations and self insurance reserves. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates. L. Employee Benefit Plans Plan Termination: In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015 and distributed benefits in December 2015. Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 with the remainder to be paid in the first quarter of 2016. Plan Separation: Effective April 30, 2014, Energen separated its defined benefit non-contributory pension plan and its postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan reflecting the separation of assets and obligations in accordance with ERISA provisions. Energen remeasured the plans using current assumptions. Postretirement Benefit Plans: Energen provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. These postretirement healthcare and life insurance benefits are available upon reaching normal retirement age while working for Energen. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability. For other postretirement plans, certain financial assumptions are used in determining Energen’s projected benefit obligation. These assumptions are examined periodically by Energen, and any required changes are reflected in the subsequent determination of projected benefit obligations. Energen calculates periodic expense for the other postretirement benefit plans on an actuarial basis and the net funded status is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. The benefit obligation is the accumulated postretirement benefit obligation. Energen measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position. For our other postretirement plan, we selected a yield curve comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. Energen considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets. M. Environmental Costs Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-term Debt | LONG-TERM DEBT Long-term debt consisted of the following: (in thousands) December 31, 2015 December 31, 2014 Credit facility $ 222,500 $ 485,000 7.40% Medium-term Notes, Series A, due July 24, 2017 2,000 2,000 7.36% Medium-term Notes, Series A, due July 24, 2017 15,000 15,000 7.23% Medium-term Notes, Series A, due July 28, 2017 2,000 2,000 7.32% Medium-term Notes, Series A, due July 28, 2022 20,000 20,000 7.60% Medium-term Notes, Series A, due July 26, 2027 5,000 5,000 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 4.625% Notes, due September 1, 2021 400,000 400,000 Total 776,500 1,039,000 Less unamortized debt discount 413 437 Total $ 776,087 $ 1,038,563 The aggregate maturities of Energen’s long-term debt as of December 31, 2015 are as follows: Years ending December 31, (in thousands) 2016 2017 2018 2019 2020 Thereafter $— $19,000 $— $222,500 $— $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. Although none of the agreements have events of default based on credit ratings, the interest rates applicable to the syndicated credit facility discussed below may adjust based on credit rating changes during certain periods. 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. Credit Facilities: On September 2, 2014, Energen entered into a five -year syndicated secured credit facility with domestic and foreign lenders. On October 20, 2015, the borrowing base and aggregate commitments were reduced to $1.4 billion in association with the semi-annual redetermination required under the agreement. Energen’s obligations under the $1.4 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. Subject to release of collateral in certain periods upon the achievement of certain investment grade ratings from designated ratings agencies, the credit facility is collateralized by certain assets of Energen, including a pledge of equity interests in subsidiaries of Energen other than Energen Resources, and by mortgages on substantially all of Energen Resources’ oil and natural gas properties. 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 ; 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; and, during certain periods, to maintain a ratio of the net present value of proved reserves of our oil and natural gas properties to consolidated total debt greater than or equal to 1.50 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 during an event of default, 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. 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. Our next scheduled redetermination is April 1, 2016. See Note 1, Organization and Basis of Presentation, for discussion of financial covenants under liquidity. Under Energen’s 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. Upon an uncured event of default under the credit facility, all amounts owing under the credit facility, if any, 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. Energen was in compliance with the terms of its credit facility as of December 31, 2015 . The following is a summary of information relating to Energen’s credit facility: (in thousands) December 31, 2015 December 31, 2014 Credit facility outstanding $ 222,500 $ 485,000 Available for borrowings 1,177,500 1,515,000 Total borrowing commitments $ 1,400,000 $ 2,000,000 Maximum amount outstanding at any month-end $ 685,000 $ 750,000 Average daily amount outstanding $ 358,929 $ 482,166 Weighted average interest rates based on: Average daily amount outstanding 1.60 % 1.46 % Amount outstanding at year-end 1.64 % 1.67 % Energen’s total interest expense was $43.1 million , $37.8 million and $39.7 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Energen’s total interest expense for the years ended December 31, 2015, 2014 and 2013 included amortization of debt issuance costs of $3.3 million , $5.7 million and $2.0 million , respectively. Capitalized interest expense for the year ended December 31, 2015 was not significant. Capitalized interest expense was $0.2 million for both the years ended December 31, 2014 and 2013. At December 31, 2015, Energen paid commitment fees on the unused portion of available credit facilities at a current annual rate of 30 basis points per annum. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES The components of Energen’s income taxes consisted of the following: Years ended December 31, (in thousands) 2015 2014 2013 Taxes estimated to be payable currently: Federal $ 3,972 $ 161,576 $ 23,342 State 758 72,379 2,516 Total current 4,730 233,955 25,858 Taxes deferred: Federal (513,187 ) 144,645 85,950 State (26,548 ) (34,447 ) (2,300 ) Total deferred (539,735 ) 110,198 83,650 Total income tax expense (benefit) $ (535,005 ) $ 344,153 $ 109,508 The components of Energen’s income taxes consisted of the following: Years ended December 31, (in thousands) 2015 2014 2013 Income tax expense (benefit) from continuing operations $ (535,005 ) $ 40,728 $ 74,323 Income tax expense from discontinued operations — 17,928 33,174 Income tax expense from gain on disposal of discontinued operations — 285,497 2,011 Total income tax expense (benefit) $ (535,005 ) $ 344,153 $ 109,508 Energen elected early adoption of Accounting Standards Update (ASU) No. 2015-17, Balance Sheet Classification of Deferred Taxes, prospectively as of December 31, 2015. This update requires that deferred tax liabilities and assets be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of each jurisdiction of an entity be offset and presented as a single amount is not affected by the amendments in this update. We reclassified $14.5 million from a current deferred income tax asset to a noncurrent deferred income tax liability at December 31, 2015. Temporary differences and carryforwards which gave rise to Energen’s deferred tax assets and liabilities were as follows: (in thousands) December 31, 2015 December 31, 2014 Current Noncurrent Current Noncurrent Deferred tax assets: Minimum tax credit $ — $ 44,862 $ — $ 46,338 Allowance for doubtful accounts — 253 244 — Insurance and other accruals — 2,807 2,537 — Compensation accruals — 11,650 11,355 — Pension and other costs — 8,693 — 7,009 Other comprehensive income — — 10,732 1,581 State net operating losses and other carryforwards — 12,577 — 15,392 Other — 962 665 — Total deferred tax assets — 81,804 25,533 70,320 Valuation allowance — (4,235 ) (1,122 ) (2,467 ) Total deferred tax assets — 77,569 24,411 67,853 Deferred tax liabilities: Depreciation and basis differences — 620,629 — 1,057,430 Derivative instruments — 2,838 102,691 — Other comprehensive income — 141 — — Other — 6,330 884 10,909 Total deferred tax liabilities — 629,938 103,575 1,068,339 Net deferred tax liabilities $ — $ (552,369 ) $ (79,164 ) $ (1,000,486 ) Energen files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2015, the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $44.9 million . Energen has a noncurrent deferred tax asset of $8.4 million relating to Energen Resources’ $191.3 million state net operating loss carryforward which will expire beginning in 2027. Energen Resources anticipates generating adequate future taxable income from the reversals of its existing taxable temporary differences to fully realize this benefit. Energen has a full valuation allowance recorded against a noncurrent deferred tax asset of $4.2 million arising from certain state net operating loss and charitable contribution carryforwards. Energen intends to fully reserve this asset until it is determined that it is more likely than not that the asset can be realized through future taxable income in the respective state taxing jurisdictions. No other valuation allowance with respect to deferred taxes is deemed necessary as Energen anticipates generating adequate future taxable income from the reversals of its existing taxable temporary differences to realize the benefits of all remaining deferred tax assets on the consolidated balance sheets. Total income tax expense from continuing operations differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below: Years ended December 31, (in thousands) 2015 2014 2013 Income tax expense (benefit) at statutory federal income tax rate $ (518,258 ) $ 49,130 $ 75,671 Increase (decrease) resulting from: State income taxes, net of federal income tax benefit (14,112 ) 93 1,461 Impact of state law changes (3,075 ) (121 ) (1,966 ) Impact of state deferred tax revaluation on San Juan properties (1,241 ) (8,382 ) — 401(k) stock dividend deduction — (232 ) (449 ) Other, net 1,681 240 (394 ) Total income tax expense (benefit) $ (535,005 ) $ 40,728 $ 74,323 Effective income tax rate (%) 36.13 29.01 34.38 In addition to other changes in state apportionment reflected in the state income taxes, net of federal income tax benefit above, Energen recognized a $1.2 million and an $8.4 million income tax benefit during the 4th quarter of 2015 and 2014, respectively, as a result of re-measuring its state deferred tax liabilities. This re-measurement reflected the state apportionment changes related to certain San Juan Basin properties designated as held for sale as of December 31, 2015, and 2014. A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows: (in thousands) Balance as of December 31, 2012 $ 12,555 Additions based on tax positions related to the current year 4,546 Additions for tax positions of prior years 366 Reductions for tax positions of prior years (46 ) Lapse of statute of limitations (1,435 ) Balance as of December 31, 2013 15,986 Additions based on tax positions related to the current year 3,873 Additions for tax positions of prior years 19 Reductions for tax positions of prior years (954 ) Lapse of statute of limitations (1,394 ) Balance as of December 31, 2014 17,530 Additions based on tax positions related to the current year 2,378 Reductions based on tax positions related to the current year (6,589 ) Reductions for tax positions of prior years (345 ) Lapse of statute of limitations (1,785 ) Balance as of December 31, 2015 $ 11,189 The amount of unrecognized tax benefits at December 31, 2015 that would favorably impact Energen’s effective tax rate, if recognized, is $3 million . Energen recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2015 , 2014 , and 2013 , Energen recognized approximately $2,000 of income, $27,000 of expense and $15,000 of expense for interest (net of tax benefit) and penalties, respectively. Energen had approximately $0.2 million and $0.2 million for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2015 and 2014 , respectively. Energen’s tax returns for years 2012-2014 remain open and subject to examination by the IRS and major state taxing jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations is highly uncertain, Energen does not expect that the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements. |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS Plan Terminations: In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015 and distributed benefits in December 2015. Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 and with the remainder to be paid in the first quarter of 2016. In connection with the termination of these plans, Energen has also classified approximately $3.3 million as of December 31, 2015 of its investment in a Rabbi Trust from other long term assets to prepayments and other assets in the accompanying balance sheets to reflect its intent to utilize these assets to partially fund the estimated payments in the first quarter of 2016. Effective April 30, 2014, Energen separated its defined benefit non-contributory pension plan and its postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan reflecting the separation of assets and obligations in accordance with ERISA provisions. Energen remeasured the plans using current assumptions. Benefit Obligations: The following table sets forth the combined funded status of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in Energen’s consolidated financial statements. As of December 31, (in thousands) 2015 2014 2015 2014 Pension Postretirement Benefits Accumulated benefit obligation $ 15,729 $ 107,669 Benefit obligation: Balance at beginning of period $ 107,669 $ 266,294 $ 11,127 $ 33,224 Service cost — 8,329 392 262 Interest cost 816 5,325 466 716 Actuarial (gain) loss (683 ) 9,078 (1,185 ) 6,385 Plan amendments — — (4,071 ) — Curtailment gain — (8,496 ) — — Transfer in connection with the sale of Alagasco — (124,783 ) — (28,648 ) Termination benefit charge — 2,477 — — Retiree drug subsidy program — — — 48 Benefits paid (92,073 ) (50,555 ) (241 ) (860 ) Balance at end of period $ 15,729 $ 107,669 $ 6,488 $ 11,127 Plan assets: Fair value of plan assets at beginning of period $ 67,542 $ 193,457 $ 10,693 $ 55,459 Actual return (loss) on plan assets (289 ) 5,359 (83 ) (331 ) Employer contributions 24,847 19,164 — 21 Transfer in connection with the sale of Alagasco — (99,883 ) — (43,596 ) Benefits paid (92,073 ) (50,555 ) (241 ) (860 ) Fair value of plan assets at end of period $ 27 $ 67,542 $ 10,369 $ 10,693 Funded status of plans $ (15,702 ) $ (40,127 ) $ 3,881 $ (434 ) Noncurrent assets $ — $ — $ 3,881 $ — Current liabilities (15,702 ) (24,626 ) — — Noncurrent liabilities — (15,501 ) — (434 ) Net asset (liability) recognized $ (15,702 ) $ (40,127 ) $ 3,881 $ (434 ) Amounts recognized to accumulated other comprehensive income: Prior service credit, net of taxes $ — $ — $ (2,646 ) $ — Net actuarial loss, net of taxes 2,179 22,246 205 624 Total accumulated other comprehensive income (loss) $ 2,179 $ 22,246 $ (2,441 ) $ 624 Other investment assets designated for payment of the nonqualified supplemental retirement plans were as follows: December 31, 2015 (in thousands) Level 1 Level 2 Total Cash and cash equivalents $ 3,308 $ — $ 3,308 Total $ 3,308 $ — $ 3,308 December 31, 2014 (in thousands) Level 1 Level 2 Total Fixed income $ — $ 4,255 $ 4,255 Cash and cash equivalents 9,929 — 9,929 Total $ 9,929 $ 4,255 $ 14,184 While intended for payment of the nonqualified supplemental retirement plan benefits, these assets remain subject to the claims of Energen’s creditors and are not recognized in the funded status of the plan. These assets are recorded at fair value and included in prepayments and other and other assets in the consolidated balance sheets. The components of net periodic benefit cost from continuing operations were as follows: Years ended December 31, (in thousands) 2015 2014 2013 Pension Plans Components of net periodic benefit cost: Service cost $ — $ 6,808 $ 5,196 Interest cost 816 4,498 4,496 Expected long-term return on assets — (4,386 ) (5,225 ) Prior service cost amortization — 202 246 Actuarial loss amortization 737 4,995 6,919 Termination benefit charge — 2,477 — Settlement charge 29,767 4,082 161 Curtailment expense (gain) — 254 (4 ) Net periodic expense $ 31,320 $ 18,930 $ 11,789 Postretirement Benefit Plans Components of net periodic benefit cost: Service cost $ 392 $ 253 $ 386 Interest cost 466 661 645 Expected long-term return on assets (457 ) (1,122 ) (787 ) Actuarial gain amortization — (653 ) (28 ) Transition obligation amortization — 44 229 Net periodic (income) expense $ 401 $ (817 ) $ 445 Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows: Years ended December 31, (in thousands) 2015 2014 2013 Pension Plans Net actuarial (gain) loss experienced during the year $ (394 ) $ 10,495 $ (14,138 ) Net actuarial loss recognized as expense (30,478 ) (25,433 ) (8,934 ) Prior service cost recognized as expense — (246 ) (311 ) Curtailment loss — (8,749 ) — Total recognized in other comprehensive income (loss) (30,872 ) (23,933 ) (23,383 ) Postretirement Benefit Plans Net actuarial (gain) loss experienced during the year $ (645 ) $ 7,649 $ (8,057 ) Prior service credit during the year (4,071 ) — — Net actuarial gain recognized as expense — 1,908 550 Transition obligation recognized as expense — (48 ) (283 ) Total recognized in other comprehensive income (loss) $ (4,716 ) $ 9,509 $ (7,790 ) In the year ended December 31, 2015, Energen incurred settlement charges of $27.3 million for the payment of lump sums from the qualified defined benefit pension plans. Also in the first quarter of 2015, Energen incurred a settlement charge of $2.5 million for the payment of lump sums from the non-qualified supplemental retirement plans. During the year ended December 31, 2014, Energen incurred settlement charges of $7.6 million for the payment of lump sums from the qualified defined benefit pension plans of which $3.7 million is included in discontinued operations. Also during 2014, Energen incurred settlement charges of $0.4 million for the payment of lump sums from the non-qualified supplemental retirement plans. In the fourth quarter of 2014, Energen incurred a settlement charge of $1.8 million for the payment of lump sums from the non-qualified supplemental retirement plans which is included in discontinued operations. In the fourth quarter of 2014, Energen recognized a termination benefit charge of $2.5 million to provide for early retirement of certain non-highly compensated employees. In conjunction with the sale of Alagasco, Energen recognized a curtailment loss of $0.3 million in the fourth quarter of 2014. For the year ended December 31, 2013, Energen incurred settlement charges of $0.6 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.2 million was expensed and $0.4 million was recognized as a regulatory asset at Alagasco. In conjunction with the sale of its Black Warrior Basin coalbed methane properties in Alabama, Energen recognized a curtailment gain of $1.2 million in the fourth quarter of 2013. Estimated amounts to be amortized, including settlement charges, from accumulated other comprehensive income into pension cost during 2016 are included in the table below. (in thousands) Amortization of net actuarial loss $ 3,352 Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2016 are included in the table below. (in thousands) Amortization of prior service credit $ (515 ) Energen has a long-term disability plan covering most employees. Energen had expense of $0.2 million for each of the years ended December 31, 2015 , 2014 and 2013 . Assumptions: The weighted average rate assumptions to determine net periodic benefit costs were as follows: Years ended December 31, 2015 2014 2013 Pension Plans Discount rate 0.96 % 3.66 % 3.63 % Expected long-term return on plan assets — % 7.00 % 7.00 % Rate of compensation increase for pay-related plans — % 3.63 % 3.71 % Postretirement Benefit Plans Discount rate 4.25 % 4.88 % 4.36 % Expected long-term return on plan assets 6.20 % 7.00 % 7.00 % Rate of compensation increase — % 3.60 % 3.70 % The pension benefit obligation as of December 31, 2014 represents the present value of the estimated cost of settling the benefit obligation of the plan. For our defined benefit pension plan, we discounted the estimated termination liability using the one year spot rate of 0.70 percent . For the year ended December 31, 2015, the discount rate shown above represents the weighted average for the nonqualified supplemental retirement plan. The discount rate shown below represents the weighted average for both the defined qualified and nonqualified supplemental retirement plans for the year ended December 31, 2014. For the year ended December 31, 2015, the expected long-term return on plan assets no longer applies for our defined benefit pension plan as the assets of the nonqualified supplemental retirement plan are not considered qualifying assets. As the plans were frozen as of December 31, 2014, the rate of compensation increase no longer applies for any of the plans. The weighted average assumptions used to determine the benefit obligations at the measurement date were as follows: Years ended December 31, 2015 2014 Pension Plans Discount rate 3.90 % 0.96 % Postretirement Benefit Plans Discount rate 4.70 % 4.25 % The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows: As of December 31, 2015 2014 Health care cost trend rate assumed for next year 7.75 % 7.25 % Rate to which the cost trend rate is assumed to decline 5.00 % 5.00 % Year that rate reaches ultimate rate 2026 2021 Health care costs trend rates will not have a material impact to the accumulated postretirement benefit obligation due to the separation of assets and obligations of the postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan. Employees remaining at Energen will receive a fixed postretirement benefit. Investment Strategy: For our postretirement benefit plan assets, we continue to employ a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions. Energen seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, commodity or class of investment fund. The Company’s weighted average plan asset allocations by asset category were as follows: Pension Postretirement Benefits As of December 31, Target 2015 2014 Target 2015 2014 Asset category: Equity securities — % — % — % 56 % 56 % 60 % Debt securities — % — % — % 44 % 44 % 40 % Cash and cash equivalents 100 % 100 % 100 % — % — % — % Total 100 % 100 % 100 % 100 % 100 % 100 % Equity securities for postretirement benefits do not include the Company’s common stock. Plan assets included in the funded status of the pension plans were as follows: December 31, 2015 (in thousands) Level 1 Level 2 Total Cash and cash equivalents 27 $ — $ 27 Total $ 27 $ — $ 27 December 31, 2014 (in thousands) Level 1 Level 2 Total Cash and cash equivalents $ 67,542 $ — $ 67,542 Total $ 67,542 $ — $ 67,542 Plan assets included in the funded status of the postretirement benefit plans were as follows: December 31, 2015 (in thousands) Level 1 Level 2 Total United States equities $ 4,185 $ — $ 4,185 Global equities 1,650 — 1,650 Fixed income — 4,534 4,534 Total $ 5,835 $ 4,534 $ 10,369 December 31, 2014 (in thousands) Level 1 Level 2 Total United States equities $ 4,715 $ — $ 4,715 Global equities 1,711 — 1,711 Fixed income — 4,267 4,267 Total $ 6,426 $ 4,267 $ 10,693 Energen had no Level 3 postretirement benefit plan assets. United States equities consists of mutual funds with varying strategies. These funds invest largely in medium to large capitalized companies with exposure blending growth, market-oriented and value styles. Additional fund investments include small capitalization companies, and certain of these funds utilize tax-sensitive management approaches. Global equities are mutual funds that invest in non-United States securities broadly diversified across most developed markets with exposure blending growth, market-oriented and value styles. Fixed income securities are high-quality short-duration securities including investment-grade market sectors with tactical investments in non-investment grade sectors. Cash Flows: The Company expects to make benefit payments, which will be partially funded by the Rabbi Trust, of approximately $14.6 million during 2016 with respect to the termination of the nonqualified supplemental retirement plans. Due to restructuring of our plans, Energen no longer qualifies for benefits related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows: (in thousands) Pension Benefits Postretirement Benefits 2016 $14,606 $198 2017 $117 $213 2018 $114 $245 2019 $110 $258 2020 $107 $289 2021-2025 $472 $1,769 |
Common Stock Plans
Common Stock Plans | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Common Stock Plans | COMMON STOCK PLANS Energen Employee Savings Plan (ESP): In October 2014, Energen’s Board of Directors amended and restated the ESP to make certain benefit design changes effective January 1, 2015. The benefit design changes include an increase in the percentage of Energen match and other contributions. A majority of our employees are eligible to participate in the ESP by electing to contribute a portion of their compensation to the ESP. Energen may match a percentage of the contributions and make these contributions in Energen common stock or in funds for the purchase of Energen common stock. Employees may diversify 100 percent of their ESP Energen stock account into other ESP investment options. The ESP also contains employer supplemental contributions. Effective January 1, 2015, the Company match will no longer be contributed in Energen common stock. Expense associated with Energen contributions to the ESP was $5.7 million , $3.7 million and $3.7 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Stock Incentive Plan: The Stock Incentive Plan provided for the grant of performance share awards and restricted stock units and restricted stock. The Stock Incentive Plan also provided for the grant of non-qualified stock options and incentive stock options to officers and key employees. Energen has typically funded performance share obligations, restricted stock obligations and options through original issue shares and restricted stock through treasury shares. Under the Stock Incentive Plan, established in 1997, 8,600,000 shares of Energen common stock were reserved for issuance, adjusted for stock splits, with 2,294,740 remaining for issuance as of December 31, 2015 . Performance Share Awards: The Stock Incentive Plan provided 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 provided that payment of earned performance share awards be made in the form of Energen common stock. A summary of performance share award activity as of December 31, 2015 , and transactions during the years ended December 31, 2015, 2014 and 2013 is presented below: Stock Incentive Plan Shares Weighted Average Price Nonvested at December 31, 2012 — $ — Granted (two-year vesting period) 86,221 61.14 Granted (three-year vesting period) 82,606 62.96 Forfeited (8,008 ) 60.03 Nonvested at December 31, 2013 160,819 62.13 Granted (two-year vesting period) 937 131.56 Granted (three-year vesting period) 65,309 93.49 Vested and paid (14,097 ) 70.06 Nonvested at December 31, 2014 212,968 71.53 Granted (three-year vesting period) 120,372 83.94 Vested and paid (77,257 ) 61.36 Nonvested at December 31, 2015 256,083 $ 80.43 Energen recorded expense of $6.7 million , $6.2 million and $3.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, for performance share awards with a related deferred income tax benefit of $2.4 million , $2.3 million and $1.4 million . As of December 31, 2015, there was $8.9 million of total unrecognized compensation cost related to performance share awards. These awards have a remaining weighted average requisite service period of 1.66 years. Restricted Stock: In addition, the Stock Incentive Plan provided 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 grant date. A summary of restricted stock award activity as of December 31, 2015 , and transactions during the years ended December 31, 2015 , 2014 and 2013 is presented below: Stock Incentive Plan Awards Weighted Average Price Nonvested at December 31, 2012 11,115 $ 45.24 Restricted stock granted 52,650 52.34 Forfeited (1,247 ) 48.36 Nonvested at December 31, 2013 62,518 51.16 Restricted stock units granted 48,904 71.91 Vested (11,848 ) 65.94 Nonvested at December 31, 2014 99,574 59.60 Restricted stock units granted 99,814 65.15 Vested (14,446 ) 53.20 Nonvested at December 31, 2015 184,942 $ 63.09 Energen recorded expense of $6.0 million , $3.2 million and $1.9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, related to restricted stock awards, with a related deferred income tax benefit of $2.1 million , $1.2 million and $0.7 million , respectively. As of December 31, 2015 , there was $1.9 million of total unrecognized compensation cost related to nonvested restricted stock awards recorded in premium on capital stock. These awards have a remaining requisite service period of 1.75 years. Stock Options: The Stock Incentive Plan provided for the grant of non-qualified stock options, incentive stock options, or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provided for the purchase of Energen common stock at not less than the fair market value on the date the option was granted. The sale or transfer of the shares is limited during certain periods. All outstanding options are incentive or non-qualified, vest within three years from date of grant and expire 10 years from the grant date. A summary of stock option activity as of December 31, 2015 , and transactions during the years ended December 31, 2015 , 2014 and 2013 are presented below: Stock Incentive Plan Shares Weighted Average Exercise Price Outstanding at December 31, 2012 1,648,475 $ 47.58 Granted 137,762 49.22 Exercised (590,119 ) 40.92 Forfeited (5,074 ) 51.85 Outstanding at December 31, 2013 1,191,044 51.06 Granted 110,307 72.55 Exercised (544,280 ) 50.09 Outstanding at December 31, 2014 757,071 54.88 Exercised (23,680 ) 41.42 Outstanding at December 31, 2015 733,391 $ 55.32 Exercisable at December 31, 2013 713,445 $ 49.80 Exercisable at December 31, 2014 454,938 $ 51.88 Exercisable at December 31, 2015 622,156 $ 53.80 Energen uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values: Grant date 4/15/2014 1/22/2014 10/15/2013 1/24/2013 Awards granted 2,439 107,868 3,686 134,076 Fair market value of stock option at grant $32.22 $27.57 $30.53 $16.66 Expected life of award 5.8 years 5.8 years 5.8 years 5.8 years Risk-free interest rate 1.93% 2.06% 1.79% 1.01 % Annualized volatility rate 40.7% 40.7% 40.6% 40.3 % Dividend yield 0.2% 0.8% 0.7% 1.2 % Energen recorded stock option expense of $0.4 million , $2.9 million and $3.4 million during the years ended December 31, 2015 , 2014 and 2013 , respectively, with a related deferred tax benefit of $0.1 million , $1.1 million and $1.3 million , respectively. The total intrinsic value of stock options exercised during the year ended December 31, 2015 , was $0.7 million . During the year ended December 31, 2015 , Energen received cash of $1.0 million from the exercise of stock options. Total intrinsic value for outstanding options as of December 31, 2015 , was $0.3 million and $0.3 million for exercisable options. The fair value of options vested for the year ended December 31, 2015 was $3.7 million . As of December 31, 2015 , there was $0.1 million of unrecognized compensation cost related to outstanding nonvested stock options. The following table summarizes options outstanding as of December 31, 2015 : Stock Incentive Plan Range of Exercise Prices Shares Weighted Average Remaining Contractual Life $46.45 19,990 1.00 year $60.56 48,560 2.00 years $29.79 24,291 3.00 years $46.69 26,481 4.00 years $54.99 104,841 5.00 years $54.11 271,164 6.00 years $48.36 124,071 7.00 years $80.48 3,686 7.79 years $72.39 107,868 8.00 years $79.63 2,439 8.00 years $29.79-$80.48 733,391 5.76 years The weighted average remaining contractual life of currently exercisable stock options is 5.43 years as of December 31, 2015 . Stock Appreciation Rights Plan: The Energen Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Energen common stock. Officers of Energen are not eligible to participate in this Plan. These awards are liability awards which settle in cash and are remeasured each reporting period until settlement. These awards have a three year requisite service period. A summary of stock appreciation rights activity as of December 31, 2015 , and transactions during the years ended December 31, 2015 , 2014 and 2013 are presented below: Stock Appreciation Rights Plan Shares Weighted Average Exercise Price Outstanding at December 31, 2012 653,030 $ 44.14 Granted 88,000 48.36 Exercised/forfeited (363,653 ) 39.66 Outstanding at December 31, 2013 377,377 49.48 Granted 62,749 72.39 Exercised/forfeited (164,976 ) 52.37 Outstanding at December 31, 2014 275,150 52.96 Exercised/forfeited (10,283 ) 55.18 Outstanding at December 31, 2015 264,867 $ 52.88 Energen issued the following awards with stock appreciation rights. Energen uses the Black-Scholes pricing model to calculate the fair values of the rights awarded. On December 19, 2013, we modified certain stock appreciation rights subsequent to the original grant date. For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2015 : Grant date 1/22/2014 1/22/2014 1/24/2013 1/24/2013 1/24/2013 1/26/2011 (modified) (modified) (modified) Awards granted 62,227 522 83,654 768 3,578 182,199 Fair market value of award $5.11 $1.67 $8.30 $5.64 $4.24 $4.80 Expected life of award 4.56 years 2.13 years 3.57 years 2.13 years 1.50 years 2.53 years Risk-free interest rate 1.67% 1.11% 1.43% 1.11% 0.80% 1.23% Annualized volatility rate 33.4% 33.4% 33.4% 33.4% 33.4% 33.4% Dividend yield 0.20% 0.20% 0.20% 0.20% 0.20% 0.20% Grant date 1/26/2011 1/27/2010 1/28/2009 2/4/2008 2/1/2007 (modified) Awards granted 7,785 171,749 305,257 67,093 85,906 Fair market value of award $2.74 $5.95 $13.18 $0.81 $2.16 Expected life of award 1.50 years 2.04 years 1.54 years 1.05 years 0.54 years Risk-free interest rate 0.80% 1.08% 0.82% 0.65% 0.54% Annualized volatility rate 33.4% 33.4% 33.4% 33.4% 33.4% Dividend yield 0.20% 0.20% 0.20% 0.20% 0.20% Income associated with stock appreciation rights of $3.2 million and $0.4 million was recorded for the years ended December 31, 2015 and 2014. Expense associated with stock appreciation rights of $9.9 million was recorded for the year ended 2013. During the year ended December 31, 2015 , the total intrinsic value of stock appreciation rights exercised was $0.1 million . During the year ended December 31, 2015 , Energen paid $0.1 million in settlement of stock appreciation rights. Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provided for the grant of stock equivalent units which may include market conditions. Officers of Energen are not eligible to participate in this Plan. These awards are liability awards which are remeasured each reporting period and settle in cash at completion of the vesting period. Stock equivalent units with service conditions were valued based on Energen’s stock price at the end of the period adjusted to remove the present value of future dividends. A summary of Petrotech unit activity as of December 31, 2015 , and transactions during the years ended December 31, 2015 , 2014 and 2013 are presented below: Petrotech Incentive Plan Shares Outstanding at December 31, 2012 141,243 Granted (three-year vesting period) 92,418 Granted (17 month vesting period) 2,952 Paid (36,792 ) Forfeited (26,529 ) Outstanding at December 31, 2013 173,292 Granted 76,084 Paid (4,431 ) Forfeited (31,075 ) Outstanding at December 31, 2014 213,870 Granted (three-year vesting period) 128,519 Granted (two-year vesting period) 297 Granted (16 month vesting period) 1,648 Paid (78,430 ) Forfeited (22,158 ) Outstanding at December 31, 2015 243,746 Energen recognized expense of $3.0 million , $4.5 million and $6.2 million during 2015 , 2014 and 2013 , respectively, related to these units. 1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allowed officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of Energen’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. Energen has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust’s assets remain subject to the claims of our creditors. Amounts earned under the 1997 Deferred Compensation Plan and invested in Energen common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the consolidated statements of shareholders’ equity. As of December 31, 2015 there were 576,850 shares reserved for issuance from the 1997 Deferred Compensation Plan. 1992 Energen Corporation Directors Stock Plan: In 1992 Energen adopted the Energen Corporation Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Energen common stock. Under the Plan, 11,550 shares, 10,360 shares and 13,500 shares were awarded during the years ended December 31, 2015 , 2014 and 2013 , respectively, leaving 116,374 shares reserved for issuance as of December 31, 2015 . Stock Repurchase Authorization: By resolution adopted October 22, 2014, the Board of Directors authorized Energen to repurchase up to 3,600,000 shares of Energen common stock. The resolution does not have an expiration date and does not limit Energen’s authorization to acquire shares in connection with tax withholdings and payment of exercise price on stock compensation plans. For the year ended December 31, 2014, Energen repurchased and retired 226,839 shares for $14.9 million pursuant to our repurchase authorization. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2015 and 2013 . As of December 31, 2015 , a total of 3,373,161 shares remain authorized for future repurchase. Energen also from time to time acquires shares in connection with participant elections under Energen’s stock compensation plans. For the years ended December 31, 2015 , 2014 and 2013 , Energen acquired 73,126 shares, 32,768 shares and 14,766 shares, respectively, in connection with its stock compensation plans. |
Derivative Commodity Instrument
Derivative Commodity Instruments | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Commodity Instruments | DERIVATIVE COMMODITY INSTRUMENTS The following table details gain (loss) on derivative instruments, net, as follows: Years ended December 31, (in thousands) 2015 2014 2013 Open non-cash mark-to-market gains (losses) on derivative instruments $ (281,752 ) $ 315,445 $ (47,832 ) Closed gains (losses) on derivative instruments 397,045 19,574 (2,192 ) Gain (loss) on derivative instruments, net $ 115,293 $ 335,019 $ (50,024 ) The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets: (in thousands) December 31, 2015 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amount 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 $ 72,563 $ (15,600 ) $ 56,963 $ — $ — $ 56,963 Liabilities Derivative instruments 16,059 (15,600 ) 459 — — 459 Total derivatives $ 56,504 $ — $ 56,504 $ — $ — $ 56,504 (in thousands) December 31, 2014 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amount 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 $ 339,977 $ (17,640 ) $ 322,337 $ — $ — $ 322,337 Liabilities Derivative instruments 18,628 (17,640 ) 988 — — 988 Total derivatives $ 321,349 $ — $ 321,349 $ — $ — $ 321,349 *All derivative instruments were current at December 31, 2015 and 2014. 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 gain position with eleven of our active counterparties and in a net loss position with the remaining one at December 31, 2015 . The largest counterparty net gain positions at December 31, 2015 , Morgan Stanley Capital Group Inc. and BP Corporation North America Inc., constituted approximately $18.1 million , and $10.7 million , respectively, of Energen’s total net gain on fair value of derivatives. The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements: Years ended December 31, (in thousands) Location on Statements of Income 2014 2013 Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $23 and ($6,660) — $ 37 $ (10,866 ) Gain reclassified from accumulated other comprehensive income into income (effective portion) Gain (loss) on derivative instruments, net $ 21,612 $ 34,293 Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing) Gain (loss) on derivative instruments, net $ — $ 835 The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement: Years ended December 31, (in thousands) Location on Statements of Income 2015 2014 2013 Gain (loss) recognized in income on derivatives Gain (loss) on derivative instruments, net $ 115,293 $ 313,408 $ (73,980 ) As of December 31, 2015, Energen entered into the following transactions for 2016 and subsequent years: Production Period Total Hedged Volumes Average Contract Price Description Oil 2016 1,086 MBbl $63.80 Bbl NYMEX Swaps Oil Basis Differential 2016 7,524 MBbl $(1.92) Bbl WTI/WTI Basis Swaps 2016 2,117 MBbl $(1.63) Bbl WTS/WTI Basis Swaps WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing As of December 31, 2015 , the maximum term over which Energen has hedged exposures to the variability of cash flows is through December 31, 2016. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS 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: December 31, 2015 (in thousands) Level 2 Level 3 Total Assets Derivative instruments $ 69,864 $ (12,901 ) $ 56,963 Liabilities Derivative instruments 2,699 (3,158 ) (459 ) Net derivative asset (liability) $ 72,563 $ (16,059 ) $ 56,504 December 31, 2014 (in thousands) Level 2 Level 3 Total Assets Derivative instruments $ 294,865 $ 27,472 $ 322,337 Liabilities Derivative instruments 2,048 (3,036 ) (988 ) Net derivative asset $ 296,913 $ 24,436 $ 321,349 At December 31, 2015, Energen had interest rate swap agreements with a notional value of $66.7 million . The interest rate swaps exchange a variable interest rate for a fixed interest rate of 1.0425 percent. The fair value of our interest rate swap was a $0.2 million and a $0.8 million liability at December 31, 2015 and 2014, respectively, and are classified as Level 2 fair value liabilities. The fair value of our interest rate swaps are recognized on a gross basis in accounts payable on the consolidated balance sheet. 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 $0.1 million change in the fair value of open Level 3 derivative contracts and to the 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: Years ended December 31, (in thousands) 2015 2014 2013 Balance at beginning of period $ 24,436 $ 18,289 $ 89,019 Realized gains 13,145 22,208 55,210 Unrealized gains (losses) relating to instruments held at the reporting date* (40,495 ) 2,981 (71,367 ) Settlements during period (13,145 ) (19,042 ) (54,573 ) Balance at end of period $ (16,059 ) $ 24,436 $ 18,289 *Includes $16.1 million in mark-to-market losses, $20.2 million in mark-to-market gains and $7.6 million in mark-to-market losses for the years ended December 31, 2015, 2014 and 2013, respectively. The tables below set 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 December 31, 2015 Valuation Technique* Unobservable Input* Range Oil Basis - WTI/WTI 2016 $ (13,181 ) Discounted Cash Flow Forward Basis ($0.07 - $0.28) Bbl Oil Basis - WTS/WTI 2016 $ (2,878 ) Discounted Cash Flow Forward Basis ($0.19 - $0.31) Bbl *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. 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 13, Asset Retirement Obligations, for further discussion related to these ARO’s. These assumptions are classified as Level 3 fair value. 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 issues. 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. 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. See Note 14, Asset Impairment, for impairments recognized by Energen during the years ended December 31, 2015, 2014 and 2013. Financial Instruments Not Carried at Fair Value The stated value of cash and cash equivalents, short-term investments, accounts receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. Short-term investments purchased and sold during 2015 of $919 million are not considered readily convertible into cash and accordingly are not classified in cash and cash equivalents. In addition, the Company also invested in certain short-term investments that qualify and were classified as cash and cash equivalents. The fair value of Energen’s long-term debt, including the current portion and notes payable to banks, approximates $690.1 million and $993.7 million and has a carrying value of $776.5 million and $1,039.0 million at December 31, 2015 and 2014, respectively. The fair values are based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value. Concentration of Credit Risk Revenues and related accounts receivable from oil and natural gas operations primarily are generated from the sale of produced oil and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect Energen’s overall exposure to credit risk, either positively or negatively, in that our oil and natural gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen considers the credit quality of its purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The two largest purchasers of Energen’s oil and natural gas, Plains Marketing, LP (Plains) and Shell Trading (US) Company, accounted for approximately 47 percent and 21 percent, respectively, of Energen’s accounts receivable for commodity sales as of December 31, 2015 . Energen’s other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2015 . During the year ended December 31, 2015 , Plains accounted for approximately 33 percent of total revenues, excluding the impact of non-cash mark-to-market open derivatives. All other oil and natural gas purchasers each accounted for less than 10 percent of total revenues for the year ended December 31, 2015 . |
Exploratory Costs
Exploratory Costs | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Exploratory Costs | EXPLORATORY COSTS 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: Years ended December 31, (in thousands) 2015 2014 2013 Capitalized exploratory well costs at beginning of period $ 119,439 $ 57,600 $ 79,791 Additions pending determination of proved reserves 634,908 946,751 421,599 Reclassifications due to determination of proved reserves (650,759 ) (882,254 ) (442,909 ) Exploratory well costs charged to expense — (2,658 ) (881 ) Capitalized exploratory well costs at end of period $ 103,588 $ 119,439 $ 57,600 The following table sets forth capitalized exploratory wells costs: (in thousands) December 31, 2015 December 31, 2014 Exploratory wells in progress (drilling rig not released) $ 1,760 $ 18,781 Capitalized exploratory well costs for a period of one year or less 101,828 100,658 Total capitalized exploratory well costs $ 103,588 $ 119,439 No wells were capitalized for a period greater than one year as of December 31, 2015 and 2014. At December 31, 2015, Energen had 40 gross exploratory wells either drilling or waiting on results from completion and testing. These wells are located in the Permian Basin. |
Reconciliation of Earnings Per
Reconciliation of Earnings Per Share | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Reconciliation of Earnings Per Share | RECONCILIATION OF EARNINGS PER SHARE Years ended December 31, (in thousands, except per share amounts) 2015 2014 2013 Net Loss Shares Per Share Amount Net Income Shares Per Share Amount Net Income Shares Per Share Amount Basic EPS $ (945,731 ) 76,078 $ (12.43 ) $ 568,032 72,897 $ 7.79 $ 204,554 72,318 $ 2.83 Effect of dilutive securities Stock options — 216 112 Non-vested restricted stock — 58 20 Performance share awards — 104 21 Diluted EPS $ (945,731 ) 76,078 $ (12.43 ) $ 568,032 73,275 $ 7.75 $ 204,554 72,471 $ 2.82 In periods of loss, shares that otherwise would have been included in diluted average commons shares outstanding are excluded. Energen had 355,915 of excluded shares for the year ended December 31, 2015. Energen had the following shares that were excluded from the computation of diluted EPS, as inclusion would be anti-dilutive. Years ended December 31, (in thousands) 2015 2014 2013 Stock options 114 114 134 Non-vested restricted stock — 3 7 Performance share awards — 2 4 |
Equity Offering
Equity Offering | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Equity Offering | EQUITY OFFERING During the second quarter of 2015, Energen issued 5,700,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $398.6 million , after deducting offering expenses. Net proceeds from this offering were used to repay borrowings under our credit facility and for general corporate purposes. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES Commitments and Agreements: Under various agreements for third-party gathering, treatment, transportation or other services, Energen is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 5.8 MMBOE through October 2020 . 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 in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party under The Comprehensive Environmental Response, Compensation, and Liability Act 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. Due to its one time use of Reef Environmental for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site. Legal Matters: Energen and its affiliates 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 affiliates. 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 suit against Endeavor Energy Resources. L.P. 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 defendant in the action filed a counterclaim alleging Energen Resources tortiously interfered with a prospective contract. The counterclaim seeks $300 million in damages. Energen Resources believes the counterclaim is without merit, and no amount has been accrued as of December 31, 2015. Energen Resources intends to pursue a favorable ruling in the quiet title action and vigorously defend against the counterclaim. We recently became aware that Energen Resources may be one of multiple defendants in a Petition for Damages to the Cameron Parish Coastal Zone filed by the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron, State of Louisiana alleging violation of Louisiana’s coastal zone management laws. We are in the very preliminary stages of evaluating our exposure, and no amount has been accrued as of December 31, 2015 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 that is now under appeal. In the Revised Order, ONRR has ordered that Energen pay additional royalties on production from certain federal leases in the amount of $129,700 . Energen estimates that application of the Revised Order 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 continues to vigorously contest the Revised Order 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 December 31, 2015 . Lease Obligations: Energen’s total lease payments included as operating lease expense were $23.7 million , $24.1 million and $25.0 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Minimum future rental payments required after 2015 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows: Years Ending December 31, (in thousands) 2016 2017 2018 2019 2020 2021 and thereafter $2,537 $2,574 $2,537 $2,431 $— $— |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS Energen’s asset retirement obligations 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 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, 2012 $ 118,023 Liabilities incurred 2,772 Liabilities settled (5,525 ) Accretion expense (including discontinued operations of $1,197) 8,192 Reclassification associated with held for sale properties* (14,929 ) Balance as of December 31, 2013 108,533 Liabilities incurred 2,266 Liabilities settled (1,543 ) Accretion expense (including discontinued operations of $251) 7,859 Revision in estimated cash flows 692 Reclassification associated with held for sale properties** (23,747 ) Balance as of December 31, 2014 $ 94,060 Liabilities incurred 981 Liabilities settled (686 ) Accretion expense 7,108 Reclassification associated with held for sale properties*** (11,473 ) Balance as of December 31, 2015 $ 89,990 *Asset retirement obligation associated with North Louisiana/East Texas properties. **Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2014. ***Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2015. |
Asset Impairment
Asset Impairment | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Asset Impairment | ASSET IMPAIRMENT Impairments recognized by Energen during the years ended December 31, 2015, 2014 and 2013 are presented below: Years ended December 31, (in thousands) 2015 2014 2013 Continuing operations Permian Basin properties Central Basin Platform $ 484,848 $ — $ — Delaware Basin 607,303 90,594 — Midland Basin — 25,776 — San Juan Basin properties 133,055 230,315 — Permian Basin unproved leasehold properties 29,168 64,361 13,906 San Juan Basin unproved leasehold properties 37,934 5,755 — Total asset impairments from continuing operations 1,292,308 416,801 13,906 Discontinued operations North Louisiana/East Texas oil and natural gas properties — 1,936 29,794 Total asset impairments from discontinued operations — 1,936 29,794 Total asset impairments $ 1,292,308 $ 418,737 $ 43,700 Non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement. Permian Basin: For 2015, Energen recognized non-cash impairment writedowns on certain properties in the Permian Basin of $1,092.2 million to adjust the carrying amount of these properties to their fair value. We estimate future discounted cash flows in determining fair value using commodity assumptions, which are based on the commodity price curve for five years and then escalated at 3 percent through our assumed price cap. During the fourth quarter of 2015, Energen recognized non-cash impairment writedowns of $646.1 million due to commodity price declines and the related impact to our drilling plans. Our commodity price assumptions declined over the third quarter by approximately 12 percent for oil and 6 percent for natural gas in comparable periods. During the third quarter of 2015, Energen recognized non-cash impairment writedowns of $390.2 million due to commodity price declines. Our commodity price assumptions declined over the second quarter by approximately 19 percent for oil and 12 percent for natural gas in comparable periods. During the second quarter of 2015, Energen recognized non-cash impairment writedowns on certain properties in the Central Basin Platform of $51.5 million . Estimated future cash flows were revised due to the receipt of an unsolicited offer for these properties. During the first quarter of 2015, Energen recognized a non-cash impairment writedown of $4.3 million . During the third and fourth quarters of 2014, Energen recognized non-cash impairment writedowns on certain Permian Basin properties in the Midland Basin of $25.8 million and in the Delaware Basin of $90.6 million , respectively, to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Energen recognized unproved leasehold writedowns primarily on Permian Basin oil properties in the Delaware Basin of $29.2 million in 2015. During 2014, Energen recognized unproved leasehold writedowns of $64.4 million . These unproved leasehold writedowns include $55.1 million of leasehold expirations. San Juan Basin: Energen recognized non-cash impairment writedowns on properties in the San Juan Basin of $133.1 million during the fourth quarter of 2015 to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. These remaining properties were designated as held for sale as of December 31, 2015. At December 31, 2015, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 16,930 MBOE. During the third and fourth quarters of 2014, non-cash impairment writedowns of $142.2 million and $88.1 million , respectively, were recognized by Energen on certain natural gas properties in the San Juan Basin to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows in the third quarter and based on direct market data in the fourth quarter as these properties were designated as held for sale as of December 31, 2014. At December 31, 2014, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 69,038 MBOE. During 2015 and 2014, Energen recognized unproved leasehold writedowns on San Juan Basin properties of $37.9 million and $5.8 million , respectively. North Louisiana/East Texas: In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million . The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations. Energen recognized non-cash impairment writedowns on these properties in 2014 of $1.9 million to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2014. Energen also recognized non-cash impairment writedowns on these properties of $29.8 million in 2013. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2013. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment writedowns are classified as Level 3 fair value. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil. Black Warrior Basin: In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million . Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas. |
Acquisition and Disposition of
Acquisition and Disposition of Properties | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Acquisition and Disposition of Properties | ACQUISITION AND DISPOSITION OF PROPERTIES Subsequent to December 31, 2015, Energen classified certain non-core assets in the eastern Delaware Basin as held for sale. Proved reserves associated with these Delaware Basin properties totaled 25,200 MBOE at December 31, 2015. At December 31, 2015, our remaining San Juan Basin properties were classified as held for sale. Proved reserves associated with these San Juan Basin properties totaled 16,930 MBOE at December 31, 2015. On March 31, 2015, Energen completed the sale of the majority of its natural gas assets in the San Juan Basin in New Mexico and Colorado (effective as of January 1, 2015) for an aggregate purchase price of $395 million . The sales proceeds were reduced by purchase price adjustments of approximately $11 million related to the operations of the San Juan Basin properties subsequent to December 31, 2014 and one-time adjustments related primarily to liabilities assumed by the buyer, which resulted in pre-tax proceeds to Energen of approximately $384 million before consideration of transaction costs of approximately $2.8 million . Energen recognized a pre-tax gain of $27.0 million on the sale. Energen used proceeds from the sale to reduce long-term indebtedness. At December 31, 2014, proved reserves associated with these San Juan Basin properties totaled 69,038 MBOE. Energen completed an estimated total of $85.7 million in various purchases of unproved leasehold largely in the Permian Basin during 2015. During 2014, Energen completed a total of approximately $68.5 million in various purchases of unproved leasehold properties, including the October 2014, purchase of approximately 15,000 net acres of unproved leasehold in the Mancos formation oil play in the San Juan Basin for $22.8 million . During 2013, Energen also completed a total of approximately $26.8 million in various purchases of unproved leasehold properties. |
Discontinued Operations and Hel
Discontinued Operations and Held for Sale Properties | 12 Months Ended |
Dec. 31, 2015 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations and Held for Sale Properties | DISCONTINUED OPERATIONS AND HELD FOR SALE PROPERTIES As discussed in Note 15, Acquisition and Disposition of Properties, subsequent to December 31, 2015, Energen classified certain non-core assets in the eastern Delaware Basin as held for sale. Proved reserves associated with these Delaware Basin properties totaled 25,200 MBOE at December 31, 2015. At December 31, 2015, our remaining San Juan Basin properties were classified as held for sale. Proved reserves associated with these San Juan Basin properties totaled 16,930 MBOE at December 31, 2015. The following table details San Juan Basin held for sale properties by major classes of assets and liabilities. Property sales in the San Juan Basin do not qualify for discontinued operations: (in thousands) December 31, 2015 December 31, 2014 Inventories $ 3,651 $ — Oil and natural gas properties 305,386 1,166,124 Less accumulated depreciation, depletion and amortization (219,059 ) (770,327 ) Other property and equipment, net 3,761 — Total assets held for sale 93,739 395,797 Other long-term liabilities (12,789 ) (24,230 ) Total liabilities held for sale (12,789 ) (24,230 ) Total net assets held for sale $ 80,950 $ 371,567 On September 2, 2014, Energen completed the transaction to sell Alagasco to Laclede for $1.6 billion , less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion resulting in a pre-tax gain of $726.5 million . This sale has an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. Energen’s results of operations and cash flows for the years ended December 31, 2014 and 2013 presented in our consolidated financial statements and these notes reflect Alagasco as discontinued operations. We classified as discontinued operations interest on debt required to be extinguished, certain depreciation costs that ended at close of transaction, the related income tax impact of these items and the earnings of Alagasco. In addition, we reclassified from discontinued operations certain general and administrative expenses, other income and the related tax impact from these items. The table below provides a detail of these items included in income (loss) from discontinued operations as follows: Years ended December 31, (in thousands) 2014 2013 Alagasco net income $ 40,646 $ 57,399 Depreciation, depletion and amortization (408 ) (598 ) General and administrative 3,337 5,894 Interest expense (17,306 ) (13,815 ) Other income (347 ) (1,342 ) Income tax expense 5,567 3,728 Alagasco income from discontinued operations 31,489 51,266 Energen income (loss) from discontinued operations (2,197 ) 7,813 Income from discontinued operations $ 29,292 $ 59,079 Years ended December 31, (in thousands, except per share data) 2014 2013 Natural gas distribution revenues $ 397,648 $ 533,338 Oil and natural gas revenues 5,199 60,191 Total revenues $ 402,847 $ 593,529 Pretax income from discontinued operations $ 47,220 $ 92,253 Income tax expense 17,928 33,174 Income From Discontinued Operations $ 29,292 $ 59,079 Gain on disposal of discontinued operations, net $ 724,594 $ 5,605 Income tax expense 285,497 2,011 Gain on Disposal of Discontinued Operations, net $ 439,097 $ 3,594 Total Income From Discontinued Operations $ 468,389 $ 62,673 Diluted Earnings Per Average Common Share Income from discontinued operations $ 0.40 $ 0.81 Gain on disposal of discontinued operations, net 5.99 0.05 Total Income From Discontinued Operations $ 6.39 $ 0.86 Basic Earnings Per Average Common Share Income from discontinued operations $ 0.40 $ 0.82 Gain on disposal of discontinued operations, net 6.02 0.05 Total Income From Discontinued Operations $ 6.42 $ 0.87 In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million . The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations. Energen recognized non-cash impairment writedowns on these properties in 2014 of $1.9 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2014. Energen also recognized non-cash impairment writedowns on these properties of $29.8 million in 2013. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2013. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil. In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million . Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 that was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | SUPPLEMENTAL CASH FLOW INFORMATION Supplemental information concerning Energen’s cash flow activities from continuing operations was as follows: Years ended December 31, (in thousands) 2015 2014 2013 Interest paid, net of amount capitalized $ 40,747 $ 32,172 $ 38,255 Income taxes paid $ 8,114 $ 219,505 $ 22,781 Noncash investing activities: Accrued development, exploration costs and other capital $ 79,206 $ 207,461 $ 93,623 Capitalized asset retirement obligations costs $ 981 $ 2,958 $ 2,772 Receivable from sale of Alabama Gas Corporation $ — $ 8,247 $ — Noncash financing activities: Issuance of common stock for employee benefit plans $ 5,758 $ 2,448 $ 1,015 Treasury stock acquired in connection with tax withholdings $ 4,722 $ 2,547 $ 977 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2015 | |
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) Pension and Postretirement Plans Balance as of December 31, 2014 $ (22,870 ) Other comprehensive income before reclassifications 3,305 Amounts reclassified from accumulated other comprehensive income 19,828 Change in accumulated other comprehensive income (loss) 23,133 Balance as of December 31, 2015 $ 263 The following table provides details of the reclassifications out of accumulated other comprehensive income (loss): Years ended December 31, (in thousands) 2015 2014 2013 Amounts Reclassified Line Item Where Presented Gains (losses) on cash flow hedges: Commodity contracts $ — $ 21,611 $ 35,684 Gain (loss) on derivative instruments, net Interest rate swap — (2,280 ) (1,723 ) Interest expense Total cash flow hedges — 19,331 33,961 Income tax expense — (7,414 ) (12,957 ) Net of tax — 11,917 21,004 Pension and postretirement plans: Transition obligation — (22 ) (319 ) General and administrative Prior service cost — (248 ) (257 ) General and administrative Actuarial losses (30,504 ) (21,932 ) (12,357 ) General and administrative Actuarial losses on settlement charges* — — (421 ) Assets held for sale Total pension and postretirement plans (30,504 ) (22,202 ) (13,354 ) Income tax benefit 10,676 7,771 4,674 Net of tax (19,828 ) (14,431 ) (8,680 ) Total reclassifications for the period $ (19,828 ) $ (2,514 ) $ 12,324 *During the year ended December 31, 2013, Energen incurred settlement charges of $0.6 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.2 million was recognized in actuarial losses above and $0.4 million was recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above. |
Recently Issued Accounting Stan
Recently Issued Accounting Standards | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Changes and Error Corrections [Abstract] | |
Recently Issued Accounting Standards | RECENTLY ISSUED ACCOUNTING STANDARDS In November 2015, the Financial Accounting Standards Board (FASB) issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. Prior year comparable periods have not been updated retrospectively, as we elected to adopt the standard prospectively. This update requires that deferred tax liabilities and assets be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of each jurisdiction of an entity be offset and presented as a single amount is not affected by the amendments in this update. The amendment is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Energen elected early adoption of this ASU prospectively as of December 31, 2015. We reclassified $14.5 million from a current deferred income tax asset to a noncurrent deferred income tax liability at December 31, 2015. In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendment is effective for fiscal years beginning on or after December 15, 2015, and interim periods within those fiscal years. Energen does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This update clarifies the guidance regarding line-of-credit arrangements with regards to the recently issued ASU 2015-03. ASU 2015-15 allows entities to defer and present debt issue costs as an asset and subsequently amortize the deferred debt issue costs ratably over the term of the line-of-credit arrangement. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This update codifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. The amendments in this ASU will not impact the Company's financial position or results of operations. The new guidance will require a formal assessment of going concern by management based on criteria prescribed in the new guidance. The Company is reviewing its policies and processes to ensure compliance with this new guidance. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. 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. Companies may apply this update retrospectively or using a modified retrospective approach to adjust retained earnings. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers, which deferred the effective date of ASU No. 2014-09 to annual periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are currently evaluating the impact of this guidance on our financial statements. In April 2014, the FASB issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held for sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment was effective for annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The adoption of this ASU did not have a material impact on the consolidated financial statements of Energen. |
Summarized Quarterly Financial
Summarized Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summarized Quarterly Financial Information (Unaudited) | SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited) The following data summarizes quarterly operating results: Year ended December 31, 2015 (in thousands, except per share amounts) First Second Third Fourth Revenues $ 221,858 $ 168,326 $ 295,571 $ 192,799 Operating loss $ (12,409 ) $ (161,678 ) $ (348,214 ) $ (915,550 ) Loss from continuing operations $ (15,420 ) $ (111,601 ) $ (227,904 ) $ (590,806 ) Net loss $ (15,420 ) $ (111,601 ) $ (227,904 ) $ (590,806 ) Diluted earnings per average common share Continuing operations $ (0.21 ) $ (1.52 ) $ (2.89 ) $ (7.50 ) Net loss $ (0.21 ) $ (1.52 ) $ (2.89 ) $ (7.50 ) Basic earnings per average common share Continuing operations $ (0.21 ) $ (1.52 ) $ (2.89 ) $ (7.50 ) Net loss $ (0.21 ) $ (1.52 ) $ (2.89 ) $ (7.50 ) Year ended December 31, 2014 (in thousands, except per share amounts) First Second Third Fourth Revenues as originally reported $ 561,178 $ 270,097 $ 497,761 $ 611,435 Discontinued operations* (263,900 ) — — — Reclassification of loss on sale of assets and other 153 909 747 833 Adjusted revenues $ 297,431 $ 271,006 $ 498,508 $ 612,268 Operating income as originally reported $ 104,599 $ 3,107 $ 48,171 $ 94,223 Discontinued operations* (73,139 ) — — — Adjusted operating income $ 31,460 $ 3,107 $ 48,171 $ 94,223 Income (loss) from continuing operations $ 15,647 $ (3,154 ) $ 20,631 $ 66,519 Net income (loss) $ 53,316 $ (7,953 ) $ 457,251 $ 65,418 Diluted earnings per average common share Continuing operations $ 0.21 $ (0.04 ) $ 0.28 $ 0.91 Net income (loss) $ 0.73 $ (0.11 ) $ 6.22 $ 0.89 Basic earnings per average common share Continuing operations $ 0.22 $ (0.04 ) $ 0.28 $ 0.91 Net income (loss) $ 0.73 $ (0.11 ) $ 6.26 $ 0.90 *As discussed in Note 16, Discontinued Operations and Held for Sale Properties, during the third quarter of 2014, Energen completed the transaction to sell Alagasco to Laclede. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. |
Oil and Natural Gas Operations
Oil and Natural Gas Operations (Unaudited) Oil and Natural Gas Operations (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Oil and Natural Gas Operations (Unaudited) | OIL AND NATURAL GAS OPERATIONS (Unaudited) Capitalized Costs: The following table sets forth capitalized costs: (in thousands) December 31, 2015 December 31, 2014 Proved $ 7,911,554 $ 8,069,638 Unproved 150,674 142,340 Total capitalized costs 8,062,228 8,211,978 Accumulated depreciation, depletion and amortization 3,673,569 2,663,434 Capitalized costs, net $ 4,388,659 $ 5,548,544 Costs Incurred: The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year: Years ended December 31, (in thousands) 2015 2014 2013 Property acquisition: Proved $ 1,866 $ 2,582 $ 4,661 Unproved 85,690 68,514 26,820 Exploration 649,764 972,164 435,636 Development 372,177 408,949 655,353 Total costs incurred $ 1,109,497 $ 1,452,209 $ 1,122,470 Results of Operations From Producing Activities: The following table sets forth results of Energen’s oil, natural gas liquids and natural gas operations from producing activities: Years ended December 31, (in thousands) 2015 2014 2013 Gross revenues* $ 878,554 $ 1,679,213 $ 1,206,293 Production (lifting costs) 285,760 376,495 351,541 Exploration expense 14,877 28,090 14,036 Depreciation, depletion and amortization including asset impairments 1,880,190 960,539 463,606 Accretion expense 7,108 7,608 6,995 Income tax expense (benefit) (469,362 ) 99,469 128,773 Results of operations from producing activities $ (840,019 ) $ 207,012 $ 241,342 * The years ended December 31, 2015, 2014 and 2013 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $281.8 million , a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million and a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million , respectively. Oil and Natural Gas Operations: The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that proved categories of reserves be disclosed. Proved reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2015 , 2014 and 2013 . Changes to prices and costs could have a significant effect on the disclosed amount of proved reserves and their associated values. In addition, the estimation of proved reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of proved reserves disclosed. The proved reserves are located onshore in the United States of America. Estimates of physical quantities of oil and natural gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. (Ryder Scott) and Hickman McClaine and Associates, Inc. (Hickman McClaine), independent oil and natural gas reservoir engineers, have audited the estimates of proved reserves of oil, natural gas liquids and natural gas that Energen has attributed to its net interests in oil and natural gas properties as of December 31, 2015 . Ryder Scott audited the proved reserve estimates for coalbed methane in the San Juan Basin and substantially all of the Permian Basin proved reserves. Hickman McClaine audited the conventional proved reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 99 percent of Energen’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate. Year ended December 31, 2015 Oil MBbl NGL MBbl Natural Gas MMcf Total MMBOE Proved reserves at beginning of period 181,227 73,463 707,926 372.7 Revisions of previous estimates (39,537 ) (11,979 ) (44,176 ) (58.9 ) Purchases 2 1 2 — Extensions and discoveries 83,319 25,530 143,022 132.6 Production (14,023 ) (4,065 ) (35,604 ) (24.0 ) Sales (297 ) (11,237 ) (337,266 ) (67.7 ) Proved reserves at end of period 210,691 71,713 433,904 354.7 Proved developed reserves at end of period 108,319 36,374 236,112 184.0 Proved undeveloped reserves at end of period 102,372 35,339 197,792 170.7 Year ended December 31, 2014 Oil MBbl NGL MBbl Natural Gas MMcf Total MMBOE Proved reserves at beginning of period 164,870 63,011 719,725 347.8 Revisions of previous estimates (48,548 ) (15,165 ) (71,806 ) (75.7 ) Purchases 88 26 116 0.1 Extensions and discoveries 76,722 29,695 141,209 130 Production (11,818 ) (4,104 ) (59,562 ) (25.8 ) Sales (87 ) — (21,756 ) (3.7 ) Proved reserves at end of period 181,227 73,463 707,926 372.7 Proved developed reserves at end of period 118,697 47,621 589,074 264.5 Proved undeveloped reserves at end of period 62,530 25,842 118,852 108.2 Year ended December 31, 2013 Oil MBbl NGL MBbl Natural Gas MMcf Total MMBOE Proved reserves at beginning of period 155,348 56,155 809,128 346.4 Revisions of previous estimates (680 ) 2,211 18,465 4.6 Purchases 142 56 282 0.2 Extensions and discoveries 20,517 7,823 50,568 36.8 Production (10,378 ) (3,233 ) (70,506 ) (25.4 ) Sales (79 ) (1 ) (88,212 ) (14.8 ) Proved reserves at end of period 164,870 63,011 719,725 347.8 Proved developed reserves at end of period 113,795 42,087 623,305 259.8 Proved undeveloped reserves at end of period 51,075 20,924 96,420 88.0 2015 Activities: Energen had net downward reserve revisions during 2015 which totaled 58.9 MMBOE including negative revisions of approximately 38.0 MMBOE related to changes in year-end pricing and negative revisions of approximately 8.2 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period. Other negative revisions were 5.5 MMBOE due to increased declines in certain Wolfberry wells and 5.0 MMBOE of Wolfcamp reserves due to interference caused by our wellbore placement geometry. During 2015, Energen had extensions and discoveries of 132.6 MMBOE, primarily in the Permian Basin, of which 78 percent were proved undeveloped reserves and 22 percent were proved developed reserves. Extension drilling resulted in 3.1 MMBOE of discoveries with exploratory drilling providing 129.5 MMBOE of discoveries. During 2015, Energen had sales of 67.7 MMBOE primarily due to the sale of certain natural gas assets in the San Juan Basin. 2014 Activities: Energen had net downward reserve revisions during 2014 which totaled 75.7 MMBOE including downward revisions of approximately 53.4 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period and upward revisions of approximately 3.9 MMBOE related to changes in year-end pricing. The San Juan Basin had upward reserve revisions of 1.6 MMBOE including 4.4 MMBOE related to changes in year-end pricing and downward revisions of approximately 1.5 MMBOE due to higher operating costs. Net downward reserve revisions of 77.3 MMBOE in the Permian Basin were due to reclassifying 53.4 MMBOE as unproved because of changes in our development plans, downward revisions of approximately 13.3 MMBOE due to decreased well performance in certain Wolfberry wells, downward revisions of approximately 5.4 due to higher operating costs and approximately 0.5 MMBOE related to changes in the year-end pricing. Energen purchased 0.1 MMBOE of reserves during 2014 primarily related to the acquisitions of oil properties in the Permian Basin. During 2014, Energen had extensions and discoveries of 130.0 MMBOE of which 70 percent were proved undeveloped reserves and 30 percent were proved developed reserves. Extension drilling resulted in 89.6 MMBOE of discoveries with exploratory drilling providing 40.4 MMBOE of discoveries. The San Juan Basin added 1.1 MMBOE of reserves through the drilling or identification of 16 well locations and 10 pay adds. The Permian Basin added 128.6 MMBOE of reserves primarily through the drilling or identification of 361 well locations. During 2014, Energen had sales of 3.7 MMBOE primarily due to the sale of the North Louisiana/East Texas primarily natural gas properties. 2013 Activities: Energen had upward reserve revisions during 2013 which totaled 4.6 MMBOE including approximately 7 MMBOE related to changes in year-end pricing and downward revisions of approximately 5.3 MMBOE of proved undeveloped reserves of which 4.6 MMBOE are expected to be drilled beyond five years with the remainder no longer expected to be drilled. The San Juan Basin upward reserve revisions of 2.2 MMBOE including 5.9 MMBOE related to changes in year-end pricing and downward revisions of approximately 4.6 MMBOE of proved undeveloped reserves that are expected to be drilled beyond five years. Net upward reserve revisions of 1.2 MMBOE in the Permian Basin were due to improved well performance in certain Wolfberry wells and approximately 0.4 MMBOE related to changes in the year-end pricing and downward revisions of approximately 0.7 MMBOE of proved undeveloped reserves that are no longer expected to be drilled. Energen purchased 0.2 MMBOE of reserves during 2013 primarily related to the acquisitions of oil properties in the Permian Basin. During 2013, Energen had extensions and discoveries of 36.8 MMBOE of which 45 percent were proved undeveloped reserves and 55 percent were proved developed reserves. Extension drilling resulted in 21.6 MMBOE of discoveries with exploratory drilling providing 15.2 MMBOE of discoveries. The San Juan Basin added 2.3 MMBOE of reserves through 30 pay adds. The Permian Basin added 34.4 MMBOE of reserves primarily through the drilling or identification of 262 well locations. During 2013, Energen had sales of 14.8 MMBOE primarily due to the sale of the Black Warrior Basin coalbed methane properties. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of Energen’s crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. Open mark-to-market derivatives applicable to future periods are excluded from the calculation of standardized measure of future net cash flows. Years ended December 31, (in thousands) 2015 2014 2013 Future gross revenues $ 11,714,729 $ 20,971,672 $ 19,509,305 Future production costs 4,353,974 7,532,273 6,136,709 Future development costs 1,961,661 1,784,738 1,896,602 Future income tax expense 1,065,887 3,440,582 3,209,697 Future net cash flows 4,333,207 8,214,079 8,266,297 Discount at 10% per annum 2,299,859 3,994,423 4,248,456 Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 2,033,348 $ 4,219,656 $ 4,017,841 The following are the principal sources of changes in the standardized measure of discounted future net cash flows: Years ended December 31, (in thousands) 2015 2014 2013 Balance at beginning of year $ 4,219,656 $ 4,017,841 $ 3,699,319 Revisions to reserves proved in prior years: Net changes in prices, production costs and future development costs (2,861,591 ) (1,147,028 ) 566,838 Net changes due to revisions in quantity estimates (404,708 ) (1,285,394 ) (81,762 ) Development costs incurred, previously estimated 350,560 337,198 299,432 Accretion of discount 421,966 401,784 369,932 Changes in timing and other* (903,975 ) 987,652 (179,502 ) Total revisions (3,397,748 ) (705,788 ) 974,938 New field discoveries and extensions, net of future production and development costs 776,315 2,321,028 376,326 Sales of oil and gas produced, net of production costs (514,380 ) (1,054,553 ) (1,014,593 ) Purchases 8 4,241 4,690 Sales (372,039 ) (21,092 ) (24,876 ) Net change in income taxes 1,321,536 (342,021 ) 2,037 Net change in standardized measure of discounted future net cash flows (2,186,308 ) 201,815 318,522 Balance at end of year $ 2,033,348 $ 4,219,656 $ 4,017,841 *Amount represents changes in production timing and other. In 2015, the production timing is significantly affected by changes related to the delay of the drilling program. For 2014, the production timing is significantly affected by changes related to the acceleration of the horizontal drilling program and the delay of the vertical drilling program. |
Summary of Significant Accoun31
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | The accompanying consolidated financial statements include Energen and its subsidiaries, principally Energen Resources, after elimination of all significant intercompany transactions in consolidation. In the opinion of management, our consolidated financial statements reflect all adjustments necessary to present fairly 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. |
Property and Related Depletion | Energen follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, natural gas liquids and natural gas reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. 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, we continue 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) we are 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 balance sheets. If the exploratory well is determined to be a dry well, the costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves. |
Operating Revenues | Energen utilizes the sales method of accounting to recognize oil, natural gas liquids and natural gas production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining proved reserves for such property. |
Derivative Commodity Instruments | We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen. All derivative transactions are included in operating activities on the consolidated statements of cash flows. The majority of our counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Energen formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the nature of the risk being hedged. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes. Effective June 30, 2013, Energen discontinued the use of cash flow hedge accounting and dedesignated all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen in accumulated other comprehensive income until the forecasted transactions actually occurred. Any subsequent gains or losses are accounted for as mark-to-market and recognized immediately through gain (loss) on derivative instruments, net. As a result of Energen’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 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 . |
Asset Impairments | Oil and natural gas proved properties periodically are assessed for possible impairment on a field-by-field basis using the estimated undiscounted future cash flows. Energen monitors its oil and natural gas properties as well as the market and business environments in which it operates and makes assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected production performance. If a material event occurs, we make an estimate of undiscounted future cash flows to determine whether the asset is impaired. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. If the asset is impaired, Energen 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. 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 variables can, and often do, differ from the estimates and can have a positive or negative impact on our need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact Energen’s original and ongoing assessments of potential impairment. Energen also may recognize impairments of capitalized costs for unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by exploration activities, changes in economic factors and potential shifts in business strategy employed by management. We consider a combination of geologic and economic factors to evaluate the need for impairment of these costs. |
Long-Lived Assets and Discontinued Operations | Energen may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held for sale are reported at the lower of the carrying amount or estimated fair value. Certain of these held for sale properties also qualify as discontinued operations and the results of operations of these properties are reclassified and reported as discontinued operations for prior periods. |
Acquisitions | Energen recognizes all acquisitions at fair value. Energen estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen obtained control of the properties for all acquisitions that qualify as business combinations. The 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). Fair value measurements also utilize assumptions of market participants. Energen uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy. Acquisition related costs are expensed as incurred in general and administrative expense on the consolidated income statements. |
Inventory | Inventories consist primarily of tubular goods and other oilfield equipment used in our operations and are stated at the lower of cost or market value, on a weighted average cost basis. |
Fair Value Measurements | The carrying values of cash and cash equivalents, accounts payable, accounts receivable (net of allowance), derivative commodity instruments, pension and postretirement plan assets and liabilities and other current assets and liabilities approximate fair value. 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 assumptions 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; 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. 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 directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps 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 basin specific, 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, we maintain communications with our counterparties and discuss pricing practices. Further, we corroborate the fair value of our transactions by comparison of market-based price sources. Energen utilizes a discounted cash flow model in valuing its interest rate derivatives, which are comprised of interest rate swap agreements. The fair value attributable to Energen's interest rate derivative contracts is based on (i) the contracted notional amounts, (ii) active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. Pension and postretirement plan assets include cash and mutual funds. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and Level 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds. |
Income Taxes | Energen uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. Energen and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method. |
Accounts Receivable and Allowance for Doubtful Accounts | Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in the existing accounts receivable. Energen determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered. |
Cash and Cash Equivalents | Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value. |
Short-term investments | All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments. |
Earnings Per Share (EPS) | Energen’s basic earnings per share amounts have been computed based on the weighted average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities. |
Stock-Based Compensation | Energen recognizes all share-based compensation awards in general and administrative expense on the consolidated income statement over the requisite vesting period. Equity awards are measured at fair value as of the date of grant. Awards that are settled in cash are classified as liabilities and re-measured at fair value at the end of each reporting period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. We recognize all stock-based compensation expense in the period of grant, subject to certain vesting requirements, for retirement eligible employees. Energen utilizes the long-form method of calculating the available pool of windfall tax benefit. |
Estimates | The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, physical quantities of proved oil and gas reserves, periodic assessments of oil and gas properties for impairment, Energen’s obligations under its employee pension and compensation plans, the valuation of derivative financial instruments, the allowance for doubtful accounts, tax contingency reserves, legal contingency reserves, asset retirement obligations and self insurance reserves. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates. |
Employee Benefit Plans | Plan Termination: In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015 and distributed benefits in December 2015. Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 with the remainder to be paid in the first quarter of 2016. Plan Separation: Effective April 30, 2014, Energen separated its defined benefit non-contributory pension plan and its postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan reflecting the separation of assets and obligations in accordance with ERISA provisions. Energen remeasured the plans using current assumptions. Postretirement Benefit Plans: Energen provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. These postretirement healthcare and life insurance benefits are available upon reaching normal retirement age while working for Energen. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability. For other postretirement plans, certain financial assumptions are used in determining Energen’s projected benefit obligation. These assumptions are examined periodically by Energen, and any required changes are reflected in the subsequent determination of projected benefit obligations. Energen calculates periodic expense for the other postretirement benefit plans on an actuarial basis and the net funded status is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. The benefit obligation is the accumulated postretirement benefit obligation. Energen measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position. For our other postretirement plan, we selected a yield curve comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. Energen considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets. |
Environmental Costs | Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated. |
Investment Strategy | For our postretirement benefit plan assets, we continue to employ a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions. Energen seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, commodity or class of investment fund. |
Recently Issued Accounting Pronouncements | In November 2015, the Financial Accounting Standards Board (FASB) issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. Prior year comparable periods have not been updated retrospectively, as we elected to adopt the standard prospectively. This update requires that deferred tax liabilities and assets be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of each jurisdiction of an entity be offset and presented as a single amount is not affected by the amendments in this update. The amendment is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Energen elected early adoption of this ASU prospectively as of December 31, 2015. We reclassified $14.5 million from a current deferred income tax asset to a noncurrent deferred income tax liability at December 31, 2015. In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendment is effective for fiscal years beginning on or after December 15, 2015, and interim periods within those fiscal years. Energen does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This update clarifies the guidance regarding line-of-credit arrangements with regards to the recently issued ASU 2015-03. ASU 2015-15 allows entities to defer and present debt issue costs as an asset and subsequently amortize the deferred debt issue costs ratably over the term of the line-of-credit arrangement. In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This update codifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. The amendments in this ASU will not impact the Company's financial position or results of operations. The new guidance will require a formal assessment of going concern by management based on criteria prescribed in the new guidance. The Company is reviewing its policies and processes to ensure compliance with this new guidance. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. 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. Companies may apply this update retrospectively or using a modified retrospective approach to adjust retained earnings. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers, which deferred the effective date of ASU No. 2014-09 to annual periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are currently evaluating the impact of this guidance on our financial statements. In April 2014, the FASB issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held for sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment was effective for annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The adoption of this ASU did not have a material impact on the consolidated financial statements of Energen. |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Schedule of Long-Term Debt | Long-term debt consisted of the following: (in thousands) December 31, 2015 December 31, 2014 Credit facility $ 222,500 $ 485,000 7.40% Medium-term Notes, Series A, due July 24, 2017 2,000 2,000 7.36% Medium-term Notes, Series A, due July 24, 2017 15,000 15,000 7.23% Medium-term Notes, Series A, due July 28, 2017 2,000 2,000 7.32% Medium-term Notes, Series A, due July 28, 2022 20,000 20,000 7.60% Medium-term Notes, Series A, due July 26, 2027 5,000 5,000 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 4.625% Notes, due September 1, 2021 400,000 400,000 Total 776,500 1,039,000 Less unamortized debt discount 413 437 Total $ 776,087 $ 1,038,563 |
Schedule of Aggregate Maturities of Long-Term Debt | The aggregate maturities of Energen’s long-term debt as of December 31, 2015 are as follows: Years ending December 31, (in thousands) 2016 2017 2018 2019 2020 Thereafter $— $19,000 $— $222,500 $— $535,000 |
Schedule of Credit Facilities | The following is a summary of information relating to Energen’s credit facility: (in thousands) December 31, 2015 December 31, 2014 Credit facility outstanding $ 222,500 $ 485,000 Available for borrowings 1,177,500 1,515,000 Total borrowing commitments $ 1,400,000 $ 2,000,000 Maximum amount outstanding at any month-end $ 685,000 $ 750,000 Average daily amount outstanding $ 358,929 $ 482,166 Weighted average interest rates based on: Average daily amount outstanding 1.60 % 1.46 % Amount outstanding at year-end 1.64 % 1.67 % |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Taxes | The components of Energen’s income taxes consisted of the following: Years ended December 31, (in thousands) 2015 2014 2013 Taxes estimated to be payable currently: Federal $ 3,972 $ 161,576 $ 23,342 State 758 72,379 2,516 Total current 4,730 233,955 25,858 Taxes deferred: Federal (513,187 ) 144,645 85,950 State (26,548 ) (34,447 ) (2,300 ) Total deferred (539,735 ) 110,198 83,650 Total income tax expense (benefit) $ (535,005 ) $ 344,153 $ 109,508 |
Schedule of Components of Income Tax Expense (Benefit), Continuing and Discontinued Operations | The components of Energen’s income taxes consisted of the following: Years ended December 31, (in thousands) 2015 2014 2013 Income tax expense (benefit) from continuing operations $ (535,005 ) $ 40,728 $ 74,323 Income tax expense from discontinued operations — 17,928 33,174 Income tax expense from gain on disposal of discontinued operations — 285,497 2,011 Total income tax expense (benefit) $ (535,005 ) $ 344,153 $ 109,508 |
Schedule of Deferred Tax Assets and Liabilities | Temporary differences and carryforwards which gave rise to Energen’s deferred tax assets and liabilities were as follows: (in thousands) December 31, 2015 December 31, 2014 Current Noncurrent Current Noncurrent Deferred tax assets: Minimum tax credit $ — $ 44,862 $ — $ 46,338 Allowance for doubtful accounts — 253 244 — Insurance and other accruals — 2,807 2,537 — Compensation accruals — 11,650 11,355 — Pension and other costs — 8,693 — 7,009 Other comprehensive income — — 10,732 1,581 State net operating losses and other carryforwards — 12,577 — 15,392 Other — 962 665 — Total deferred tax assets — 81,804 25,533 70,320 Valuation allowance — (4,235 ) (1,122 ) (2,467 ) Total deferred tax assets — 77,569 24,411 67,853 Deferred tax liabilities: Depreciation and basis differences — 620,629 — 1,057,430 Derivative instruments — 2,838 102,691 — Other comprehensive income — 141 — — Other — 6,330 884 10,909 Total deferred tax liabilities — 629,938 103,575 1,068,339 Net deferred tax liabilities $ — $ (552,369 ) $ (79,164 ) $ (1,000,486 ) |
Schedule of Effective Income Tax Rate Reconciliation | Total income tax expense from continuing operations differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below: Years ended December 31, (in thousands) 2015 2014 2013 Income tax expense (benefit) at statutory federal income tax rate $ (518,258 ) $ 49,130 $ 75,671 Increase (decrease) resulting from: State income taxes, net of federal income tax benefit (14,112 ) 93 1,461 Impact of state law changes (3,075 ) (121 ) (1,966 ) Impact of state deferred tax revaluation on San Juan properties (1,241 ) (8,382 ) — 401(k) stock dividend deduction — (232 ) (449 ) Other, net 1,681 240 (394 ) Total income tax expense (benefit) $ (535,005 ) $ 40,728 $ 74,323 Effective income tax rate (%) 36.13 29.01 34.38 |
Schedule of Reconciliation of Unrecognized Tax Benefits | A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows: (in thousands) Balance as of December 31, 2012 $ 12,555 Additions based on tax positions related to the current year 4,546 Additions for tax positions of prior years 366 Reductions for tax positions of prior years (46 ) Lapse of statute of limitations (1,435 ) Balance as of December 31, 2013 15,986 Additions based on tax positions related to the current year 3,873 Additions for tax positions of prior years 19 Reductions for tax positions of prior years (954 ) Lapse of statute of limitations (1,394 ) Balance as of December 31, 2014 17,530 Additions based on tax positions related to the current year 2,378 Reductions based on tax positions related to the current year (6,589 ) Reductions for tax positions of prior years (345 ) Lapse of statute of limitations (1,785 ) Balance as of December 31, 2015 $ 11,189 |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Benefit Obligations | The following table sets forth the combined funded status of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in Energen’s consolidated financial statements. As of December 31, (in thousands) 2015 2014 2015 2014 Pension Postretirement Benefits Accumulated benefit obligation $ 15,729 $ 107,669 Benefit obligation: Balance at beginning of period $ 107,669 $ 266,294 $ 11,127 $ 33,224 Service cost — 8,329 392 262 Interest cost 816 5,325 466 716 Actuarial (gain) loss (683 ) 9,078 (1,185 ) 6,385 Plan amendments — — (4,071 ) — Curtailment gain — (8,496 ) — — Transfer in connection with the sale of Alagasco — (124,783 ) — (28,648 ) Termination benefit charge — 2,477 — — Retiree drug subsidy program — — — 48 Benefits paid (92,073 ) (50,555 ) (241 ) (860 ) Balance at end of period $ 15,729 $ 107,669 $ 6,488 $ 11,127 Plan assets: Fair value of plan assets at beginning of period $ 67,542 $ 193,457 $ 10,693 $ 55,459 Actual return (loss) on plan assets (289 ) 5,359 (83 ) (331 ) Employer contributions 24,847 19,164 — 21 Transfer in connection with the sale of Alagasco — (99,883 ) — (43,596 ) Benefits paid (92,073 ) (50,555 ) (241 ) (860 ) Fair value of plan assets at end of period $ 27 $ 67,542 $ 10,369 $ 10,693 Funded status of plans $ (15,702 ) $ (40,127 ) $ 3,881 $ (434 ) Noncurrent assets $ — $ — $ 3,881 $ — Current liabilities (15,702 ) (24,626 ) — — Noncurrent liabilities — (15,501 ) — (434 ) Net asset (liability) recognized $ (15,702 ) $ (40,127 ) $ 3,881 $ (434 ) Amounts recognized to accumulated other comprehensive income: Prior service credit, net of taxes $ — $ — $ (2,646 ) $ — Net actuarial loss, net of taxes 2,179 22,246 205 624 Total accumulated other comprehensive income (loss) $ 2,179 $ 22,246 $ (2,441 ) $ 624 |
Schedule of Allocation of Plan Assets | The Company’s weighted average plan asset allocations by asset category were as follows: Pension Postretirement Benefits As of December 31, Target 2015 2014 Target 2015 2014 Asset category: Equity securities — % — % — % 56 % 56 % 60 % Debt securities — % — % — % 44 % 44 % 40 % Cash and cash equivalents 100 % 100 % 100 % — % — % — % Total 100 % 100 % 100 % 100 % 100 % 100 % |
Schedule of Net Periodic Benefit Cost | The components of net periodic benefit cost from continuing operations were as follows: Years ended December 31, (in thousands) 2015 2014 2013 Pension Plans Components of net periodic benefit cost: Service cost $ — $ 6,808 $ 5,196 Interest cost 816 4,498 4,496 Expected long-term return on assets — (4,386 ) (5,225 ) Prior service cost amortization — 202 246 Actuarial loss amortization 737 4,995 6,919 Termination benefit charge — 2,477 — Settlement charge 29,767 4,082 161 Curtailment expense (gain) — 254 (4 ) Net periodic expense $ 31,320 $ 18,930 $ 11,789 Postretirement Benefit Plans Components of net periodic benefit cost: Service cost $ 392 $ 253 $ 386 Interest cost 466 661 645 Expected long-term return on assets (457 ) (1,122 ) (787 ) Actuarial gain amortization — (653 ) (28 ) Transition obligation amortization — 44 229 Net periodic (income) expense $ 401 $ (817 ) $ 445 |
Schedule of Other Changes in Plan Assets and Projected Benefit Obligations Recognized in Other Comprehensive Income | Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows: Years ended December 31, (in thousands) 2015 2014 2013 Pension Plans Net actuarial (gain) loss experienced during the year $ (394 ) $ 10,495 $ (14,138 ) Net actuarial loss recognized as expense (30,478 ) (25,433 ) (8,934 ) Prior service cost recognized as expense — (246 ) (311 ) Curtailment loss — (8,749 ) — Total recognized in other comprehensive income (loss) (30,872 ) (23,933 ) (23,383 ) Postretirement Benefit Plans Net actuarial (gain) loss experienced during the year $ (645 ) $ 7,649 $ (8,057 ) Prior service credit during the year (4,071 ) — — Net actuarial gain recognized as expense — 1,908 550 Transition obligation recognized as expense — (48 ) (283 ) Total recognized in other comprehensive income (loss) $ (4,716 ) $ 9,509 $ (7,790 ) |
Schedule of Estimated Amount to be Amortized from Accumulated Other Comprehensive Income | Estimated amounts to be amortized, including settlement charges, from accumulated other comprehensive income into pension cost during 2016 are included in the table below. (in thousands) Amortization of net actuarial loss $ 3,352 Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2016 are included in the table below. (in thousands) Amortization of prior service credit $ (515 ) |
Schedule of Weighted Average Rate Assumptions | The weighted average rate assumptions to determine net periodic benefit costs were as follows: Years ended December 31, 2015 2014 2013 Pension Plans Discount rate 0.96 % 3.66 % 3.63 % Expected long-term return on plan assets — % 7.00 % 7.00 % Rate of compensation increase for pay-related plans — % 3.63 % 3.71 % Postretirement Benefit Plans Discount rate 4.25 % 4.88 % 4.36 % Expected long-term return on plan assets 6.20 % 7.00 % 7.00 % Rate of compensation increase — % 3.60 % 3.70 % The pension benefit obligation as of December 31, 2014 represents the present value of the estimated cost of settling the benefit obligation of the plan. For our defined benefit pension plan, we discounted the estimated termination liability using the one year spot rate of 0.70 percent . For the year ended December 31, 2015, the discount rate shown above represents the weighted average for the nonqualified supplemental retirement plan. The discount rate shown below represents the weighted average for both the defined qualified and nonqualified supplemental retirement plans for the year ended December 31, 2014. For the year ended December 31, 2015, the expected long-term return on plan assets no longer applies for our defined benefit pension plan as the assets of the nonqualified supplemental retirement plan are not considered qualifying assets. As the plans were frozen as of December 31, 2014, the rate of compensation increase no longer applies for any of the plans. The weighted average assumptions used to determine the benefit obligations at the measurement date were as follows: Years ended December 31, 2015 2014 Pension Plans Discount rate 3.90 % 0.96 % Postretirement Benefit Plans Discount rate 4.70 % 4.25 % |
Schedule of Assumed Post-65 Health Care Cost Trend Rates | The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows: As of December 31, 2015 2014 Health care cost trend rate assumed for next year 7.75 % 7.25 % Rate to which the cost trend rate is assumed to decline 5.00 % 5.00 % Year that rate reaches ultimate rate 2026 2021 |
Schedule of Expected Benefit Payments | The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows: (in thousands) Pension Benefits Postretirement Benefits 2016 $14,606 $198 2017 $117 $213 2018 $114 $245 2019 $110 $258 2020 $107 $289 2021-2025 $472 $1,769 |
Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | Plan assets included in the funded status of the pension plans were as follows: December 31, 2015 (in thousands) Level 1 Level 2 Total Cash and cash equivalents 27 $ — $ 27 Total $ 27 $ — $ 27 December 31, 2014 (in thousands) Level 1 Level 2 Total Cash and cash equivalents $ 67,542 $ — $ 67,542 Total $ 67,542 $ — $ 67,542 |
Postretirement Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | Plan assets included in the funded status of the postretirement benefit plans were as follows: December 31, 2015 (in thousands) Level 1 Level 2 Total United States equities $ 4,185 $ — $ 4,185 Global equities 1,650 — 1,650 Fixed income — 4,534 4,534 Total $ 5,835 $ 4,534 $ 10,369 December 31, 2014 (in thousands) Level 1 Level 2 Total United States equities $ 4,715 $ — $ 4,715 Global equities 1,711 — 1,711 Fixed income — 4,267 4,267 Total $ 6,426 $ 4,267 $ 10,693 |
Nonqualified Supplemental Retirement Plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | Other investment assets designated for payment of the nonqualified supplemental retirement plans were as follows: December 31, 2015 (in thousands) Level 1 Level 2 Total Cash and cash equivalents $ 3,308 $ — $ 3,308 Total $ 3,308 $ — $ 3,308 December 31, 2014 (in thousands) Level 1 Level 2 Total Fixed income $ — $ 4,255 $ 4,255 Cash and cash equivalents 9,929 — 9,929 Total $ 9,929 $ 4,255 $ 14,184 |
Common Stock Plans (Tables)
Common Stock Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Performance Share Award Activity | A summary of performance share award activity as of December 31, 2015 , and transactions during the years ended December 31, 2015, 2014 and 2013 is presented below: Stock Incentive Plan Shares Weighted Average Price Nonvested at December 31, 2012 — $ — Granted (two-year vesting period) 86,221 61.14 Granted (three-year vesting period) 82,606 62.96 Forfeited (8,008 ) 60.03 Nonvested at December 31, 2013 160,819 62.13 Granted (two-year vesting period) 937 131.56 Granted (three-year vesting period) 65,309 93.49 Vested and paid (14,097 ) 70.06 Nonvested at December 31, 2014 212,968 71.53 Granted (three-year vesting period) 120,372 83.94 Vested and paid (77,257 ) 61.36 Nonvested at December 31, 2015 256,083 $ 80.43 |
Schedule of Restricted Stock Activity and Transactions | A summary of restricted stock award activity as of December 31, 2015 , and transactions during the years ended December 31, 2015 , 2014 and 2013 is presented below: Stock Incentive Plan Awards Weighted Average Price Nonvested at December 31, 2012 11,115 $ 45.24 Restricted stock granted 52,650 52.34 Forfeited (1,247 ) 48.36 Nonvested at December 31, 2013 62,518 51.16 Restricted stock units granted 48,904 71.91 Vested (11,848 ) 65.94 Nonvested at December 31, 2014 99,574 59.60 Restricted stock units granted 99,814 65.15 Vested (14,446 ) 53.20 Nonvested at December 31, 2015 184,942 $ 63.09 |
Schedule of Stock Option Activity and Transactions | A summary of stock option activity as of December 31, 2015 , and transactions during the years ended December 31, 2015 , 2014 and 2013 are presented below: Stock Incentive Plan Shares Weighted Average Exercise Price Outstanding at December 31, 2012 1,648,475 $ 47.58 Granted 137,762 49.22 Exercised (590,119 ) 40.92 Forfeited (5,074 ) 51.85 Outstanding at December 31, 2013 1,191,044 51.06 Granted 110,307 72.55 Exercised (544,280 ) 50.09 Outstanding at December 31, 2014 757,071 54.88 Exercised (23,680 ) 41.42 Outstanding at December 31, 2015 733,391 $ 55.32 Exercisable at December 31, 2013 713,445 $ 49.80 Exercisable at December 31, 2014 454,938 $ 51.88 Exercisable at December 31, 2015 622,156 $ 53.80 |
Schedule of Stock Options Valuation Assumptions | Energen uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values: Grant date 4/15/2014 1/22/2014 10/15/2013 1/24/2013 Awards granted 2,439 107,868 3,686 134,076 Fair market value of stock option at grant $32.22 $27.57 $30.53 $16.66 Expected life of award 5.8 years 5.8 years 5.8 years 5.8 years Risk-free interest rate 1.93% 2.06% 1.79% 1.01 % Annualized volatility rate 40.7% 40.7% 40.6% 40.3 % Dividend yield 0.2% 0.8% 0.7% 1.2 % |
Schedule of Outstanding Stock Options by Range of Exercise Prices | The following table summarizes options outstanding as of December 31, 2015 : Stock Incentive Plan Range of Exercise Prices Shares Weighted Average Remaining Contractual Life $46.45 19,990 1.00 year $60.56 48,560 2.00 years $29.79 24,291 3.00 years $46.69 26,481 4.00 years $54.99 104,841 5.00 years $54.11 271,164 6.00 years $48.36 124,071 7.00 years $80.48 3,686 7.79 years $72.39 107,868 8.00 years $79.63 2,439 8.00 years $29.79-$80.48 733,391 5.76 years |
Summary of Stock Appreciation Rights Activity | A summary of stock appreciation rights activity as of December 31, 2015 , and transactions during the years ended December 31, 2015 , 2014 and 2013 are presented below: Stock Appreciation Rights Plan Shares Weighted Average Exercise Price Outstanding at December 31, 2012 653,030 $ 44.14 Granted 88,000 48.36 Exercised/forfeited (363,653 ) 39.66 Outstanding at December 31, 2013 377,377 49.48 Granted 62,749 72.39 Exercised/forfeited (164,976 ) 52.37 Outstanding at December 31, 2014 275,150 52.96 Exercised/forfeited (10,283 ) 55.18 Outstanding at December 31, 2015 264,867 $ 52.88 |
Schedule of Stock Appreciation Rights Valuation Assumptions | For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2015 : Grant date 1/22/2014 1/22/2014 1/24/2013 1/24/2013 1/24/2013 1/26/2011 (modified) (modified) (modified) Awards granted 62,227 522 83,654 768 3,578 182,199 Fair market value of award $5.11 $1.67 $8.30 $5.64 $4.24 $4.80 Expected life of award 4.56 years 2.13 years 3.57 years 2.13 years 1.50 years 2.53 years Risk-free interest rate 1.67% 1.11% 1.43% 1.11% 0.80% 1.23% Annualized volatility rate 33.4% 33.4% 33.4% 33.4% 33.4% 33.4% Dividend yield 0.20% 0.20% 0.20% 0.20% 0.20% 0.20% Grant date 1/26/2011 1/27/2010 1/28/2009 2/4/2008 2/1/2007 (modified) Awards granted 7,785 171,749 305,257 67,093 85,906 Fair market value of award $2.74 $5.95 $13.18 $0.81 $2.16 Expected life of award 1.50 years 2.04 years 1.54 years 1.05 years 0.54 years Risk-free interest rate 0.80% 1.08% 0.82% 0.65% 0.54% Annualized volatility rate 33.4% 33.4% 33.4% 33.4% 33.4% Dividend yield 0.20% 0.20% 0.20% 0.20% 0.20% |
Schedule of Incentive Units Activity | A summary of Petrotech unit activity as of December 31, 2015 , and transactions during the years ended December 31, 2015 , 2014 and 2013 are presented below: Petrotech Incentive Plan Shares Outstanding at December 31, 2012 141,243 Granted (three-year vesting period) 92,418 Granted (17 month vesting period) 2,952 Paid (36,792 ) Forfeited (26,529 ) Outstanding at December 31, 2013 173,292 Granted 76,084 Paid (4,431 ) Forfeited (31,075 ) Outstanding at December 31, 2014 213,870 Granted (three-year vesting period) 128,519 Granted (two-year vesting period) 297 Granted (16 month vesting period) 1,648 Paid (78,430 ) Forfeited (22,158 ) Outstanding at December 31, 2015 243,746 |
Derivative Commodity Instrume36
Derivative Commodity Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Gain (Loss) on Derivative Instruments | The following table details gain (loss) on derivative instruments, net, as follows: Years ended December 31, (in thousands) 2015 2014 2013 Open non-cash mark-to-market gains (losses) on derivative instruments $ (281,752 ) $ 315,445 $ (47,832 ) Closed gains (losses) on derivative instruments 397,045 19,574 (2,192 ) Gain (loss) on derivative instruments, net $ 115,293 $ 335,019 $ (50,024 ) |
Schedule of Derivative Assets and Liabilities at Fair Value | The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets: (in thousands) December 31, 2015 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amount 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 $ 72,563 $ (15,600 ) $ 56,963 $ — $ — $ 56,963 Liabilities Derivative instruments 16,059 (15,600 ) 459 — — 459 Total derivatives $ 56,504 $ — $ 56,504 $ — $ — $ 56,504 (in thousands) December 31, 2014 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amount 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 $ 339,977 $ (17,640 ) $ 322,337 $ — $ — $ 322,337 Liabilities Derivative instruments 18,628 (17,640 ) 988 — — 988 Total derivatives $ 321,349 $ — $ 321,349 $ — $ — $ 321,349 *All derivative instruments were current at December 31, 2015 and 2014. The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis: December 31, 2015 (in thousands) Level 2 Level 3 Total Assets Derivative instruments $ 69,864 $ (12,901 ) $ 56,963 Liabilities Derivative instruments 2,699 (3,158 ) (459 ) Net derivative asset (liability) $ 72,563 $ (16,059 ) $ 56,504 December 31, 2014 (in thousands) Level 2 Level 3 Total Assets Derivative instruments $ 294,865 $ 27,472 $ 322,337 Liabilities Derivative instruments 2,048 (3,036 ) (988 ) Net derivative asset $ 296,913 $ 24,436 $ 321,349 |
Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location | The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements: Years ended December 31, (in thousands) Location on Statements of Income 2014 2013 Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $23 and ($6,660) — $ 37 $ (10,866 ) Gain reclassified from accumulated other comprehensive income into income (effective portion) Gain (loss) on derivative instruments, net $ 21,612 $ 34,293 Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing) Gain (loss) on derivative instruments, net $ — $ 835 |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location | The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement: Years ended December 31, (in thousands) Location on Statements of Income 2015 2014 2013 Gain (loss) recognized in income on derivatives Gain (loss) on derivative instruments, net $ 115,293 $ 313,408 $ (73,980 ) |
Schedule of Hedging Transactions | As of December 31, 2015, Energen entered into the following transactions for 2016 and subsequent years: Production Period Total Hedged Volumes Average Contract Price Description Oil 2016 1,086 MBbl $63.80 Bbl NYMEX Swaps Oil Basis Differential 2016 7,524 MBbl $(1.92) Bbl WTI/WTI Basis Swaps 2016 2,117 MBbl $(1.63) Bbl WTS/WTI Basis Swaps WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Schedule of Derivative Liabilities at Fair Value | The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets: (in thousands) December 31, 2015 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amount 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 $ 72,563 $ (15,600 ) $ 56,963 $ — $ — $ 56,963 Liabilities Derivative instruments 16,059 (15,600 ) 459 — — 459 Total derivatives $ 56,504 $ — $ 56,504 $ — $ — $ 56,504 (in thousands) December 31, 2014 Gross Amounts Not Offset in the Balance Sheets Gross Amounts Recognized at Fair Value Gross Amounts Offset in the Balance Sheets Net Amount 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 $ 339,977 $ (17,640 ) $ 322,337 $ — $ — $ 322,337 Liabilities Derivative instruments 18,628 (17,640 ) 988 — — 988 Total derivatives $ 321,349 $ — $ 321,349 $ — $ — $ 321,349 *All derivative instruments were current at December 31, 2015 and 2014. The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis: December 31, 2015 (in thousands) Level 2 Level 3 Total Assets Derivative instruments $ 69,864 $ (12,901 ) $ 56,963 Liabilities Derivative instruments 2,699 (3,158 ) (459 ) Net derivative asset (liability) $ 72,563 $ (16,059 ) $ 56,504 December 31, 2014 (in thousands) Level 2 Level 3 Total Assets Derivative instruments $ 294,865 $ 27,472 $ 322,337 Liabilities Derivative instruments 2,048 (3,036 ) (988 ) Net derivative asset $ 296,913 $ 24,436 $ 321,349 |
Schedule of Changes in Fair Value of Derivative Instruments Classified as Level 3 | The table below sets forth a summary of changes in the fair value of Energen’s Level 3 derivative commodity instruments as follows: Years ended December 31, (in thousands) 2015 2014 2013 Balance at beginning of period $ 24,436 $ 18,289 $ 89,019 Realized gains 13,145 22,208 55,210 Unrealized gains (losses) relating to instruments held at the reporting date* (40,495 ) 2,981 (71,367 ) Settlements during period (13,145 ) (19,042 ) (54,573 ) Balance at end of period $ (16,059 ) $ 24,436 $ 18,289 *Includes $16.1 million in mark-to-market losses, $20.2 million in mark-to-market gains and $7.6 million in mark-to-market losses for the years ended December 31, 2015, 2014 and 2013, respectively. |
Schedule of Level Three Fair Value Measurements of Derivative Commodity Instruments | The tables below set 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 December 31, 2015 Valuation Technique* Unobservable Input* Range Oil Basis - WTI/WTI 2016 $ (13,181 ) Discounted Cash Flow Forward Basis ($0.07 - $0.28) Bbl Oil Basis - WTS/WTI 2016 $ (2,878 ) Discounted Cash Flow Forward Basis ($0.19 - $0.31) Bbl *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. |
Exploratory Costs (Tables)
Exploratory Costs (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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: Years ended December 31, (in thousands) 2015 2014 2013 Capitalized exploratory well costs at beginning of period $ 119,439 $ 57,600 $ 79,791 Additions pending determination of proved reserves 634,908 946,751 421,599 Reclassifications due to determination of proved reserves (650,759 ) (882,254 ) (442,909 ) Exploratory well costs charged to expense — (2,658 ) (881 ) Capitalized exploratory well costs at end of period $ 103,588 $ 119,439 $ 57,600 The following table sets forth capitalized exploratory wells costs: (in thousands) December 31, 2015 December 31, 2014 Exploratory wells in progress (drilling rig not released) $ 1,760 $ 18,781 Capitalized exploratory well costs for a period of one year or less 101,828 100,658 Total capitalized exploratory well costs $ 103,588 $ 119,439 |
Reconciliation of Earnings Pe39
Reconciliation of Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share Reconciliation | Years ended December 31, (in thousands, except per share amounts) 2015 2014 2013 Net Loss Shares Per Share Amount Net Income Shares Per Share Amount Net Income Shares Per Share Amount Basic EPS $ (945,731 ) 76,078 $ (12.43 ) $ 568,032 72,897 $ 7.79 $ 204,554 72,318 $ 2.83 Effect of dilutive securities Stock options — 216 112 Non-vested restricted stock — 58 20 Performance share awards — 104 21 Diluted EPS $ (945,731 ) 76,078 $ (12.43 ) $ 568,032 73,275 $ 7.75 $ 204,554 72,471 $ 2.82 |
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share | Energen had the following shares that were excluded from the computation of diluted EPS, as inclusion would be anti-dilutive. Years ended December 31, (in thousands) 2015 2014 2013 Stock options 114 114 134 Non-vested restricted stock — 3 7 Performance share awards — 2 4 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Minimum Future Rental Payments | Minimum future rental payments required after 2015 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows: Years Ending December 31, (in thousands) 2016 2017 2018 2019 2020 2021 and thereafter $2,537 $2,574 $2,537 $2,431 $— $— |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation | The following table reflects the components of the change in Energen’s ARO balance: (in thousands) Balance as of December 31, 2012 $ 118,023 Liabilities incurred 2,772 Liabilities settled (5,525 ) Accretion expense (including discontinued operations of $1,197) 8,192 Reclassification associated with held for sale properties* (14,929 ) Balance as of December 31, 2013 108,533 Liabilities incurred 2,266 Liabilities settled (1,543 ) Accretion expense (including discontinued operations of $251) 7,859 Revision in estimated cash flows 692 Reclassification associated with held for sale properties** (23,747 ) Balance as of December 31, 2014 $ 94,060 Liabilities incurred 981 Liabilities settled (686 ) Accretion expense 7,108 Reclassification associated with held for sale properties*** (11,473 ) Balance as of December 31, 2015 $ 89,990 *Asset retirement obligation associated with North Louisiana/East Texas properties. **Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2014. ***Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2015. |
Asset Impairment (Tables)
Asset Impairment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Impairment of Long-Lived Assets Held and Used by Asset | Impairments recognized by Energen during the years ended December 31, 2015, 2014 and 2013 are presented below: Years ended December 31, (in thousands) 2015 2014 2013 Continuing operations Permian Basin properties Central Basin Platform $ 484,848 $ — $ — Delaware Basin 607,303 90,594 — Midland Basin — 25,776 — San Juan Basin properties 133,055 230,315 — Permian Basin unproved leasehold properties 29,168 64,361 13,906 San Juan Basin unproved leasehold properties 37,934 5,755 — Total asset impairments from continuing operations 1,292,308 416,801 13,906 Discontinued operations North Louisiana/East Texas oil and natural gas properties — 1,936 29,794 Total asset impairments from discontinued operations — 1,936 29,794 Total asset impairments $ 1,292,308 $ 418,737 $ 43,700 |
Discontinued Operations and H43
Discontinued Operations and Held for Sale Properties (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Schedule of Discontinued Operations | The following table details San Juan Basin held for sale properties by major classes of assets and liabilities. Property sales in the San Juan Basin do not qualify for discontinued operations: (in thousands) December 31, 2015 December 31, 2014 Inventories $ 3,651 $ — Oil and natural gas properties 305,386 1,166,124 Less accumulated depreciation, depletion and amortization (219,059 ) (770,327 ) Other property and equipment, net 3,761 — Total assets held for sale 93,739 395,797 Other long-term liabilities (12,789 ) (24,230 ) Total liabilities held for sale (12,789 ) (24,230 ) Total net assets held for sale $ 80,950 $ 371,567 We classified as discontinued operations interest on debt required to be extinguished, certain depreciation costs that ended at close of transaction, the related income tax impact of these items and the earnings of Alagasco. In addition, we reclassified from discontinued operations certain general and administrative expenses, other income and the related tax impact from these items. The table below provides a detail of these items included in income (loss) from discontinued operations as follows: Years ended December 31, (in thousands) 2014 2013 Alagasco net income $ 40,646 $ 57,399 Depreciation, depletion and amortization (408 ) (598 ) General and administrative 3,337 5,894 Interest expense (17,306 ) (13,815 ) Other income (347 ) (1,342 ) Income tax expense 5,567 3,728 Alagasco income from discontinued operations 31,489 51,266 Energen income (loss) from discontinued operations (2,197 ) 7,813 Income from discontinued operations $ 29,292 $ 59,079 Years ended December 31, (in thousands, except per share data) 2014 2013 Natural gas distribution revenues $ 397,648 $ 533,338 Oil and natural gas revenues 5,199 60,191 Total revenues $ 402,847 $ 593,529 Pretax income from discontinued operations $ 47,220 $ 92,253 Income tax expense 17,928 33,174 Income From Discontinued Operations $ 29,292 $ 59,079 Gain on disposal of discontinued operations, net $ 724,594 $ 5,605 Income tax expense 285,497 2,011 Gain on Disposal of Discontinued Operations, net $ 439,097 $ 3,594 Total Income From Discontinued Operations $ 468,389 $ 62,673 Diluted Earnings Per Average Common Share Income from discontinued operations $ 0.40 $ 0.81 Gain on disposal of discontinued operations, net 5.99 0.05 Total Income From Discontinued Operations $ 6.39 $ 0.86 Basic Earnings Per Average Common Share Income from discontinued operations $ 0.40 $ 0.82 Gain on disposal of discontinued operations, net 6.02 0.05 Total Income From Discontinued Operations $ 6.42 $ 0.87 |
Supplemental Cash Flow Inform44
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Elements [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures | Supplemental information concerning Energen’s cash flow activities from continuing operations was as follows: Years ended December 31, (in thousands) 2015 2014 2013 Interest paid, net of amount capitalized $ 40,747 $ 32,172 $ 38,255 Income taxes paid $ 8,114 $ 219,505 $ 22,781 Noncash investing activities: Accrued development, exploration costs and other capital $ 79,206 $ 207,461 $ 93,623 Capitalized asset retirement obligations costs $ 981 $ 2,958 $ 2,772 Receivable from sale of Alabama Gas Corporation $ — $ 8,247 $ — Noncash financing activities: Issuance of common stock for employee benefit plans $ 5,758 $ 2,448 $ 1,015 Treasury stock acquired in connection with tax withholdings $ 4,722 $ 2,547 $ 977 |
Accumulated Other Comprehensi45
Accumulated Other Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Schedule of 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) Pension and Postretirement Plans Balance as of December 31, 2014 $ (22,870 ) Other comprehensive income before reclassifications 3,305 Amounts reclassified from accumulated other comprehensive income 19,828 Change in accumulated other comprehensive income (loss) 23,133 Balance as of December 31, 2015 $ 263 |
Reclassification out of Accumulated Other Comprehensive Income | The following table provides details of the reclassifications out of accumulated other comprehensive income (loss): Years ended December 31, (in thousands) 2015 2014 2013 Amounts Reclassified Line Item Where Presented Gains (losses) on cash flow hedges: Commodity contracts $ — $ 21,611 $ 35,684 Gain (loss) on derivative instruments, net Interest rate swap — (2,280 ) (1,723 ) Interest expense Total cash flow hedges — 19,331 33,961 Income tax expense — (7,414 ) (12,957 ) Net of tax — 11,917 21,004 Pension and postretirement plans: Transition obligation — (22 ) (319 ) General and administrative Prior service cost — (248 ) (257 ) General and administrative Actuarial losses (30,504 ) (21,932 ) (12,357 ) General and administrative Actuarial losses on settlement charges* — — (421 ) Assets held for sale Total pension and postretirement plans (30,504 ) (22,202 ) (13,354 ) Income tax benefit 10,676 7,771 4,674 Net of tax (19,828 ) (14,431 ) (8,680 ) Total reclassifications for the period $ (19,828 ) $ (2,514 ) $ 12,324 *During the year ended December 31, 2013, Energen incurred settlement charges of $0.6 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.2 million was recognized in actuarial losses above and $0.4 million was recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above. |
Summarized Quarterly Financia46
Summarized Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Operating Results | The following data summarizes quarterly operating results: Year ended December 31, 2015 (in thousands, except per share amounts) First Second Third Fourth Revenues $ 221,858 $ 168,326 $ 295,571 $ 192,799 Operating loss $ (12,409 ) $ (161,678 ) $ (348,214 ) $ (915,550 ) Loss from continuing operations $ (15,420 ) $ (111,601 ) $ (227,904 ) $ (590,806 ) Net loss $ (15,420 ) $ (111,601 ) $ (227,904 ) $ (590,806 ) Diluted earnings per average common share Continuing operations $ (0.21 ) $ (1.52 ) $ (2.89 ) $ (7.50 ) Net loss $ (0.21 ) $ (1.52 ) $ (2.89 ) $ (7.50 ) Basic earnings per average common share Continuing operations $ (0.21 ) $ (1.52 ) $ (2.89 ) $ (7.50 ) Net loss $ (0.21 ) $ (1.52 ) $ (2.89 ) $ (7.50 ) Year ended December 31, 2014 (in thousands, except per share amounts) First Second Third Fourth Revenues as originally reported $ 561,178 $ 270,097 $ 497,761 $ 611,435 Discontinued operations* (263,900 ) — — — Reclassification of loss on sale of assets and other 153 909 747 833 Adjusted revenues $ 297,431 $ 271,006 $ 498,508 $ 612,268 Operating income as originally reported $ 104,599 $ 3,107 $ 48,171 $ 94,223 Discontinued operations* (73,139 ) — — — Adjusted operating income $ 31,460 $ 3,107 $ 48,171 $ 94,223 Income (loss) from continuing operations $ 15,647 $ (3,154 ) $ 20,631 $ 66,519 Net income (loss) $ 53,316 $ (7,953 ) $ 457,251 $ 65,418 Diluted earnings per average common share Continuing operations $ 0.21 $ (0.04 ) $ 0.28 $ 0.91 Net income (loss) $ 0.73 $ (0.11 ) $ 6.22 $ 0.89 Basic earnings per average common share Continuing operations $ 0.22 $ (0.04 ) $ 0.28 $ 0.91 Net income (loss) $ 0.73 $ (0.11 ) $ 6.26 $ 0.90 *As discussed in Note 16, Discontinued Operations and Held for Sale Properties, during the third quarter of 2014, Energen completed the transaction to sell Alagasco to Laclede. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. |
Oil and Natural Gas Operation47
Oil and Natural Gas Operations (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Schedule of Capitalized Costs | The following table sets forth capitalized costs: (in thousands) December 31, 2015 December 31, 2014 Proved $ 7,911,554 $ 8,069,638 Unproved 150,674 142,340 Total capitalized costs 8,062,228 8,211,978 Accumulated depreciation, depletion and amortization 3,673,569 2,663,434 Capitalized costs, net $ 4,388,659 $ 5,548,544 |
Schedule of Cost Incurred in Property Acquisition, Exploration and Development Activities | The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year: Years ended December 31, (in thousands) 2015 2014 2013 Property acquisition: Proved $ 1,866 $ 2,582 $ 4,661 Unproved 85,690 68,514 26,820 Exploration 649,764 972,164 435,636 Development 372,177 408,949 655,353 Total costs incurred $ 1,109,497 $ 1,452,209 $ 1,122,470 |
Schedule of Results of Operations from Producing Activities | The following table sets forth results of Energen’s oil, natural gas liquids and natural gas operations from producing activities: Years ended December 31, (in thousands) 2015 2014 2013 Gross revenues* $ 878,554 $ 1,679,213 $ 1,206,293 Production (lifting costs) 285,760 376,495 351,541 Exploration expense 14,877 28,090 14,036 Depreciation, depletion and amortization including asset impairments 1,880,190 960,539 463,606 Accretion expense 7,108 7,608 6,995 Income tax expense (benefit) (469,362 ) 99,469 128,773 Results of operations from producing activities $ (840,019 ) $ 207,012 $ 241,342 * The years ended December 31, 2015, 2014 and 2013 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $281.8 million , a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million and a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million , respectively. |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserves | The independent reservoir engineers have issued reports covering approximately 99 percent of Energen’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate. Year ended December 31, 2015 Oil MBbl NGL MBbl Natural Gas MMcf Total MMBOE Proved reserves at beginning of period 181,227 73,463 707,926 372.7 Revisions of previous estimates (39,537 ) (11,979 ) (44,176 ) (58.9 ) Purchases 2 1 2 — Extensions and discoveries 83,319 25,530 143,022 132.6 Production (14,023 ) (4,065 ) (35,604 ) (24.0 ) Sales (297 ) (11,237 ) (337,266 ) (67.7 ) Proved reserves at end of period 210,691 71,713 433,904 354.7 Proved developed reserves at end of period 108,319 36,374 236,112 184.0 Proved undeveloped reserves at end of period 102,372 35,339 197,792 170.7 Year ended December 31, 2014 Oil MBbl NGL MBbl Natural Gas MMcf Total MMBOE Proved reserves at beginning of period 164,870 63,011 719,725 347.8 Revisions of previous estimates (48,548 ) (15,165 ) (71,806 ) (75.7 ) Purchases 88 26 116 0.1 Extensions and discoveries 76,722 29,695 141,209 130 Production (11,818 ) (4,104 ) (59,562 ) (25.8 ) Sales (87 ) — (21,756 ) (3.7 ) Proved reserves at end of period 181,227 73,463 707,926 372.7 Proved developed reserves at end of period 118,697 47,621 589,074 264.5 Proved undeveloped reserves at end of period 62,530 25,842 118,852 108.2 Year ended December 31, 2013 Oil MBbl NGL MBbl Natural Gas MMcf Total MMBOE Proved reserves at beginning of period 155,348 56,155 809,128 346.4 Revisions of previous estimates (680 ) 2,211 18,465 4.6 Purchases 142 56 282 0.2 Extensions and discoveries 20,517 7,823 50,568 36.8 Production (10,378 ) (3,233 ) (70,506 ) (25.4 ) Sales (79 ) (1 ) (88,212 ) (14.8 ) Proved reserves at end of period 164,870 63,011 719,725 347.8 Proved developed reserves at end of period 113,795 42,087 623,305 259.8 Proved undeveloped reserves at end of period 51,075 20,924 96,420 88.0 |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | Years ended December 31, (in thousands) 2015 2014 2013 Future gross revenues $ 11,714,729 $ 20,971,672 $ 19,509,305 Future production costs 4,353,974 7,532,273 6,136,709 Future development costs 1,961,661 1,784,738 1,896,602 Future income tax expense 1,065,887 3,440,582 3,209,697 Future net cash flows 4,333,207 8,214,079 8,266,297 Discount at 10% per annum 2,299,859 3,994,423 4,248,456 Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 2,033,348 $ 4,219,656 $ 4,017,841 |
Schedule of Principal Sources of Changes in Standardized Measure of Discounted Future Net Cash Flows | The following are the principal sources of changes in the standardized measure of discounted future net cash flows: Years ended December 31, (in thousands) 2015 2014 2013 Balance at beginning of year $ 4,219,656 $ 4,017,841 $ 3,699,319 Revisions to reserves proved in prior years: Net changes in prices, production costs and future development costs (2,861,591 ) (1,147,028 ) 566,838 Net changes due to revisions in quantity estimates (404,708 ) (1,285,394 ) (81,762 ) Development costs incurred, previously estimated 350,560 337,198 299,432 Accretion of discount 421,966 401,784 369,932 Changes in timing and other* (903,975 ) 987,652 (179,502 ) Total revisions (3,397,748 ) (705,788 ) 974,938 New field discoveries and extensions, net of future production and development costs 776,315 2,321,028 376,326 Sales of oil and gas produced, net of production costs (514,380 ) (1,054,553 ) (1,014,593 ) Purchases 8 4,241 4,690 Sales (372,039 ) (21,092 ) (24,876 ) Net change in income taxes 1,321,536 (342,021 ) 2,037 Net change in standardized measure of discounted future net cash flows (2,186,308 ) 201,815 318,522 Balance at end of year $ 2,033,348 $ 4,219,656 $ 4,017,841 *Amount represents changes in production timing and other. In 2015, the production timing is significantly affected by changes related to the delay of the drilling program. For 2014, the production timing is significantly affected by changes related to the acceleration of the horizontal drilling program and the delay of the vertical drilling program. |
Organization and Basis of Pre48
Organization and Basis of Presentation (Sale of Alabama Gas Corporation) (Details) - USD ($) $ in Thousands | Sep. 02, 2014 | Dec. 31, 2014 | Dec. 31, 2013 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Pre-tax gain on disposal of discontinued operations | $ 724,594 | $ 5,605 | |
Alabama Gas Corporation | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Disposal group, consideration | $ 1,600,000 | ||
Debt assumed | 267,000 | ||
Proceeds from sale | 1,320,000 | ||
Pre-tax gain on disposal of discontinued operations | $ 726,500 |
Organization and Basis of Pre49
Organization and Basis of Presentation (Additional Information) (Details) | Sep. 02, 2014 | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Oct. 20, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) |
Line of Credit Facility [Line Items] | ||||||
Cash | $ 1,272,000 | $ 1,852,000 | $ 2,523,000 | |||
Available for borrowings | 1,177,500,000 | 1,515,000,000 | ||||
Long-term debt, gross | 776,500,000 | 1,039,000,000 | ||||
Outstanding long-term debt | $ 776,500,000 | |||||
Syndicated Credit Facility | Credit Facility, September 2, 2014 | ||||||
Line of Credit Facility [Line Items] | ||||||
Credit facility | $ 1,400,000,000 | |||||
Debt instrument, term | 5 years | |||||
Debt covenant, debt to EBITDAX ratio | 4 | |||||
Medium-term Notes and Notes Payable, Other Payables [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Long-term debt, gross | $ 554,000,000 | |||||
Credit facility | Credit facility | ||||||
Line of Credit Facility [Line Items] | ||||||
Long-term debt, gross | $ 222,500,000 | $ 485,000,000 | ||||
One-time Termination Benefits | Subsequent Event | ||||||
Line of Credit Facility [Line Items] | ||||||
Incurred cost in connection with workforce reduction | $ 3,200,000 |
Summary of Significant Accoun50
Summary of Significant Accounting Policies (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Allowance for doubtful accounts receivable | $ 700,000 | $ 700,000 | |
Short-term investments | 0 | 0 | |
Excess tax benefit from share-based compensation | $ 1,100,000 | $ 5,900,000 | $ 3,100,000 |
Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Yield curve, term | 0 years | ||
Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Yield curve, term | 30 years |
Long-Term Debt (Schedule of Lon
Long-Term Debt (Schedule of Long-Term Debt) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||
Long-term debt, gross | $ 776,500 | $ 1,039,000 |
Less unamortized debt discount | 413 | 437 |
Long-term debt | 776,087 | 1,038,563 |
Credit facility | Credit facility | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | 222,500 | 485,000 |
Medium-term Notes | 7.40% Medium-term Notes, Series A, due July 24, 2017 | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | $ 2,000 | $ 2,000 |
Debt instrument, interest rate | 7.40% | 7.40% |
Medium-term Notes | 7.36% Medium-term Notes, Series A, due July 24, 2017 | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | $ 15,000 | $ 15,000 |
Debt instrument, interest rate | 7.36% | 7.36% |
Medium-term Notes | 7.23% Medium-term Notes, Series A, due July 28, 2017 | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | $ 2,000 | $ 2,000 |
Debt instrument, interest rate | 7.23% | 7.23% |
Medium-term Notes | 7.32% Medium-term Notes, Series A, due July 28, 2022 | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | $ 20,000 | $ 20,000 |
Debt instrument, interest rate | 7.32% | 7.32% |
Medium-term Notes | 7.60% Medium-term Notes, Series A, due July 26, 2027 | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | $ 5,000 | $ 5,000 |
Debt instrument, interest rate | 7.60% | 7.60% |
Medium-term Notes | 7.35% Medium-term Notes, Series A, due July 28, 2027 | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | $ 10,000 | $ 10,000 |
Debt instrument, interest rate | 7.35% | 7.35% |
Medium-term Notes | 7.125% Medium-term Notes, Series B, due February 15, 2028 | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | $ 100,000 | $ 100,000 |
Debt instrument, interest rate | 7.125% | 7.125% |
Notes | 4.625% Notes, due September 1, 2021 | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | $ 400,000 | $ 400,000 |
Debt instrument, interest rate | 4.625% | 4.625% |
Long-Term Debt (Aggregate Matur
Long-Term Debt (Aggregate Maturities) (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Maturities of Long-term Debt [Abstract] | |
2,016 | $ 0 |
2,017 | 19,000 |
2,018 | 0 |
2,019 | 222,500 |
2,020 | 0 |
Thereafter | $ 535,000 |
Long-Term Debt (Additional Info
Long-Term Debt (Additional Information) (Details) - USD ($) | Sep. 02, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Oct. 20, 2015 |
Debt Instrument [Line Items] | |||||
Cross default provision, minimum threshold amount | $ 10,000,000 | ||||
Loan limit percentage (less than) | 10.00% | ||||
Cross default provision, minimum debt default amount | $ 75,000,000 | ||||
Interest expense | 43,108,000 | $ 37,771,000 | $ 39,736,000 | ||
Amortization of debt issuance costs | $ 3,300,000 | 5,700,000 | 2,000,000 | ||
Interest expense, capitalized | $ 200,000 | $ 200,000 | |||
Unused capacity, commitment fee percentage | 0.30% | ||||
Syndicated Credit Facility | Credit Facility, September 2, 2014 | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, term | 5 years | ||||
Credit facility | $ 1,400,000,000 | ||||
Debt covenant, debt to EBITDAX ratio | 4 | ||||
Debt covenant, current assets to current liabilities ratio | 1 | ||||
Debt covenant, minimum net present value of proved reserves to consolidated debt, ratio | 1.50 |
Long-Term Debt (Lines of Credit
Long-Term Debt (Lines of Credit) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Line of Credit Facility [Abstract] | ||
Credit facility outstanding | $ 222,500 | $ 485,000 |
Available for borrowings | 1,177,500 | 1,515,000 |
Total borrowing commitments | 1,400,000 | 2,000,000 |
Maximum amount outstanding at any month-end | 685,000 | 750,000 |
Average daily amount outstanding | $ 358,929 | $ 482,166 |
Average daily amount outstanding | 1.60% | 1.46% |
Amount outstanding at year-end | 1.64% | 1.67% |
Income Taxes (Components of Inc
Income Taxes (Components of Income Taxes) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Taxes estimated to be payable currently: | |||
Federal | $ 3,972 | $ 161,576 | $ 23,342 |
State | 758 | 72,379 | 2,516 |
Total current | 4,730 | 233,955 | 25,858 |
Taxes deferred: | |||
Federal | (513,187) | 144,645 | 85,950 |
State | (26,548) | (34,447) | (2,300) |
Total deferred | (539,735) | 110,198 | 83,650 |
Total income tax expense (benefit) | $ (535,005) | $ 344,153 | $ 109,508 |
Income Taxes (Components of I56
Income Taxes (Components of Income Taxes, Continuing and Discontinued Operations) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Disclosure [Abstract] | |||
Income tax expense (benefit) from continuing operations | $ (535,005) | $ 40,728 | $ 74,323 |
Income tax expense from discontinued operations | 0 | 17,928 | 33,174 |
Income tax expense from gain on disposal of discontinued operations | 0 | 285,497 | 2,011 |
Total income tax expense (benefit) | $ (535,005) | $ 344,153 | $ 109,508 |
Income Taxes (Deferred Tax Asse
Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Income Tax Contingency [Line Items] | ||
Full valuation allowance | $ 4,200 | |
Deferred tax assets: | ||
Total deferred tax assets, Current | 0 | $ 25,533 |
Total deferred tax assets, Noncurrent | 81,804 | 70,320 |
Valuation allowance, Current | 0 | (1,122) |
Valuation allowance, Noncurrent | (4,235) | (2,467) |
Total deferred tax assets, net, Current | 0 | 24,411 |
Total deferred tax assets, net, Noncurrent | 77,569 | 67,853 |
Deferred tax liabilities: | ||
Total deferred tax liabilities, current | 0 | 103,575 |
Total deferred tax liabilities, noncurrent | 629,938 | 1,068,339 |
Deferred tax liabilities, net, current | 0 | (79,164) |
Deferred tax liabilities, net, noncurrent | (552,369) | (1,000,486) |
Oil and Gas Operations | ||
Income Tax Contingency [Line Items] | ||
State operating loss carryforwards and other tax carryforwards portion about to expire | 191,300 | |
Deferred tax assets, Current | ||
Deferred tax assets: | ||
Minimum tax credit | 0 | 0 |
Allowance for doubtful accounts | 0 | 244 |
Insurance and other accruals | 0 | 2,537 |
Compensation accruals | 0 | 11,355 |
Pension and other costs | 0 | 0 |
Other comprehensive income | 0 | 10,732 |
State net operating losses and other carryforwards | 0 | 0 |
Other | 0 | 665 |
Deferred tax assets, Noncurrent | ||
Income Tax Contingency [Line Items] | ||
State net operating loss carryforwards, subject to expiration | 8,400 | |
Deferred tax assets: | ||
Minimum tax credit | 44,862 | 46,338 |
Allowance for doubtful accounts | 253 | 0 |
Insurance and other accruals | 2,807 | 0 |
Compensation accruals | 11,650 | 0 |
Pension and other costs | 8,693 | 7,009 |
Other comprehensive income | 0 | 1,581 |
State net operating losses and other carryforwards | 12,577 | 15,392 |
Other | 962 | 0 |
Deferred tax liabilities, Current | ||
Deferred tax liabilities: | ||
Depreciation and basis differences | 0 | 0 |
Derivative instruments | 0 | 102,691 |
Other comprehensive income | 0 | 0 |
Other | 0 | 884 |
Deferred tax liabilities, Noncurrent | ||
Deferred tax liabilities: | ||
Depreciation and basis differences | 620,629 | 1,057,430 |
Derivative instruments | 2,838 | 0 |
Other comprehensive income | 141 | 0 |
Other | 6,330 | $ 10,909 |
New Accounting Pronouncement, Early Adoption, Effect | ||
Income Tax Contingency [Line Items] | ||
Amount of reclassified current deferred tax asset | (14,500) | |
Deferred tax liabilities: | ||
Deferred tax liabilities, net, noncurrent | $ (14,500) |
Income Taxes (Effective Income
Income Taxes (Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Disclosure [Abstract] | |||||
Statutory federal income tax rate | 35.00% | 35.00% | 35.00% | ||
Income tax expense (benefit) at statutory federal income tax rate | $ (518,258) | $ 49,130 | $ 75,671 | ||
State income taxes, net of federal income tax benefit | (14,112) | 93 | 1,461 | ||
Impact of state law changes | (3,075) | (121) | (1,966) | ||
Impact of state deferred tax revaluation on San Juan properties | $ 1,200 | $ 8,400 | (1,241) | (8,382) | 0 |
401(k) stock dividend deduction | 0 | (232) | (449) | ||
Other, net | 1,681 | 240 | (394) | ||
Total income tax expense (benefit) | $ (535,005) | $ 40,728 | $ 74,323 | ||
Effective income tax rate (%) | 36.13% | 29.01% | 34.38% |
Income Taxes (Unrecognized Tax
Income Taxes (Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Unrecognized Tax Benefits, Beginning Balance | $ 17,530 | $ 15,986 | $ 12,555 |
Additions based on tax positions related to the current year | 2,378 | 3,873 | 4,546 |
Additions for tax positions of prior years | 19 | 366 | |
Reductions based on tax positions related to the current year | (6,589) | ||
Reductions for tax positions of prior years | (345) | (954) | (46) |
Lapse of statute of limitations | (1,785) | (1,394) | (1,435) |
Unrecognized Tax Benefits, Ending Balance | 11,189 | 17,530 | 15,986 |
Unrecognized tax benefits that would impact effective tax rate | 3,000 | ||
Income tax interest expense (income) net of tax benefit and penalties | (2) | 27 | $ 15 |
Accrued interest (net of tax benefit) and penalties payments | $ 200 | $ 200 |
Employee Benefit Plans (Benefit
Employee Benefit Plans (Benefit Obligations) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Benefit obligation: | ||||
Termination benefit charge | $ 2,500 | |||
Amounts recognized in balance sheet | ||||
Noncurrent assets | 0 | $ 3,881 | $ 0 | |
Noncurrent liabilities | (15,935) | 0 | (15,935) | |
Amounts recognized to accumulated other comprehensive income: | ||||
Total accumulated other comprehensive income (loss) | 22,870 | (263) | 22,870 | |
Nonqualified Supplemental Retirement Plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Reclassification of assets | 3,300 | |||
Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Accumulated benefit obligation | 107,669 | 15,729 | 107,669 | |
Benefit obligation: | ||||
Balance at beginning of period | 107,669 | 266,294 | ||
Service cost | 0 | 8,329 | ||
Interest cost | 816 | 5,325 | ||
Actuarial (gain) loss | (683) | 9,078 | ||
Plan amendments | 0 | 0 | ||
Curtailment gain | 0 | (8,496) | ||
Transfer in connection with the sale of Alagasco | 0 | (124,783) | ||
Termination benefit charge | 0 | 2,477 | $ 0 | |
Retiree drug subsidy program | 0 | 0 | ||
Benefits paid | (92,073) | (50,555) | ||
Balance at end of period | 107,669 | 15,729 | 107,669 | 266,294 |
Plan assets: | ||||
Fair value of plan assets at beginning of period | 67,542 | 193,457 | ||
Actual return (loss) on plan assets | (289) | 5,359 | ||
Employer contributions | 24,847 | 19,164 | ||
Transfer in connection with the sale of Alagasco | 0 | (99,883) | ||
Benefits paid | (92,073) | (50,555) | ||
Fair value of plan assets at end of period | 67,542 | 27 | 67,542 | 193,457 |
Funded status of plans | (40,127) | (15,702) | (40,127) | |
Amounts recognized in balance sheet | ||||
Noncurrent assets | 0 | 0 | 0 | |
Current liabilities | (24,626) | (15,702) | (24,626) | |
Noncurrent liabilities | (15,501) | 0 | (15,501) | |
Net asset (liability) recognized | (40,127) | (15,702) | (40,127) | |
Amounts recognized to accumulated other comprehensive income: | ||||
Prior service credit, net of taxes | 0 | 0 | 0 | |
Net actuarial loss, net of taxes | 22,246 | 2,179 | 22,246 | |
Total accumulated other comprehensive income (loss) | 22,246 | 2,179 | 22,246 | |
Postretirement Benefits | ||||
Benefit obligation: | ||||
Balance at beginning of period | 11,127 | 33,224 | ||
Service cost | 392 | 262 | ||
Interest cost | 466 | 716 | ||
Actuarial (gain) loss | (1,185) | 6,385 | ||
Plan amendments | (4,071) | 0 | ||
Curtailment gain | 0 | 0 | ||
Transfer in connection with the sale of Alagasco | 0 | (28,648) | ||
Termination benefit charge | 0 | 0 | ||
Retiree drug subsidy program | 0 | 48 | ||
Benefits paid | (241) | (860) | ||
Balance at end of period | 11,127 | 6,488 | 11,127 | 33,224 |
Plan assets: | ||||
Fair value of plan assets at beginning of period | 10,693 | 55,459 | ||
Actual return (loss) on plan assets | (83) | (331) | ||
Employer contributions | 0 | 21 | ||
Transfer in connection with the sale of Alagasco | 0 | (43,596) | ||
Benefits paid | (241) | (860) | ||
Fair value of plan assets at end of period | 10,693 | 10,369 | 10,693 | $ 55,459 |
Funded status of plans | (434) | 3,881 | (434) | |
Amounts recognized in balance sheet | ||||
Noncurrent assets | 0 | 3,881 | 0 | |
Current liabilities | 0 | 0 | 0 | |
Noncurrent liabilities | (434) | 0 | (434) | |
Net asset (liability) recognized | (434) | 3,881 | (434) | |
Amounts recognized to accumulated other comprehensive income: | ||||
Prior service credit, net of taxes | 0 | (2,646) | 0 | |
Net actuarial loss, net of taxes | 624 | 205 | 624 | |
Total accumulated other comprehensive income (loss) | $ 624 | $ (2,441) | $ 624 |
Employee Benefit Plans (Other I
Employee Benefit Plans (Other Investment Assets) (Details) - Nonqualified Supplemental Retirement Plans - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | $ 3,308 | $ 14,184 |
Fixed income | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 4,255 | |
Cash and cash equivalents | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 3,308 | 9,929 |
Level 1 | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 3,308 | 9,929 |
Level 1 | Fixed income | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 0 | |
Level 1 | Cash and cash equivalents | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 3,308 | 9,929 |
Level 2 | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 0 | 4,255 |
Level 2 | Fixed income | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | 4,255 | |
Level 2 | Cash and cash equivalents | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair value of plan assets | $ 0 | $ 0 |
Employee Benefit Plans (Net Per
Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Components of net periodic benefit cost: | ||||
Termination benefit charge | $ 2,500 | |||
Pension Benefits | ||||
Components of net periodic benefit cost: | ||||
Service cost | $ 0 | $ 8,329 | ||
Interest cost | 816 | 5,325 | ||
Expected long-term return on assets | 0 | (4,386) | $ (5,225) | |
Prior service cost amortization | 0 | 202 | 246 | |
Actuarial loss amortization | 737 | 4,995 | 6,919 | |
Termination benefit charge | 0 | 2,477 | 0 | |
Settlement charge | 29,767 | 4,082 | 161 | |
Curtailment expense (gain) | 0 | 254 | (4) | |
Net periodic expense | 31,320 | 18,930 | 11,789 | |
Postretirement Benefits | ||||
Components of net periodic benefit cost: | ||||
Service cost | 392 | 262 | ||
Interest cost | 466 | 716 | ||
Expected long-term return on assets | (457) | (1,122) | (787) | |
Actuarial loss amortization | 0 | (653) | (28) | |
Termination benefit charge | 0 | 0 | ||
Transition obligation amortization | 0 | 44 | 229 | |
Net periodic expense | 401 | (817) | 445 | |
Continuing Operations | Pension Benefits | ||||
Components of net periodic benefit cost: | ||||
Service cost | 0 | 6,808 | 5,196 | |
Interest cost | 816 | 4,498 | 4,496 | |
Continuing Operations | Postretirement Benefits | ||||
Components of net periodic benefit cost: | ||||
Service cost | 392 | 253 | 386 | |
Interest cost | $ 466 | $ 661 | $ 645 |
Employee Benefit Plans (Other C
Employee Benefit Plans (Other Comprehensive Income) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||||||
Termination benefit charge | $ 2,500 | |||||
Pension Benefits | ||||||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||||||
Net actuarial (gain) loss experienced during the year | $ (394) | $ 10,495 | $ (14,138) | |||
Net actuarial loss recognized as expense | (30,478) | (25,433) | (8,934) | |||
Prior service cost recognized as expense | 0 | (246) | (311) | |||
Curtailment loss | 0 | (8,749) | 0 | |||
Total recognized in other comprehensive income (loss) | (30,872) | (23,933) | (23,383) | |||
Settlement charges | 27,300 | 7,600 | ||||
Settlement charges expensed | 3,700 | |||||
Termination benefit charge | 0 | 2,477 | 0 | |||
Curtailment gain | 0 | 8,496 | ||||
Settlement charge | 29,767 | 4,082 | 161 | |||
Amortization of net actuarial loss | 3,352 | |||||
Postretirement Benefits | ||||||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||||||
Net actuarial (gain) loss experienced during the year | (645) | 7,649 | (8,057) | |||
Net actuarial loss recognized as expense | 0 | 1,908 | 550 | |||
Prior service cost recognized as expense | (4,071) | 0 | 0 | |||
Transition obligation recognized as expense | 0 | (48) | (283) | |||
Total recognized in other comprehensive income (loss) | (4,716) | 9,509 | (7,790) | |||
Termination benefit charge | 0 | 0 | ||||
Curtailment gain | 0 | 0 | ||||
Amortization of prior service credit | (515) | |||||
Nonqualified Supplemental Retirement Plans | ||||||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||||||
Settlement charges | $ 2,500 | 1,800 | 400 | 600 | ||
Settlement charges expensed | 200 | |||||
Long-term Disability Plan | ||||||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||||||
Expense related to long-term disability plan | $ 200 | $ 200 | 200 | |||
Alabama Gas Corporation | Nonqualified Supplemental Retirement Plans | ||||||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||||||
Settlement charges | $ 400 | |||||
Alagasco | ||||||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||||||
Curtailment gain | $ 300 | |||||
Black Warrior Basin | ||||||
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract] | ||||||
Curtailment gain | $ 1,200 |
Employee Benefit Plans (Assumpt
Employee Benefit Plans (Assumptions) (Details) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Plans | |||
One year spot rate | 0.70% | ||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Health care cost trend rate assumed for next year | 7.75% | 7.25% | |
Rate to which the cost trend rate is assumed to decline | 5.00% | 5.00% | |
Year that rate reaches ultimate rate | 2,026 | 2,021 | |
Pension Benefits | |||
Pension Plans | |||
Discount rate | 0.96% | 3.66% | 3.63% |
Expected long-term return on plan assets | 0.00% | 7.00% | 7.00% |
Rate of compensation increase for pay-related plans | 0.00% | 3.63% | 3.71% |
Postretirement Benefit Plans | |||
Discount rate | 3.90% | 0.96% | |
Postretirement Benefits | |||
Pension Plans | |||
Discount rate | 4.25% | 4.88% | 4.36% |
Expected long-term return on plan assets | 6.20% | 7.00% | 7.00% |
Rate of compensation increase for pay-related plans | 0.00% | 3.60% | 3.70% |
Postretirement Benefit Plans | |||
Discount rate | 4.70% | 4.25% |
Employee Benefit Plans (Allocat
Employee Benefit Plans (Allocation of Plan Assets) (Details) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Benefits | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation | 100.00% | |
Actual plan asset allocation | 100.00% | 100.00% |
Postretirement Benefits | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation | 100.00% | |
Actual plan asset allocation | 100.00% | 100.00% |
Equity securities | Pension Benefits | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation | 0.00% | |
Actual plan asset allocation | 0.00% | 0.00% |
Equity securities | Postretirement Benefits | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation | 56.00% | |
Actual plan asset allocation | 56.00% | 60.00% |
Debt securities | Pension Benefits | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation | 0.00% | |
Actual plan asset allocation | 0.00% | 0.00% |
Debt securities | Postretirement Benefits | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation | 44.00% | |
Actual plan asset allocation | 44.00% | 40.00% |
Cash and cash equivalents | Pension Benefits | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation | 100.00% | |
Actual plan asset allocation | 100.00% | 100.00% |
Cash and cash equivalents | Postretirement Benefits | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Target allocation | 0.00% | |
Actual plan asset allocation | 0.00% | 0.00% |
Employee Benefit Plans (Fair Va
Employee Benefit Plans (Fair Value of Plan Assets) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | $ 27 | $ 67,542 | $ 193,457 |
Pension Benefits | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 27 | 67,542 | |
Pension Benefits | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Pension Benefits | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 27 | 67,542 | |
Pension Benefits | Cash and cash equivalents | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 27 | 67,542 | |
Pension Benefits | Cash and cash equivalents | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 10,369 | 10,693 | $ 55,459 |
Postretirement Benefits | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 5,835 | 6,426 | |
Postretirement Benefits | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 4,534 | 4,267 | |
Postretirement Benefits | United States equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 4,185 | 4,715 | |
Postretirement Benefits | United States equities | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 4,185 | 4,715 | |
Postretirement Benefits | United States equities | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Postretirement Benefits | Global equities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 1,650 | 1,711 | |
Postretirement Benefits | Global equities | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 1,650 | 1,711 | |
Postretirement Benefits | Global equities | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Postretirement Benefits | Fixed income | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 4,534 | 4,267 | |
Postretirement Benefits | Fixed income | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Postretirement Benefits | Fixed income | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | $ 4,534 | $ 4,267 |
Employee Benefit Plans (Cash Fl
Employee Benefit Plans (Cash Flows) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Nonqualified Supplemental Retirement Plans | |
Defined Benefit Plan Disclosure [Line Items] | |
Anticipated required or discretionary contributions during in next fiscal year | $ 14,600 |
Pension Benefits | |
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract] | |
2,016 | 14,606 |
2,017 | 117 |
2,018 | 114 |
2,019 | 110 |
2,020 | 107 |
2021-2025 | 472 |
Postretirement Benefits | |
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract] | |
2,016 | 198 |
2,017 | 213 |
2,018 | 245 |
2,019 | 258 |
2,020 | 289 |
2021-2025 | $ 1,769 |
Common Stock Plans (Energen Emp
Common Stock Plans (Energen Employee Savings Plan) (Details) - Energen Employee Savings Plan - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Percentage of common stock that might be diversified into other investment options | 100.00% | ||
Expense associated with contributions to employee savings plan | $ 5.7 | $ 3.7 | $ 3.7 |
Common Stock Plans (Stock Incen
Common Stock Plans (Stock Incentive Plan) (Details) - Stock Incentive Plan - shares | Dec. 31, 2015 | Apr. 27, 2011 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of shares authorized for issuance | 8,600,000 | |
Number of shares remaining for issuance | 2,294,740 |
Common Stock Plans (Performance
Common Stock Plans (Performance Share Awards) (Details) - Performance share awards - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Weighted Average Price | |||
Share-based compensation expense | $ 6.7 | $ 6.2 | $ 3.8 |
Tax benefit related to stock-based compensation | 2.4 | $ 2.3 | $ 1.4 |
Unrecognized compensation cost | $ 8.9 | ||
Weighted average requisite service period | 1 year 7 months 28 days | ||
Stock Incentive Plan | |||
Shares | |||
Nonvested, Beginning of Period, Shares | 212,968 | 160,819 | 0 |
Forfeited, Shares | (8,008) | ||
Vested and paid, Shares | (77,257) | (14,097) | |
Nonvested, End of Period, Shares | 256,083 | 212,968 | 160,819 |
Weighted Average Price | |||
Nonvested, Beginning of Period, Weighted Average Price (in dollars per share) | $ 71.53 | $ 62.13 | $ 0 |
Forfeited, Weighted Average Price (in dollars per share) | 60.03 | ||
Vested and paid, Weighted Average Price (in dollars per share) | 61.36 | 70.06 | |
Nonvested, End of Period, Weighted Average Price (in dollars per share) | $ 80.43 | $ 71.53 | $ 62.13 |
Stock Incentive Plan | Two year vesting period | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation, vesting period | 2 years | ||
Shares | |||
Granted, Shares | 937 | 86,221 | |
Weighted Average Price | |||
Granted, Weighted Average Price (in dollars per share) | $ 131.56 | $ 61.14 | |
Stock Incentive Plan | Three year vesting period | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation, vesting period | 3 years | ||
Shares | |||
Granted, Shares | 120,372 | 65,309 | 82,606 |
Weighted Average Price | |||
Granted, Weighted Average Price (in dollars per share) | $ 83.94 | $ 93.49 | $ 62.96 |
Common Stock Plans (Restricted
Common Stock Plans (Restricted Stock) (Details) - Restricted Stock and Restricted Stock Units - Stock Incentive Plan - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | $ 6 | $ 3.2 | $ 1.9 |
Tax benefit related to stock-based compensation | 2.1 | $ 1.2 | $ 0.7 |
Unrecognized compensation cost | $ 1.9 | ||
Remaining requisite service period (in years) | 1 year 9 months | ||
Shares | |||
Nonvested, Beginning of Period, Shares | 99,574 | 62,518 | 11,115 |
Granted, Shares | 99,814 | 48,904 | 52,650 |
Forfeited, Shares | (1,247) | ||
Vested, Shares | (14,446) | (11,848) | |
Nonvested, End of Period, Shares | 184,942 | 99,574 | 62,518 |
Weighted Average Price | |||
Nonvested, Beginning of Period, Weighted Average Price (in dollars per share) | $ 59.60 | $ 51.16 | $ 45.24 |
Granted, Weighted Average Price (in dollars per share) | 65.15 | 71.91 | 52.34 |
Forfeited, Weighted Average Price (in dollars per share) | 48.36 | ||
Vested and paid, Weighted Average Price (in dollars per share) | 53.20 | 65.94 | |
Nonvested, End of Period, Weighted Average Price (in dollars per share) | $ 63.09 | $ 59.60 | $ 51.16 |
Common Stock Plans (Stock Optio
Common Stock Plans (Stock Options) (Details) - Stock Incentive Plan - $ / shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Shares | |||
Remaining reserved for issuance | 2,294,740 | ||
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation, vesting period | 3 years | ||
Share-based compensation, expiration period | 10 years | ||
Shares | |||
Outstanding, Beginning of Period, Shares | 757,071 | 1,191,044 | 1,648,475 |
Granted, Shares | 110,307 | 137,762 | |
Exercised, Shares | (23,680) | (544,280) | (590,119) |
Forfeited, Shares | (5,074) | ||
Outstanding, End of Period, Shares | 733,391 | 757,071 | 1,191,044 |
Exercisable, Shares | 622,156 | 454,938 | 713,445 |
Weighted Average Exercise Price | |||
Outstanding, Beginning of Period, Weighted Average Exercise Price (in dollars per share) | $ 54.88 | $ 51.06 | $ 47.58 |
Granted, Weighted Average Exercise Price (in dollars per share) | 72.55 | 49.22 | |
Exercised, Weighted Average Exercise Price (in dollars per share) | 41.42 | 50.09 | 40.92 |
Forfeited, Weighted Average Exercise Price (in dollars per share) | 51.85 | ||
Outstanding, End of Period, Weighted Average Exercise Price (in dollars per share) | 55.32 | 54.88 | 51.06 |
Exercisable, Weighted Average Exercise Price (in dollars per share) | $ 53.80 | $ 51.88 | $ 49.80 |
Common Stock Plans (Stock Opt73
Common Stock Plans (Stock Options, Valuation Assumptions) (Details) - Stock options - Stock Incentive Plan - $ / shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 110,307 | 137,762 | |
4/15/2014 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 2,439 | ||
Fair market value of stock option at grant (in dollars per share) | $ 32.22 | ||
Expected life of award | 5 years 9 months 18 days | ||
Risk-free interest rate | 1.93% | ||
Annualized volatility rate | 40.70% | ||
Dividend yield | 0.20% | ||
1/22/2014 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 107,868 | ||
Fair market value of stock option at grant (in dollars per share) | $ 27.57 | ||
Expected life of award | 5 years 9 months 18 days | ||
Risk-free interest rate | 2.06% | ||
Annualized volatility rate | 40.70% | ||
Dividend yield | 0.80% | ||
10/15/2013 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 3,686 | ||
Fair market value of stock option at grant (in dollars per share) | $ 30.53 | ||
Expected life of award | 5 years 9 months 18 days | ||
Risk-free interest rate | 1.79% | ||
Annualized volatility rate | 40.60% | ||
Dividend yield | 0.70% | ||
1/24/2013 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 134,076 | ||
Fair market value of stock option at grant (in dollars per share) | $ 16.66 | ||
Expected life of award | 5 years 9 months 18 days | ||
Risk-free interest rate | 1.01% | ||
Annualized volatility rate | 40.30% | ||
Dividend yield | 1.20% |
Common Stock Plans (Stock Opt74
Common Stock Plans (Stock Options, Textual) (Details) - Stock options - Stock Incentive Plan - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | $ 0.4 | $ 2.9 | $ 3.4 |
Tax benefit related to stock-based compensation | 0.1 | $ 1.1 | $ 1.3 |
Intrinsic value of stock options exercised during period | 0.7 | ||
Cash received from exercise of stock options | 1 | ||
Intrinsic value for outstanding options | 0.3 | ||
Intrinsic value for exercisable options | 0.3 | ||
Fair value of vested options | 3.7 | ||
Unrecognized compensation cost | $ 0.1 |
Common Stock Plans (Stock Opt75
Common Stock Plans (Stock Options, Range of Exercise Prices) (Details) | 12 Months Ended |
Dec. 31, 2015$ / sharesshares | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Weighted average remaining contractual life of exercisable stock options | 5 years 5 months 5 days |
Stock options | Stock Incentive Plan | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Number of outstanding options, Range of Exercise Prices, Lower Range Limit | $ 29.79 |
Number of outstanding options, Range of Exercise Prices, Upper Range Limit | $ 80.48 |
Shares | shares | 733,391 |
Weighted Average Remaining Contractual Life | 5 years 9 months 5 days |
Stock options | Stock Incentive Plan | $46.45 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of Exercise Prices | $ 46.45 |
Shares | shares | 19,990 |
Weighted Average Remaining Contractual Life | 1 year |
Stock options | Stock Incentive Plan | $60.56 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of Exercise Prices | $ 60.56 |
Shares | shares | 48,560 |
Weighted Average Remaining Contractual Life | 2 years |
Stock options | Stock Incentive Plan | $29.79 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of Exercise Prices | $ 29.79 |
Shares | shares | 24,291 |
Weighted Average Remaining Contractual Life | 3 years |
Stock options | Stock Incentive Plan | $46.69 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of Exercise Prices | $ 46.69 |
Shares | shares | 26,481 |
Weighted Average Remaining Contractual Life | 4 years |
Stock options | Stock Incentive Plan | $54.99 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of Exercise Prices | $ 54.99 |
Shares | shares | 104,841 |
Weighted Average Remaining Contractual Life | 5 years |
Stock options | Stock Incentive Plan | $54.11 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of Exercise Prices | $ 54.11 |
Shares | shares | 271,164 |
Weighted Average Remaining Contractual Life | 6 years |
Stock options | Stock Incentive Plan | $48.36 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of Exercise Prices | $ 48.36 |
Shares | shares | 124,071 |
Weighted Average Remaining Contractual Life | 7 years |
Stock options | Stock Incentive Plan | $80.48 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of Exercise Prices | $ 80.48 |
Shares | shares | 3,686 |
Weighted Average Remaining Contractual Life | 7 years 9 months 15 days |
Stock options | Stock Incentive Plan | $72.39 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of Exercise Prices | $ 72.39 |
Shares | shares | 107,868 |
Weighted Average Remaining Contractual Life | 8 years |
Stock options | Stock Incentive Plan | $79.63 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |
Range of Exercise Prices | $ 79.63 |
Shares | shares | 2,439 |
Weighted Average Remaining Contractual Life | 8 years |
Common Stock Plans (2004 Stock
Common Stock Plans (2004 Stock Appreciation Rights Plan) (Details) - Stock Appreciation Rights - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
2004 Stock Appreciation Rights Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Remaining requisite service period (in years) | 3 years | ||
Shares | |||
Outstanding, Beginning of Period, Shares | 275,150 | 377,377 | 653,030 |
Granted, Shares | 62,749 | 88,000 | |
Exercised/forfeited, Shares | (10,283) | (164,976) | (363,653) |
Outstanding, End of Period, Shares | 264,867 | 275,150 | 377,377 |
Weighted Average Exercise Price | |||
Outstanding, Beginning of Period, Weighted Average Exercise Price (in dollars per share) | $ 52.96 | $ 49.48 | $ 44.14 |
Granted, Weighted Average Exercise Price (in dollars per share) | 72.39 | 48.36 | |
Exercised/forfeited, Weighted Average Exercise Price (in dollars per share) | 55.18 | 52.37 | 39.66 |
Outstanding, End of Period, Weighted Average Exercise Price (in dollars per share) | $ 52.88 | $ 52.96 | $ 49.48 |
Stock Incentive Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Share-based compensation expense (income) | $ 3.2 | $ 0.4 | $ 9.9 |
Intrinsic value of stock options exercised during period | 0.1 | ||
Settlement of stock appreciation rights | $ 0.1 | ||
1/22/2014 | 2004 Stock Appreciation Rights Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 522 | ||
Fair market value of stock option at grant (in dollars per share) | $ 1.67 | ||
Expected life of award | 2 years 1 month 17 days | ||
Risk-free interest rate | 1.11% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% | ||
1/22/2014 | 2004 Stock Appreciation Rights Plan | Originally reported | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 62,227 | ||
Fair market value of stock option at grant (in dollars per share) | $ 5.11 | ||
Expected life of award | 4 years 6 months 22 days | ||
Risk-free interest rate | 1.67% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% | ||
1/24/2013 | 2004 Stock Appreciation Rights Plan | Originally reported | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 83,654 | ||
Fair market value of stock option at grant (in dollars per share) | $ 8.30 | ||
Expected life of award | 3 years 6 months 26 days | ||
Risk-free interest rate | 1.43% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% | ||
1/26/2011 | 2004 Stock Appreciation Rights Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 7,785 | ||
Fair market value of stock option at grant (in dollars per share) | $ 2.74 | ||
Expected life of award | 1 year 6 months | ||
Risk-free interest rate | 0.80% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% | ||
1/26/2011 | 2004 Stock Appreciation Rights Plan | Originally reported | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 182,199 | ||
Fair market value of stock option at grant (in dollars per share) | $ 4.80 | ||
Expected life of award | 2 years 6 months 10 days | ||
Risk-free interest rate | 1.23% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% | ||
1/27/2010 | 2004 Stock Appreciation Rights Plan | Originally reported | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 171,749 | ||
Fair market value of stock option at grant (in dollars per share) | $ 5.95 | ||
Expected life of award | 2 years 15 days | ||
Risk-free interest rate | 1.08% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% | ||
1/28/2009 | 2004 Stock Appreciation Rights Plan | Originally reported | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 305,257 | ||
Fair market value of stock option at grant (in dollars per share) | $ 13.18 | ||
Expected life of award | 1 year 6 months 15 days | ||
Risk-free interest rate | 0.82% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% | ||
2/4/2008 | 2004 Stock Appreciation Rights Plan | Originally reported | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 67,093 | ||
Fair market value of stock option at grant (in dollars per share) | $ 0.81 | ||
Expected life of award | 12 months 18 days | ||
Risk-free interest rate | 0.65% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% | ||
2/1/2007 | 2004 Stock Appreciation Rights Plan | Originally reported | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 85,906 | ||
Fair market value of stock option at grant (in dollars per share) | $ 2.16 | ||
Expected life of award | 6 months 16 days | ||
Risk-free interest rate | 0.54% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% | ||
San Juan Basin properties | 1/24/2013 | 2004 Stock Appreciation Rights Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 768 | ||
Fair market value of stock option at grant (in dollars per share) | $ 5.64 | ||
Expected life of award | 2 years 1 month 17 days | ||
Risk-free interest rate | 1.11% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% | ||
Black Warrior Basin | 1/24/2013 | 2004 Stock Appreciation Rights Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract] | |||
Awards granted | 3,578 | ||
Fair market value of stock option at grant (in dollars per share) | $ 4.24 | ||
Expected life of award | 1 year 6 months | ||
Risk-free interest rate | 0.80% | ||
Annualized volatility rate | 33.40% | ||
Dividend yield | 0.20% |
Common Stock Plans (Other Plans
Common Stock Plans (Other Plans) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Stock Equivalent Units | Petrotech Incentive Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding, Beginning of Period, Shares | 213,870 | 173,292 | 141,243 |
Granted | 76,084 | ||
Paid, Shares | (78,430) | (4,431) | (36,792) |
Forfeited | (22,158) | (31,075) | (26,529) |
Outstanding, End of Period, Shares | 243,746 | 213,870 | 173,292 |
Share-based compensation expense | $ 3 | $ 4.5 | $ 6.2 |
Stock Equivalent Units | Petrotech Incentive Plan | Three years vesting period | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Granted | 128,519 | 92,418 | |
Share-based compensation, vesting period | 3 years | 3 years | |
Stock Equivalent Units | Petrotech Incentive Plan | Two years vesting period | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Granted | 297 | ||
Share-based compensation, vesting period | 2 years | ||
Stock Equivalent Units | Petrotech Incentive Plan | 17-month vesting period | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Granted | 2,952 | ||
Share-based compensation, vesting period | 17 months | ||
Stock Equivalent Units | Petrotech Incentive Plan | 16-month vesting period | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Granted | 1,648 | ||
Share-based compensation, vesting period | 16 months | ||
Management | 1997 Deferred Compensation Plan | |||
Deferred Compensation Arrangements [Abstract] | |||
Deferred compensation, reserved for issuance | 576,850 | ||
Director | Stock options | 1992 Energen Corporation Directors Stock Plan | |||
Deferred Compensation Arrangements [Abstract] | |||
Granted, Shares | 11,550 | 10,360 | 13,500 |
Number of shares remaining for issuance | 116,374 |
Common Stock Plans (Stock Repur
Common Stock Plans (Stock Repurchase Program) (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Oct. 22, 2014 | |
Equity, Class of Treasury Stock [Line Items] | ||||
Purchase and retirement of shares, value | $ 14,913,000 | |||
Common Stock | ||||
Equity, Class of Treasury Stock [Line Items] | ||||
Stock repurchase program, authorized amount | $ 3,600,000 | |||
Stock repurchase program, remaining authorized repurchase amount | $ 3,373,161 | |||
Shares acquired in connection with stock compensation plans | 73,126 | 32,768 | 14,766 | |
Common Stock | ||||
Equity, Class of Treasury Stock [Line Items] | ||||
Purchase and retirement of shares, shares | 0 | 226,839 | 0 | |
Purchase and retirement of shares, value | $ 2,000 |
Derivative Commodity Instrume79
Derivative Commodity Instruments (Gain (Loss) on Derivative Instruments) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative [Line Items] | |||
Gain (loss) on derivative instruments, net | $ 115,293 | $ 335,019 | $ (50,024) |
Commodity contracts | |||
Derivative [Line Items] | |||
Open non-cash mark-to-market gains (losses) on derivative instruments | (281,752) | 315,445 | (47,832) |
Closed gains (losses) on derivative instruments | 397,045 | 19,574 | (2,192) |
Gain (loss) on derivative instruments, net | $ 115,293 | $ 335,019 | $ (50,024) |
Derivative Commodity Instrume80
Derivative Commodity Instruments (Offsetting of Derivative Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Assets | ||
Gross Amounts Recognized at Fair Value | $ 72,563 | $ 339,977 |
Gross Amounts Offset in the Balance Sheets | (15,600) | (17,640) |
Net Amount Presented in the Balance Sheets | 56,963 | 322,337 |
Financial Instruments | 0 | 0 |
Cash Collateral Received | 0 | 0 |
Net Fair Value Presented in the Balance Sheets | 56,963 | 322,337 |
Liabilities | ||
Gross Amounts Recognized at Fair Value | 16,059 | 18,628 |
Gross Amounts Offset in the Balance Sheets | (15,600) | (17,640) |
Net Amount Presented in the Balance Sheets | 459 | 988 |
Financial Instruments | 0 | 0 |
Cash Collateral Received | 0 | 0 |
Net Fair Value Presented in the Balance Sheets | 459 | 988 |
Total derivatives | $ 56,504 | $ 321,349 |
Derivative Commodity Instrume81
Derivative Commodity Instruments (Cash Flow Hedging Relationship in Financial Statements) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $23 and ($6,660) | $ 37 | $ (10,866) |
Gain (loss) recognized in other comprehensive income on derivatives | 23 | (6,660) |
Gain (Loss) on Derivative Instruments, Net | ||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | ||
Gain reclassified from accumulated other comprehensive income into income (effective portion) | 21,612 | 34,293 |
Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing) | $ 0 | $ 835 |
Derivative Commodity Instrume82
Derivative Commodity Instruments (Effect of Open and Closed Derivative Commodity Instruments Not Designated as Hedging Instruments) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Gain (Loss) on Derivative Instruments, Net | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Gain (loss) recognized in income on derivatives | $ 115,293 | $ 313,408 | $ (73,980) |
Derivative Commodity Instrume83
Derivative Commodity Instruments (Reclassification) (Details) - Crude Oil - Production Period, Year One | 12 Months Ended | |
Dec. 31, 2015MBbls$ / bbl | ||
NYMEX Swaps | ||
Derivatives, Fair Value [Line Items] | ||
Total Hedged Volumes | MBbls | 1,086 | |
Average Contract Price | $ / bbl | 63.80 | |
WTI/WTI Basis Swaps | ||
Derivatives, Fair Value [Line Items] | ||
Total Hedged Volumes | MBbls | 7,524 | [1] |
Average Contract Price | $ / bbl | (1.92) | [1] |
WTS/WTI Basis Swaps | ||
Derivatives, Fair Value [Line Items] | ||
Total Hedged Volumes | MBbls | 2,117 | [2] |
Average Contract Price | $ / bbl | (1.63) | [2] |
[1] | WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing | |
[2] | WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing |
Derivative Commodity Instrume84
Derivative Commodity Instruments (Additional Information) (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($)counterparty | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Derivative [Line Items] | |||
Number of Active Counterparties with Whom Company Holds Net Gain Positions | counterparty | 11 | ||
Counterparties with whom company holds net loss positions | counterparty | 1 | ||
Gain on fair value of derivatives | $ 115,293 | $ 335,019 | $ (50,024) |
Commodity contracts | |||
Derivative [Line Items] | |||
Gain on fair value of derivatives | 115,293 | $ 335,019 | $ (50,024) |
Morgan Stanley Capital Group | Commodity contracts | |||
Derivative [Line Items] | |||
Gain on fair value of derivatives | 18,100 | ||
BP Corporation North America, Inc. | Commodity contracts | |||
Derivative [Line Items] | |||
Gain on fair value of derivatives | $ 10,700 |
Fair Value Measurements (Deriva
Fair Value Measurements (Derivative Instruments, Fair Value) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Assets | ||
Derivative instruments | $ 56,963 | $ 322,337 |
Liabilities | ||
Derivative instruments | (459) | (988) |
Net derivative asset | 56,504 | 321,349 |
Level 2 | ||
Assets | ||
Derivative instruments | 69,864 | 294,865 |
Liabilities | ||
Derivative instruments | 2,699 | 2,048 |
Net derivative asset | 72,563 | 296,913 |
Level 3 | ||
Assets | ||
Derivative instruments | (12,901) | 27,472 |
Liabilities | ||
Derivative instruments | (3,158) | (3,036) |
Net derivative asset | $ (16,059) | $ 24,436 |
Fair Value Measurements (Deri86
Fair Value Measurements (Derivative Instruments Change in Fair Value of Level 3) (Details) - Derivative Commodity Instruments - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||||
Balance at beginning of period | $ 24,436 | $ 18,289 | $ 89,019 | |
Realized gains | 13,145 | 22,208 | 55,210 | |
Unrealized gains (losses) relating to instruments held at the reporting date | [1] | (40,495) | 2,981 | (71,367) |
Settlements during period | (13,145) | (19,042) | (54,573) | |
Balance at end of period | (16,059) | 24,436 | 18,289 | |
Mark-to-market gains (losses) | $ (16,100) | $ 20,200 | $ (7,600) | |
[1] | Includes $16.1 million in mark-to-market losses, $20.2 million in mark-to-market gains and $7.6 million in mark-to-market losses for the years ended December 31, 2015, 2014 and 2013, respectively. |
Fair Value Measurements (Level
Fair Value Measurements (Level 3 Fair Value Measurements of Derivative Commodity Instruments) (Details) - Crude Oil - 2015 - Level 3 $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($)$ / bbl | |
WTI/WTI Basis Swaps | |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Net derivative asset (liability), at fair value (in USD) | $ | $ (13,181) |
WTS/WTI Basis Swaps | |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Net derivative asset (liability), at fair value (in USD) | $ | $ (2,878) |
Discounted Cash Flow Valuation Technique | Minimum | WTI/WTI Basis Swaps | |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf) | 0.07 |
Discounted Cash Flow Valuation Technique | Minimum | WTS/WTI Basis Swaps | |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf) | 0.19 |
Discounted Cash Flow Valuation Technique | Maximum | WTI/WTI Basis Swaps | |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf) | 0.28 |
Discounted Cash Flow Valuation Technique | Maximum | WTS/WTI Basis Swaps | |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf) | 0.31 |
Fair Value Measurements (Additi
Fair Value Measurements (Additional Information) (Details) | 12 Months Ended | ||
Dec. 31, 2015USD ($)customer | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Concentration Risk [Line Items] | |||
Sale of short-term investments | $ 919,000,000 | $ 473,000,000 | $ 310,000,000 |
Impact of ten percent change in commodity prices | $ 100,000 | ||
Number of large customers | customer | 2 | ||
Plains Marketing | Accounts receivable | |||
Concentration Risk [Line Items] | |||
Concentration of credit risk (less than 9 percent) | 47.00% | ||
Plains Marketing | Total operating revenues | |||
Concentration Risk [Line Items] | |||
Concentration of credit risk (less than 9 percent) | 33.00% | ||
Shell Trading | Accounts receivable | |||
Concentration Risk [Line Items] | |||
Concentration of credit risk (less than 9 percent) | 21.00% | ||
Remaining Customer Concentration Risk | Accounts receivable | |||
Concentration Risk [Line Items] | |||
Concentration of credit risk (less than 9 percent) | 9.00% | ||
Reported Value Measurement | |||
Concentration Risk [Line Items] | |||
Fair value of long-term debt | $ 776,500,000 | 1,039,000,000 | |
Estimate of Fair Value Measurement | |||
Concentration Risk [Line Items] | |||
Fair value of long-term debt | 690,100,000 | 993,700,000 | |
Swap [Member] | Credit facility | |||
Concentration Risk [Line Items] | |||
Long-term debt | $ 66,667,000 | ||
Interest rate | 1.0425% | ||
Interest rate cash flow hedge liability at fair value | $ 200,000 | $ 800,000 |
Exploratory Costs (Capitalized
Exploratory Costs (Capitalized Exploratory Well Costs) (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($)well | Dec. 31, 2014USD ($)well | Dec. 31, 2013USD ($) | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | |||
Capitalized exploratory well costs at beginning of period | $ 119,439 | $ 57,600 | $ 79,791 |
Additions pending determination of proved reserves | 634,908 | 946,751 | 421,599 |
Reclassifications due to determination of proved reserves | (650,759) | (882,254) | (442,909) |
Exploratory well costs charged to expense | 0 | (2,658) | (881) |
Capitalized exploratory well costs at end of period | 103,588 | 119,439 | $ 57,600 |
Capitalized Exploratory Well Costs [Abstract] | |||
Exploratory wells in progress (drilling rig not released) | 1,760 | 18,781 | |
Capitalized exploratory well costs for a period of one year or less | 101,828 | 100,658 | |
Total capitalized exploratory well costs | $ 103,588 | $ 119,439 | |
Number of wells capitalized for a period greater than one year | well | 0 | 0 | |
Wells in process of drilling | well | 40 |
Reconciliation of Earnings Pe90
Reconciliation of Earnings Per Share (Reconciliation) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||||||||||
Net Income (Loss) | $ (590,806) | $ (227,904) | $ (111,601) | $ (15,420) | $ 65,418 | $ 457,251 | $ (7,953) | $ 53,316 | $ (945,731) | $ 568,032 | $ 204,554 |
Basic Shares Outstanding (in shares) | 76,078,371 | 72,896,579 | 72,317,865 | ||||||||
Basic earnings per average common share (in dollars per share) | $ (7.50) | $ (2.89) | $ (1.52) | $ (0.21) | $ 0.90 | $ 6.26 | $ (0.11) | $ 0.73 | $ (12.43) | $ 7.79 | $ 2.83 |
Effect of dilutive securities | |||||||||||
Net Income (Loss), Diluted EPS | $ (590,806) | $ (227,904) | $ (111,601) | $ (15,420) | $ 65,418 | $ 457,251 | $ (7,953) | $ 53,316 | $ (945,731) | $ 568,032 | $ 204,554 |
Diluted Shares Outstanding (in shares) | 76,078,371 | 73,274,631 | 72,470,622 | ||||||||
Diluted earnings per average common share (in dollars per share) | $ (7.50) | $ (2.89) | $ (1.52) | $ (0.21) | $ 0.89 | $ 6.22 | $ (0.11) | $ 0.73 | $ (12.43) | $ 7.75 | $ 2.82 |
Stock options | |||||||||||
Effect of dilutive securities | |||||||||||
Effect of dilutive securities | 0 | 216,000 | 112,000 | ||||||||
Non-vested restricted stock | |||||||||||
Effect of dilutive securities | |||||||||||
Effect of dilutive securities | 0 | 58,000 | 20,000 | ||||||||
Performance share awards | |||||||||||
Effect of dilutive securities | |||||||||||
Effect of dilutive securities | 0 | 104,000 | 21,000 |
Reconciliation of Earnings Pe91
Reconciliation of Earnings Per Share (Antidilutive Securities) (Details) - shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of diluted EPS (in options or shares) | 355,915 | ||
Stock options | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of diluted EPS (in options or shares) | 114,000 | 114,000 | 134,000 |
Non-vested restricted stock | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of diluted EPS (in options or shares) | 0 | 3,000 | 7,000 |
Performance share awards | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of diluted EPS (in options or shares) | 0 | 2,000 | 4,000 |
Equity Offering (Details)
Equity Offering (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Jun. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Class of Stock [Line Items] | ||||
Proceeds from issuance of common stock net of offering expenses | $ 398,600 | $ 399,600 | $ 23,053 | $ 17,780 |
Common Stock | ||||
Class of Stock [Line Items] | ||||
Shares issued | 5,700,000 |
Commitments and Contingencies93
Commitments and Contingencies (Additional Information) (Details) gal in Thousands, a in Thousands | Nov. 04, 2015USD ($)a | Dec. 31, 2008gal | Dec. 31, 2015USD ($)MMBoe |
Unfavorable Regulatory Action | |||
Site Contingency [Line Items] | |||
Order for payment of additional royalties | $ 129,700 | ||
Preliminary estimates of order maximum liabilities for additional royalties | $ 24,000,000 | ||
Sylacauga, Talladega County, Alabama | |||
Site Contingency [Line Items] | |||
Gallons of wastewater transported | gal | 3 | ||
Crude Oil and Natural Gas | |||
Site Contingency [Line Items] | |||
Oil and gas delivery commitments, volume | MMBoe | 5.8 | ||
Pending Litigation | Energen vs. Endeavor Energy Resources | |||
Site Contingency [Line Items] | |||
Number of acres with cloud on the title | a | 10 | ||
Amount of counterclaim | $ 300,000,000 |
Commitments and Contingencies94
Commitments and Contingencies (Lease Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Total lease payments | $ 23,700 | $ 24,100 | $ 25,000 |
Operating Leases, Future Minimum Payments Due [Abstract] | |||
2,016 | 2,537 | ||
2,017 | 2,574 | ||
2,018 | 2,537 | ||
2,019 | 2,431 | ||
2,020 | 0 | ||
2021 and thereafter | $ 0 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||||
Balance of ARO, beginning | $ 94,060 | $ 108,533 | $ 118,023 | |||
Liabilities incurred | 981 | 2,266 | 2,772 | |||
Liabilities settled | (686) | (1,543) | (5,525) | |||
Accretion expense | 7,108 | 7,859 | 8,192 | |||
Accretion expense of discontinued operations | 251 | 1,197 | ||||
Revision in estimated cash flows | 692 | |||||
Reclassification associated with held for sale properties | (11,473) | [1] | (23,747) | [2] | (14,929) | [3] |
Balance of ARO, end | $ 89,990 | $ 94,060 | $ 108,533 | |||
[1] | Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2015. | |||||
[2] | Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2014. | |||||
[3] | Asset retirement obligation associated with North Louisiana/East Texas properties. |
Asset Impairment (Summary of Im
Asset Impairment (Summary of Impairments) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2014 | Sep. 30, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Impaired Long-Lived Assets Held and Used [Line Items] | |||||
Asset impairment | $ 1,292,308 | $ 416,801 | $ 13,906 | ||
Assets impairments from discontinued operations | 0 | 1,936 | 29,794 | ||
Total asset impairments | 1,292,308 | 418,737 | 43,700 | ||
Central Basin Platform | |||||
Impaired Long-Lived Assets Held and Used [Line Items] | |||||
Asset impairment | 484,848 | 0 | 0 | ||
Delaware Basin | |||||
Impaired Long-Lived Assets Held and Used [Line Items] | |||||
Asset impairment | $ 90,600 | 607,303 | 90,594 | 0 | |
Midland Basin | |||||
Impaired Long-Lived Assets Held and Used [Line Items] | |||||
Asset impairment | $ 25,800 | 0 | 25,776 | 0 | |
San Juan Basin properties | |||||
Impaired Long-Lived Assets Held and Used [Line Items] | |||||
Asset impairment | 133,055 | 230,315 | 0 | ||
Permian Basin Unproved Leasehold Properties | |||||
Impaired Long-Lived Assets Held and Used [Line Items] | |||||
Asset impairment | $ 55,100 | 29,168 | 64,361 | 13,906 | |
San Juan Basin unproved leasehold properties | |||||
Impaired Long-Lived Assets Held and Used [Line Items] | |||||
Asset impairment | 37,934 | 5,755 | 0 | ||
North Louisiana/East Texas oil and natural gas properties | |||||
Impaired Long-Lived Assets Held and Used [Line Items] | |||||
Assets impairments from discontinued operations | $ 0 | $ 1,936 | $ 29,794 |
Asset Impairment (Additional In
Asset Impairment (Additional Information) (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
Oct. 31, 2013USD ($) | Dec. 31, 2015USD ($)MMBoeMBblsMMcf | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($)MMBoeMBblsMMcf | Sep. 30, 2014USD ($) | Dec. 31, 2013USD ($)MMBoeMBblsMMcf | Dec. 31, 2015USD ($)MMBoeMBblsMMcf | Dec. 31, 2014USD ($)MMBoeMBblsMMcf | Dec. 31, 2013USD ($)MMBoeMBblsMMcf | Mar. 31, 2014USD ($) | |
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | $ 1,292,308 | $ 416,801 | $ 13,906 | |||||||||
Price curve, term | 5 years | |||||||||||
Increase (decrease) in commodity price assumptions (percent) | 3.00% | |||||||||||
Proved developed reserves at end of period (BOE) | MMBoe | 184 | 264.5 | 259.8 | 184 | 264.5 | 259.8 | ||||||
Assets impairments from discontinued operations | $ 0 | $ 1,936 | $ 29,794 | |||||||||
Central Basin Platform | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | 484,848 | 0 | 0 | |||||||||
San Juan Basin properties | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | $ 133,055 | $ 230,315 | 0 | |||||||||
Proved developed reserves at end of period (BOE) | MMBoe | 16.930 | 69.038 | 16.930 | 69.038 | ||||||||
Cash received from sale of oil properties | $ 384,000 | |||||||||||
San Juan Basin properties | Discontinued Operations, Held-for-sale or Disposed of by Sale | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | $ 88,100 | $ 142,200 | ||||||||||
San Juan Proved and Unproved Properties | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | $ 133,100 | |||||||||||
Permian Basin Unproved Leasehold Properties | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | 55,100 | $ 29,168 | $ 64,361 | 13,906 | ||||||||
San Juan Basin unproved leasehold properties | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | 37,934 | 5,755 | 0 | |||||||||
Midland Basin | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | $ 25,800 | 0 | 25,776 | 0 | ||||||||
Delaware Basin | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | $ 90,600 | 607,303 | 90,594 | 0 | ||||||||
North Louisiana/East Texas | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Sales price | $ 30,300 | |||||||||||
Assets impairments from discontinued operations | $ 0 | $ 1,936 | $ 29,794 | |||||||||
Natural Gas | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Increase (decrease) in commodity price assumptions (percent) | (6.00%) | (12.00%) | ||||||||||
Proved developed reserves at end of period (volume) | MMcf | 236,112 | 589,074 | 623,305 | 236,112 | 589,074 | 623,305 | ||||||
Natural Gas | North Louisiana/East Texas | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Proved developed reserves at end of period (volume) | MMcf | 23,000 | 23,000 | ||||||||||
Oil Reserves | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Increase (decrease) in commodity price assumptions (percent) | (12.00%) | (19.00%) | ||||||||||
Proved developed reserves at end of period (volume) | MBbls | 108,319 | 118,697 | 113,795 | 108,319 | 118,697 | 113,795 | ||||||
Oil Reserves | Permian Basin unproved leasehold properties | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | $ 646,100 | $ 390,200 | $ 4,300 | $ 1,092,200 | ||||||||
Oil Reserves | Central Basin Platform | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Asset impairment | $ 51,500 | |||||||||||
Oil Reserves | North Louisiana/East Texas | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Proved developed reserves at end of period (volume) | MBbls | 91 | 91 | ||||||||||
Alabama | Black Warrior Basin | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Cash received from sale of oil properties | $ 160,000 | |||||||||||
Gain on sale of oil and gas property | $ 35,000 | |||||||||||
Black Warrior Basin | Natural Gas | ||||||||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||||||||||
Proved developed reserves at end of period (volume) | MMcf | 97,000 | 97,000 |
Acquisition and Disposition o98
Acquisition and Disposition of Properties (Additional Information) (Details) a in Thousands, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||
Oct. 31, 2014USD ($)a | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($)MMBoe | Dec. 31, 2014USD ($)MMBoe | Dec. 31, 2013USD ($)MMBoe | Feb. 16, 2016MMBoe | |
Business Acquisition [Line Items] | ||||||
Proved developed reserves at end of period (BOE) | MMBoe | 184 | 264.5 | 259.8 | |||
Payments to acquire unproved leasehold properties | $ 85.7 | $ 68.5 | $ 26.8 | |||
San Juan Basin properties | ||||||
Business Acquisition [Line Items] | ||||||
Proved developed reserves at end of period (BOE) | MMBoe | 16.930 | 69.038 | ||||
Sale of assets | $ 395 | |||||
Purchase price adjustments | 11 | |||||
Cash received from sale of oil properties | 384 | |||||
Transaction costs | 2.8 | |||||
Payments to acquire unproved leasehold properties | $ 22.8 | |||||
Net acres | a | 15 | |||||
PUERTO RICO | San Juan Basin properties | ||||||
Business Acquisition [Line Items] | ||||||
Pre-tax gain on disposal | $ 27 | |||||
Subsequent Event | Delaware Basin | ||||||
Business Acquisition [Line Items] | ||||||
Proved developed reserves at end of period (BOE) | MMBoe | 25.200 |
Discontinued Operations and H99
Discontinued Operations and Held for Sale Properties (Additional Information) (Details) $ in Thousands | Sep. 02, 2014USD ($) | Oct. 31, 2013USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2013USD ($)MMBoeMBblsMMcf | Dec. 31, 2015USD ($)MMBoeMBblsMMcf | Dec. 31, 2014USD ($)MMBoeMBblsMMcf | Dec. 31, 2013USD ($)MMBoeMBblsMMcf | Feb. 16, 2016MMBoe | Mar. 31, 2014USD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Proved developed reserves at end of period (BOE) | MMBoe | 259.8 | 184 | 264.5 | 259.8 | |||||
Gain on disposal of discontinued operations, net | $ 724,594 | $ 5,605 | |||||||
Assets impairments from discontinued operations | $ 0 | $ 1,936 | $ 29,794 | ||||||
Natural Gas Reserves | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Proved developed reserves at end of period (volume) | MMcf | 623,305 | 236,112 | 589,074 | 623,305 | |||||
Oil Reserves | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Proved developed reserves at end of period (volume) | MBbls | 113,795 | 108,319 | 118,697 | 113,795 | |||||
Black Warrior Basin | Natural Gas Reserves | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Proved developed reserves at end of period (volume) | MMcf | 97,000 | 97,000 | |||||||
Alabama Gas Corporation | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Disposal group, consideration | $ 1,600,000 | ||||||||
Debt assumed | 267,000 | ||||||||
Proceeds from sale | 1,320,000 | ||||||||
Gain on disposal of discontinued operations, net | $ 726,500 | ||||||||
Black Warrior Basin | Alabama | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Cash received from sale of oil properties | $ 160,000 | ||||||||
Gain on sale of oil and gas property | $ 35,000 | ||||||||
North Louisiana/East Texas | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Sales price | $ 30,300 | ||||||||
Assets impairments from discontinued operations | $ 0 | $ 1,936 | $ 29,794 | ||||||
North Louisiana/East Texas | Natural Gas Reserves | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Proved developed reserves at end of period (volume) | MMcf | 23,000 | ||||||||
North Louisiana/East Texas | Oil Reserves | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Proved developed reserves at end of period (volume) | MBbls | 91 | ||||||||
San Juan Basin properties | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Proved developed reserves at end of period (BOE) | MMBoe | 16.930 | 69.038 | |||||||
Cash received from sale of oil properties | $ 384,000 | ||||||||
Subsequent Event | Delaware Basin | |||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||
Proved developed reserves at end of period (BOE) | MMBoe | 25.200 |
Discontinued Operations and 100
Discontinued Operations and Held for Sale Properties (Balance Sheet) (Details) - San Juan Basin properties - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Assets of Disposal Group, Including Discontinued Operation [Abstract] | ||
Inventories | $ 3,651 | $ 0 |
Oil and natural gas properties | 305,386 | 1,166,124 |
Less accumulated depreciation, depletion and amortization | (219,059) | (770,327) |
Other property and equipment, net | 3,761 | 0 |
Total assets held-for-sale | 93,739 | 395,797 |
Liabilities of Disposal Group, Including Discontinued Operation [Abstract] | ||
Other long-term liabilities | (12,789) | (24,230) |
Total liabilities held-for-sale | (12,789) | (24,230) |
Total held-for-sale properties | $ 80,950 | $ 371,567 |
Discontinued Operations and 101
Discontinued Operations and Held for Sale Properties (Income Statement) (Details) - USD ($) $ / shares in Units, $ in Thousands | Sep. 02, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | ||||
Natural gas distribution revenues | $ 397,648 | $ 533,338 | ||
Oil and natural gas revenues | 5,199 | 60,191 | ||
Total revenues | 402,847 | 593,529 | ||
Pretax income from discontinued operations | 47,220 | 92,253 | ||
Income tax expense | $ 0 | 17,928 | 33,174 | |
Income From Discontinued Operations | 0 | 29,292 | 59,079 | |
Gain on disposal of discontinued operations, net | 724,594 | 5,605 | ||
Income tax expense | 0 | 285,497 | 2,011 | |
Gain on Disposal of Discontinued Operations, net | 0 | 439,097 | 3,594 | |
Income From Discontinued Operations | $ 0 | $ 468,389 | $ 62,673 | |
Diluted earnings per average common share | ||||
Income from discontinued operations | $ 0.40 | $ 0.81 | ||
Gain on disposal of discontinued operations, net | 5.99 | 0.05 | ||
Total Income From Discontinued Operations | $ 0 | 6.39 | 0.86 | |
Basic earnings per average common share | ||||
Income from discontinued operations | 0.40 | 0.82 | ||
Gain on disposal of discontinued operations, net | 6.02 | 0.05 | ||
Total Income From Discontinued Operations | $ 0 | $ 6.42 | $ 0.87 | |
Alabama Gas Corporation | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Alagasco net income | $ 40,646 | $ 57,399 | ||
Depreciation, depletion and amortization | (408) | (598) | ||
General and administrative | 3,337 | 5,894 | ||
Interest expense | (17,306) | (13,815) | ||
Other income | (347) | (1,342) | ||
Income tax expense | 5,567 | 3,728 | ||
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | ||||
Gain on disposal of discontinued operations, net | $ 726,500 | |||
Income From Discontinued Operations | 31,489 | 51,266 | ||
Parent Company | ||||
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | ||||
Income From Discontinued Operations | $ (2,197) | $ 7,813 |
Supplemental Cash Flow Infor102
Supplemental Cash Flow Information (Schedule of Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Supplemental Cash Flow Elements [Abstract] | |||
Interest paid, net of amount capitalized | $ 40,747 | $ 32,172 | $ 38,255 |
Income taxes paid | 8,114 | 219,505 | 22,781 |
Noncash investing activities: | |||
Accrued development, exploration costs and other capital | 79,206 | 207,461 | 93,623 |
Capitalized asset retirement obligations costs | 981 | 2,958 | 2,772 |
Receivable from sale of Alabama Gas Corporation | 0 | 8,247 | 0 |
Noncash financing activities: | |||
Issuance of common stock for employee benefit plans | 5,758 | 2,448 | 1,015 |
Treasury stock acquired in connection with tax withholdings | $ 4,722 | $ 2,547 | $ 977 |
Accumulated Other Comprehens103
Accumulated Other Comprehensive Income (Loss) (Rollforward of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Amounts reclassified from accumulated other comprehensive income | $ (19,828) | $ (14,256) | $ (8,306) |
Pension and Postretirement Plans | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Balance as of December 31, 2014 | (22,870) | ||
Other comprehensive income before reclassifications | 3,305 | ||
Amounts reclassified from accumulated other comprehensive income | (19,828) | ||
Change in accumulated other comprehensive income (loss) | 23,133 | ||
Balance as of December 31, 2015 | $ 263 | $ (22,870) |
Accumulated Other Comprehens104
Accumulated Other Comprehensive Income (Loss) (Reclassifications of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Gains (losses) on cash flow hedges: | ||||||||||||
Income (Loss) From Continuing Operations Before Income Taxes | $ (1,480,736) | $ 140,371 | $ 216,204 | |||||||||
Income tax expense | 535,005 | (40,728) | (74,323) | |||||||||
Income (Loss) From Continuing Operations | $ (590,806) | $ (227,904) | $ (111,601) | $ (15,420) | $ 66,519 | $ 20,631 | $ (3,154) | $ 15,647 | (945,731) | 99,643 | 141,881 | |
Pension and postretirement plans: | ||||||||||||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (19,828) | (2,514) | 12,324 | |||||||||
Nonqualified Supplemental Retirement Plans | ||||||||||||
Pension and postretirement plans: | ||||||||||||
Settlement charges | $ 2,500 | $ 1,800 | 400 | 600 | ||||||||
Settlement charges expensed | 200 | |||||||||||
Nonqualified Supplemental Retirement Plans | Alabama Gas Corporation | ||||||||||||
Pension and postretirement plans: | ||||||||||||
Settlement charges | 400 | |||||||||||
Transition obligation | ||||||||||||
Pension and postretirement plans: | ||||||||||||
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | 0 | (22) | (319) | |||||||||
Prior service cost | ||||||||||||
Pension and postretirement plans: | ||||||||||||
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | 0 | (248) | (257) | |||||||||
Actuarial losses | ||||||||||||
Pension and postretirement plans: | ||||||||||||
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | (30,504) | (21,932) | (12,357) | |||||||||
Actuarial losses on settlement charges | ||||||||||||
Pension and postretirement plans: | ||||||||||||
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | [1] | 0 | 0 | (421) | ||||||||
Pension and Postretirement Plans | ||||||||||||
Gains (losses) on cash flow hedges: | ||||||||||||
Income tax expense | 10,676 | 7,771 | 4,674 | |||||||||
Pension and postretirement plans: | ||||||||||||
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax | (30,504) | (22,202) | (13,354) | |||||||||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (19,828) | (14,431) | (8,680) | |||||||||
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedges | ||||||||||||
Gains (losses) on cash flow hedges: | ||||||||||||
Income (Loss) From Continuing Operations Before Income Taxes | 0 | 19,331 | 33,961 | |||||||||
Income tax expense | 0 | (7,414) | (12,957) | |||||||||
Income (Loss) From Continuing Operations | 0 | 11,917 | 21,004 | |||||||||
Reclassification out of Accumulated Other Comprehensive Income | Commodity contracts | Cash Flow Hedges | ||||||||||||
Gains (losses) on cash flow hedges: | ||||||||||||
Commodity contracts | 0 | 21,611 | 35,684 | |||||||||
Reclassification out of Accumulated Other Comprehensive Income | Interest rate swap | Cash Flow Hedges | ||||||||||||
Gains (losses) on cash flow hedges: | ||||||||||||
Interest rate swap | $ 0 | $ (2,280) | $ (1,723) | |||||||||
[1] | During the year ended December 31, 2013, Energen incurred settlement charges of $0.6 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.2 million was recognized in actuarial losses above and $0.4 million was recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above. |
Recently Issued Accounting S105
Recently Issued Accounting Standards Recently Issued Accounting Standards (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Deferred tax liability, noncurrent | $ 552,369 | $ 1,000,486 |
New Accounting Pronouncement, Early Adoption, Effect | ||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | ||
Amount of reclassified current deferred tax asset | (14,500) | |
Deferred tax liability, noncurrent | $ 14,500 |
Summarized Quarterly Financi106
Summarized Quarterly Financial Data (Unaudited) (Quarterly Operating Results) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Selected Quarterly Financial Information [Abstract] | ||||||||||||
Revenues | $ 192,799 | $ 295,571 | $ 168,326 | $ 221,858 | $ 878,554 | $ 1,679,213 | $ 1,206,293 | |||||
Discontinued operations | 402,847 | 593,529 | ||||||||||
Reclassification of loss on sale of assets and other | (26,570) | 2,642 | 981 | |||||||||
Operating income (loss) | (915,550) | (348,214) | (161,678) | (12,409) | (1,437,851) | 176,961 | 252,137 | |||||
Income (loss) from continuing operations | (590,806) | (227,904) | (111,601) | (15,420) | $ 66,519 | $ 20,631 | $ (3,154) | $ 15,647 | (945,731) | 99,643 | 141,881 | |
Net income (loss) | $ (590,806) | $ (227,904) | $ (111,601) | $ (15,420) | $ 65,418 | $ 457,251 | $ (7,953) | $ 53,316 | $ (945,731) | $ 568,032 | $ 204,554 | |
Diluted earnings per average common share | ||||||||||||
Continuing operations (in dollars per share) | $ (7.50) | $ (2.89) | $ (1.52) | $ (0.21) | $ 0.91 | $ 0.28 | $ (0.04) | $ 0.21 | $ (12.43) | $ 1.36 | $ 1.96 | |
Net income (loss) (in dollars per share) | (7.50) | (2.89) | (1.52) | (0.21) | 0.89 | 6.22 | (0.11) | 0.73 | (12.43) | 7.75 | 2.82 | |
Basic earnings per average common share | ||||||||||||
Continuing operations (in dollars per share) | (7.50) | (2.89) | (1.52) | (0.21) | 0.91 | 0.28 | (0.04) | 0.22 | (12.43) | 1.37 | 1.96 | |
Net income (loss) (in dollars per share) | $ (7.50) | $ (2.89) | $ (1.52) | $ (0.21) | $ 0.90 | $ 6.26 | $ (0.11) | $ 0.73 | $ (12.43) | $ 7.79 | $ 2.83 | |
Originally reported | ||||||||||||
Selected Quarterly Financial Information [Abstract] | ||||||||||||
Revenues | $ 611,435 | $ 497,761 | $ 270,097 | $ 561,178 | ||||||||
Operating income (loss) | 94,223 | 48,171 | 3,107 | 104,599 | ||||||||
Adjustment | ||||||||||||
Selected Quarterly Financial Information [Abstract] | ||||||||||||
Revenues | 612,268 | 498,508 | 271,006 | 297,431 | ||||||||
Discontinued operations | [1] | 0 | 0 | 0 | (263,900) | |||||||
Reclassification of loss on sale of assets and other | 833 | 747 | 909 | 153 | ||||||||
Operating income (loss) | 94,223 | 48,171 | 3,107 | 31,460 | ||||||||
Discontinued operations | [1] | $ 0 | $ 0 | $ 0 | $ (73,139) | |||||||
[1] | As discussed in Note 16, Discontinued Operations and Held for Sale Properties, during the third quarter of 2014, Energen completed the transaction to sell Alagasco to Laclede. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. |
Oil and Natural Gas Operatio107
Oil and Natural Gas Operations (Unaudited) (Capitalized Costs) (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Extractive Industries [Abstract] | ||
Proved | $ 7,911,554 | $ 8,069,638 |
Unproved | 150,674 | 142,340 |
Total capitalized costs | 8,062,228 | 8,211,978 |
Accumulated depreciation, depletion and amortization | 3,673,569 | 2,663,434 |
Capitalized costs, net | $ 4,388,659 | $ 5,548,544 |
Oil and Natural Gas Operatio108
Oil and Natural Gas Operations (Unaudited) (Costs Incurred) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property acquisition: | |||
Proved | $ 1,866 | $ 2,582 | $ 4,661 |
Unproved | 85,690 | 68,514 | 26,820 |
Exploration | 649,764 | 972,164 | 435,636 |
Development | 372,177 | 408,949 | 655,353 |
Total costs incurred | $ 1,109,497 | $ 1,452,209 | $ 1,122,470 |
Oil and Natural Gas Operatio109
Oil and Natural Gas Operations (Unaudited) (Results of Operations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Reserve Quantities [Line Items] | ||||
Gross revenues | [1] | $ 878,554 | $ 1,679,213 | $ 1,206,293 |
Production (lifting costs) | 285,760 | 376,495 | 351,541 | |
Exploration expense | 14,877 | 28,090 | 14,036 | |
Depreciation, depletion and amortization including asset impairments | 1,880,190 | 960,539 | 463,606 | |
Accretion expense | 7,108 | 7,608 | 6,995 | |
Income tax expense (benefit) | (469,362) | 99,469 | 128,773 | |
Results of operations from producing activities | (840,019) | 207,012 | 241,342 | |
Commodity contracts | ||||
Reserve Quantities [Line Items] | ||||
Open non-cash mark-to-market gains (losses) on derivative instruments | $ (281,752) | $ 315,445 | $ (47,832) | |
[1] | The years ended December 31, 2015, 2014 and 2013 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $281.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million and a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, respectively. |
Oil and Natural Gas Operatio110
Oil and Natural Gas Operations (Unaudited) (Oil and Gas Operations) (Details) | 12 Months Ended | ||
Dec. 31, 2015MMBoeMBblsMMcf | Dec. 31, 2014MMBoeMBblsMMcf | Dec. 31, 2013MMBoeMBblsMMcf | |
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Proved reserves at beginning of period, total | MMBoe | 372.7 | 347.8 | 346.4 |
Revisions of previous estimates, total | MMBoe | (58.9) | (75.7) | 4.6 |
Purchases, total | MMBoe | 0 | 0.1 | 0.2 |
Extensions and discoveries, total | MMBoe | 132.6 | 130 | 36.8 |
Production, total | MMBoe | (24) | (25.8) | (25.4) |
Sales, total | MMBoe | (67.7) | (3.7) | (14.8) |
Proved reserves at end of period, total | MMBoe | 354.7 | 372.7 | 347.8 |
Proved developed reserves at end of period (BOE) | MMBoe | 184 | 264.5 | 259.8 |
Proved undeveloped reserves at end of period (BOE) | MMBoe | 170.7 | 108.2 | 88 |
Oil Reserves | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Proved reserves at beginning of period | 181,227 | 164,870 | 155,348 |
Revisions of previous estimates | (39,537) | (48,548) | (680) |
Purchases | 2 | 88 | 142 |
Extensions and discoveries | 83,319 | 76,722 | 20,517 |
Production | (14,023) | (11,818) | (10,378) |
Sales | (297) | (87) | (79) |
Proved reserves at end of period | 210,691 | 181,227 | 164,870 |
Proved developed reserves at end of period (volume) | 108,319 | 118,697 | 113,795 |
Proved undeveloped reserves at end of period (volume) | 102,372 | 62,530 | 51,075 |
Natural Gas Liquids Reserves | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Proved reserves at beginning of period | 73,463 | 63,011 | 56,155 |
Revisions of previous estimates | (11,979) | (15,165) | 2,211 |
Purchases | 1 | 26 | 56 |
Extensions and discoveries | 25,530 | 29,695 | 7,823 |
Production | (4,065) | (4,104) | (3,233) |
Sales | (11,237) | 0 | (1) |
Proved reserves at end of period | 71,713 | 73,463 | 63,011 |
Proved developed reserves at end of period (volume) | 36,374 | 47,621 | 42,087 |
Proved undeveloped reserves at end of period (volume) | 35,339 | 25,842 | 20,924 |
Natural Gas Reserves | |||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||
Proved reserves at beginning of period | MMcf | 707,926 | 719,725 | 809,128 |
Revisions of previous estimates | MMcf | (44,176) | (71,806) | 18,465 |
Purchases | MMcf | 2 | 116 | 282 |
Extensions and discoveries | MMcf | 143,022 | 141,209 | 50,568 |
Production | MMcf | (35,604) | (59,562) | (70,506) |
Sales | MMcf | (337,266) | (21,756) | (88,212) |
Proved reserves at end of period | MMcf | 433,904 | 707,926 | 719,725 |
Proved developed reserves at end of period (volume) | MMcf | 236,112 | 589,074 | 623,305 |
Proved undeveloped reserves at end of period (volume) | MMcf | 197,792 | 118,852 | 96,420 |
Oil and Natural Gas Operatio111
Oil and Natural Gas Operations (Unaudited) (Oil and Gas Operations, Activities) (Details) | 12 Months Ended | ||
Dec. 31, 2015MMBoe | Dec. 31, 2014MMBoewell_locationpay_add | Dec. 31, 2013MMBoewell_locationpay_add | |
Reserve Quantities [Line Items] | |||
Reserves included in engineer estimates, percent | 99.00% | ||
Revisions of previous estimates | (58.9) | (75.7) | 4.6 |
Purchases | 0 | 0.1 | 0.2 |
Extensions and discoveries | 132.6 | 130 | 36.8 |
Percentage of undeveloped portion of proved reserves | 78.00% | 70.00% | 45.00% |
Percentage of developed portion of proved reserves | 22.00% | 30.00% | 55.00% |
Sales | 67.7 | 3.7 | 14.8 |
Extension Drilling | |||
Reserve Quantities [Line Items] | |||
Extensions and discoveries | 3.1 | 89.6 | 21.6 |
Exploratory Drilling | |||
Reserve Quantities [Line Items] | |||
Extensions and discoveries | 129.5 | 40.4 | 15.2 |
Price Related Revisions | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (38) | 3.9 | 7 |
Expected to Be Drilled Beyond Five Years | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (8.2) | ||
No Longer Expected to be Drilled | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (5.3) | ||
No Longer Expected to Be Drilled Beyond Five Years | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (53.4) | (4.6) | |
San Juan Basin properties | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | 1.6 | 2.2 | |
Extensions and discoveries | 1.1 | 2.3 | |
Number of well locations | well_location | 16 | ||
Pay-add locations | pay_add | 10 | 30 | |
San Juan Basin properties | Price Related Revisions | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | 4.4 | 5.9 | |
San Juan Basin properties | Higher Operating Costs | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (1.5) | ||
San Juan Basin properties | Expected to Be Drilled Beyond Five Years | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (4.6) | ||
Permian Basin unproved leasehold properties | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (5.5) | (77.3) | 1.2 |
Extensions and discoveries | 128.6 | 34.4 | |
Number of well locations | well_location | 361 | 262 | |
Permian Basin unproved leasehold properties | Price Related Revisions | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | 0.4 | ||
Permian Basin unproved leasehold properties | Higher Operating Costs | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (5.4) | ||
Permian Basin unproved leasehold properties | Interference Caused by Welbore Placement Geometry [Member] | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (5) | ||
Permian Basin unproved leasehold properties | Reclassifying as Unproved | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (53.4) | ||
Permian Basin unproved leasehold properties | Well Performance Revisions | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (13.3) | ||
Permian Basin unproved leasehold properties | No Longer Expected to be Drilled | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (0.7) | ||
Permian Basin unproved leasehold properties | Change in Year-End Pricing Revisions | |||
Reserve Quantities [Line Items] | |||
Revisions of previous estimates | (0.5) | ||
North Louisiana/East Texas oil and natural gas properties | |||
Reserve Quantities [Line Items] | |||
Sales | 3.7 | ||
Black Warrior Basin | |||
Reserve Quantities [Line Items] | |||
Sales | 14.8 |
Oil and Natural Gas Operatio112
Oil and Natural Gas Operations (Unaudited) (Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract] | |||||||
Future gross revenues | $ 11,714,729 | $ 20,971,672 | $ 19,509,305 | ||||
Future production costs | 4,353,974 | 7,532,273 | 6,136,709 | ||||
Future development costs | 1,961,661 | 1,784,738 | 1,896,602 | ||||
Future income tax expense | 1,065,887 | 3,440,582 | 3,209,697 | ||||
Future net cash flows | 4,333,207 | 8,214,079 | 8,266,297 | ||||
Discount at 10% per annum | 2,299,859 | 3,994,423 | 4,248,456 | ||||
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | $ 4,219,656 | $ 4,017,841 | $ 3,699,319 | $ 2,033,348 | $ 4,219,656 | $ 4,017,841 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||||||
Balance at beginning of year | 4,219,656 | 4,017,841 | 3,699,319 | ||||
Revisions to reserves proved in prior years: | |||||||
Net changes in prices, production costs and future development costs | (2,861,591) | (1,147,028) | 566,838 | ||||
Net changes due to revisions in quantity estimates | (404,708) | (1,285,394) | (81,762) | ||||
Development costs incurred, previously estimated | 350,560 | 337,198 | 299,432 | ||||
Accretion of discount | 421,966 | 401,784 | 369,932 | ||||
Changes in timing and other | [1] | (903,975) | 987,652 | (179,502) | |||
Total revisions | (3,397,748) | (705,788) | 974,938 | ||||
New field discoveries and extensions, net of future production and development costs | 776,315 | 2,321,028 | 376,326 | ||||
Sales of oil and gas produced, net of production costs | (514,380) | (1,054,553) | (1,014,593) | ||||
Purchases | 8 | 4,241 | 4,690 | ||||
Sales | (372,039) | (21,092) | (24,876) | ||||
Net change in income taxes | 1,321,536 | (342,021) | 2,037 | ||||
Net change in standardized measure of discounted future net cash flows | (2,186,308) | 201,815 | 318,522 | ||||
Balance at end of year | $ 2,033,348 | $ 4,219,656 | $ 4,017,841 | ||||
[1] | Amount represents changes in production timing and other. In 2015, the production timing is significantly affected by changes related to the delay of the drilling program. For 2014, the production timing is significantly affected by changes related to the acceleration of the horizontal drilling program and the delay of the vertical drilling program. |