Energen (EGN) 10-K 16 Feb 16 2015 FY Annual report Financial data

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.