Energen (EGN) 10-K 28 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 14, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
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 (in shares)		97,187,767
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 4,616,230,556

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 386,093	$ 1,272
Accounts receivable, net	73,322	63,097
Inventories, net	14,222	11,255
Assets held for sale	0	93,739
Derivative instruments	50	56,963
Income tax receivable	27,153	8,376
Prepayments and other	5,071	11,638
Total current assets	505,911	246,340
Oil and natural gas properties, successful efforts method
Proved properties	7,543,464	7,611,118
Unproved properties	196,888	145,724
Less accumulated depreciation, depletion and amortization	3,723,669	3,454,510
Oil and natural gas properties, net	4,016,683	4,302,332
Other property and equipment, net	44,869	48,358
Total property, plant and equipment, net	4,061,552	4,350,690
Other postretirement assets	3,619	3,881
Other assets	8,741	10,245
TOTAL ASSETS	4,579,823	4,611,156
Current Liabilities
Long-term debt due within one year	24,000	0
Accounts payable	65,031	64,742
Accrued taxes	7,252	5,801
Accrued wages and benefits	25,089	28,563
Accrued capital costs	79,988	79,206
Revenue and royalty payable	51,217	60,493
Liabilities related to assets held for sale	0	12,789
Pension liabilities	0	15,685
Derivative instruments	65,467	459
Other	20,160	19,783
Total current liabilities	338,204	287,521
Long-term debt	527,443	773,550
Asset retirement obligations	81,544	89,990
Noncurrent derivative instruments	3,006	0
Deferred income taxes	495,888	552,369
Other	13,136	11,866
Total liabilities	1,459,221	1,715,296
Commitments and Contingencies
Shareholders' Equity
Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized	0	0
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized; 100,138,797 shares issued at December 31, 2016 and 81,770,161 shares issued at December 31, 2015	1,001	818
Premium on capital stock	1,372,569	979,030
Retained earnings	1,878,503	2,046,016
Accumulated other comprehensive income (loss), net of tax
Pension and postretirement plans	1,405	263
Deferred compensation plan	2,261	1,965
Treasury stock, at cost; 3,125,715 shares and 3,026,350 shares at December 31, 2016 and 2015, respectively	(135,137)	(132,232)
Total shareholders’ equity	3,120,602	2,895,860
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$ 4,579,823	$ 4,611,156

CONSOLIDATED BALANCE SHEETS (PA

CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (in shares)	5,000,000	5,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares issued (in shares)	100,138,797	81,770,161
Treasury stock, shares (in shares)	3,125,715	3,026,350

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues
Oil, natural gas liquids and natural gas sales	$ 621,366	$ 763,261	$ 1,344,194
Gain (loss) on derivative instruments, net	(88,477)	115,293	335,019
Total revenues	532,889	878,554	1,679,213
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production	171,714	228,380	274,432
Production and ad valorem taxes	42,938	57,380	102,063
Depreciation, depletion and amortization	447,961	593,789	548,564
Asset impairment	220,652	1,292,308	416,801
Exploration	5,415	14,878	28,090
General and administrative (including non-cash stock based compensation of $19,641, $12,910 and $16,262 for the years ended December 31, 2016, 2015 and 2014, respectively)	95,689	149,132	122,052
Accretion of discount on asset retirement obligations	6,672	7,108	7,608
(Gain) loss on sale of assets and other, net	(246,922)	(26,570)	2,642
Total operating costs and expenses	744,119	2,316,405	1,502,252
Operating Income (Loss)	(211,230)	(1,437,851)	176,961
Other Income (Expense)
Interest expense	(36,899)	(43,108)	(37,771)
Other income	978	223	1,181
Total other expense	(35,921)	(42,885)	(36,590)
Income (Loss) From Continuing Operations Before Income Taxes	(247,151)	(1,480,736)	140,371
Income tax expense (benefit)	(79,638)	(535,005)	40,728
Income (Loss) From Continuing Operations	(167,513)	(945,731)	99,643
Discontinued Operations, net of tax
Income from discontinued operations	0	0	29,292
Gain on disposal of discontinued operations, net	0	0	439,097
Income From Discontinued Operations	0	0	468,389
Net Income (Loss)	$ (167,513)	$ (945,731)	$ 568,032
Diluted Earnings Per Average Common Share
Continuing operations (in dollars per share)	$ (1.77)	$ (12.43)	$ 1.36
Discontinued operations (in dollars per share)	0	0	6.39
Net Income (Loss) (in dollars per share)	(1.77)	(12.43)	7.75
Basic Earnings Per Average Common Share
Continuing operations (in dollars per share)	(1.77)	(12.43)	1.37
Discontinued operations (in dollars per share)	0	0	6.42
Net Income (Loss) (in dollars per share)	$ (1.77)	$ (12.43)	$ 7.79
Diluted Average Common Shares Outstanding (in shares)	94,475,797	76,078,371	73,274,631
Basic Average Common Shares Outstanding (in shares)	94,475,797	76,078,371	72,896,579

CONCOLIDATED STATEMENTS OF INCO

CONCOLIDATED STATEMENTS OF INCOME (PARENTHETICAL) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
General and administrative	$ 19,641	$ 12,910	$ 16,262

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net Income (Loss)	$ (167,513)	$ (945,731)	$ 568,032
Cash flow hedges:
Total cash flow hedges	0	0	(12,178)
Pension and postretirement plans:
Amortization of net benefit obligation at transition, net of tax of $8 in 2014	0	0	14
Amortization of prior service cost, net of tax of ($176), $0 and $87, respectively	(289)	0	161
Amortization of net loss, net of tax of $1,168, $10,676 and $7,676, respectively	1,890	19,828	14,256
Current period change in fair value of pension and postretirement plans, net of tax of ($279), $1,779, and ($2,722), respectively	(459)	3,305	(5,056)
Total pension and postretirement plans	1,142	23,133	9,375
Comprehensive Income (Loss)	(166,371)	(922,598)	565,229
Commodity contracts
Cash flow hedges:
Current period change in fair value of derivative instruments, net of tax	0	0	37
Reclassification adjustment for derivative instruments, net of tax	0	0	(13,399)
Interest rate swap
Cash flow hedges:
Current period change in fair value of derivative instruments, net of tax	0	0	(298)
Reclassification adjustment for derivative instruments, net of tax	$ 0	$ 0	$ 1,482

CONSOLIDATED STATEMENTS OF COM7

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (PARENTHETICAL) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current period change in fair value of interest rate swap, tax			$ 23
Amortization of net obligation at transition, tax	$ 0	$ 0	8
Amortization of prior service cost, tax	(176)	0	87
Amortization of net loss, tax	1,168	10,676	7,676
Current period change in fair value of pension and postretirement plans, tax	(279)	1,779	(2,722)
Commodity contracts
Current period change in fair value of interest rate swap, tax	0	0	23
Reclassification adjustment for derivative instruments, tax	0	0	(8,212)
Interest rate swap
Current period change in fair value of interest rate swap, tax	0	0	160
Reclassification adjustment for derivative instruments, tax	$ 0	$ 0	$ 798

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 (in shares) at Dec. 31, 2013		75,574,156
Beginning 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	(2,547)						(2,547)
Purchase and retirement of shares (in shares)		(226,839)
Purchase and retirement of shares, value	(14,913)	$ (2)	(2,388)	(12,523)
Shares issued for employee benefit plans (in 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	(34,304)			(34,304)
Ending balance, shares (in shares) at Dec. 31, 2014		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	(4,723)						(4,723)
Shares issued for stock offering (in shares)		5,700,000
Shares issued for stock offering	398,620	$ 57	398,563
Purchase and retirement of shares (in shares)		0
Shares issued for employee benefit plans (in 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	$ (6,074)			(6,074)
Ending balance, shares (in 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)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(167,513)			(167,513)
Other comprehensive income (loss)	1,142				1,142
Purchase of treasury shares, net	(2,609)						(2,609)
Shares issued for stock offering (in shares)		18,170,000
Shares issued for stock offering	381,077	$ 182	380,895
Purchase and retirement of shares (in shares)		0
Shares issued for employee benefit plans (in shares)		198,636
Shares issued for employee benefit plans	6,858	$ 1	6,857
Deferred compensation obligation	0					296	(296)
Stock-based compensation	6,043		6,043
Tax benefit from employee stock plans	$ (256)		(256)
Ending balance, shares (in shares) at Dec. 31, 2016	100,138,797	100,138,797
Ending balance, value at Dec. 31, 2016	$ 3,120,602	$ 1,001	$ 1,372,569	$ 1,878,503	$ 1,405	$ 2,261	$ (135,137)

CONSLIDATED STATEMENTS OF SHARE

CONSLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (PARENTHETICAL) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Stockholders' Equity [Abstract]
Common stock, cash dividends per share (in dollars per share)		$ 0.08	$ 0.47
Treasury shares (in shares)	88,320	73,206	32,768

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Activities
Net Income (Loss)	$ (167,513)	$ (945,731)	$ 568,032
Income from discontinued operations	0	0	(468,389)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	447,961	593,789	548,564
Asset impairment	220,652	1,292,308	416,801
Accretion of discount on asset retirement obligations	6,672	7,108	7,608
Deferred income taxes	(57,193)	(539,735)	302,890
Change in derivative fair value	76,490	233,315	(346,646)
(Gain) loss on sale of assets	(246,393)	(28,077)	55
Stock-based compensation expense	19,641	12,910	16,262
Exploration, including dry holes	16	7,097	9,325
Discontinued operations	0	0	91,510
Other, net	5,752	35,641	4,166
Net change in:
Accounts receivable	38,305	117,486	4,812
Inventories	(2,948)	(655)	(3,121)
Accounts payable	(2,205)	(46,283)	18,695
Accrued taxes/income tax receivable	(17,326)	(4,791)	(488,980)
Pension and other postretirement benefit contributions	(14,608)	(24,848)	(12,483)
Other current assets and liabilities	(14,855)	5,058	36,382
Net cash provided by operating activities	292,448	714,592	705,483
Investing Activities
Additions to oil and natural gas properties	(447,028)	(1,154,373)	(1,264,059)
Acquisitions, net of cash acquired	(147,879)	(87,410)	(70,730)
Proceeds from asset sales and sale of Alabama Gas Corporation	528,775	394,521	1,347,725
Purchase of short-term investments	0	(919,000)	(473,000)
Sale of short-term investments	0	919,000	473,000
Discontinued operations	0	0	(51,850)
Net cash used in investing activities	(66,132)	(847,262)	(38,914)
Financing Activities
Payment of dividends on common stock	0	(6,074)	(34,304)
Issuance of common stock, net	381,261	399,600	23,053
Purchase and retirement of shares	0	0	(14,913)
Reduction of long-term debt	0	0	(600,000)
Payment of debt issuance costs	0	0	(10,901)
Net change in credit facility	(222,500)	(262,500)	(4,000)
Tax benefit on stock compensation	(256)	1,064	5,906
Discontinued operations	0	0	(35,113)
Net cash provided by (used in) financing activities	158,505	132,090	(670,272)
Net change in cash and cash equivalents	384,821	(580)	(3,703)
Cash and cash equivalents at beginning of period	1,272	1,852	5,555
Cash and cash equivalents at end of period	$ 386,093	$ 1,272	$ 1,852

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	ORGANIZATION AND BASIS OF PRESENTATION Energen Corporation (Energen or the Company) is an oil and natural gas exploration and production company engaged in the exploration, development and production of oil, natural gas liquids and natural gas. Our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources) and primarily occur within the Midland Basin, the Delaware Basin and the Central Basin Platform areas of the Permian Basin in west Texas and New Mexico. Our corporate headquarters are located in Birmingham, Alabama. 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, Held for Sale Properties and Discontinued Operations, for further information regarding the sale of Alagasco. Workforce Reduction On January 22, 2016 and March 18, 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. In connection with the reductions, we incurred charges of approximately $5.0 million during 2016 for one-time termination benefits which are included in general and administrative expense on the consolidated income statement.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2016
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. 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. C. 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. D. 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, 2016 and 2015, Energen had no short-term investments. E. 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 $0.6 million and $0.7 million at December 31, 2016 and 2015, respectively. F. 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. Energen had an inventory valuation allowance of $0.7 million and $0.2 million at December 31, 2016 and 2015, respectively. G. Oil and Natural Gas Operations 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, 2016 and 2015 . 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. 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. 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 and sale agreements and similar support as applicable. Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These 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. 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. Held for Sale Properties 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. H. Derivative Commodity Instruments We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps, options 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. I. 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 direct or indirect observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps and options priced in reference to NYMEX oil and natural gas prices, basin specific gas hedges and gas basis. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include oil basis and natural gas liquids swaps. We consider the frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While Energen does not have access to the specific assumptions used in its counterparties’ valuation models, 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. 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 year ended December 31, 2016 , we recognized tax expense of $0.3 million related to our stock-based compensation. For the years ended December 31, 2015 and 2014, we recognized an excess tax benefit of $1.1 million and $5.9 million , respectively. K. 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. L. 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. M. 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. N. 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. The Pension Benefit Guaranty Corporation (PBGC) is conducting an audit of the termination of the pension plan to ensure that Energen properly calculated and distributed benefits in accordance with plan provisions and in compliance with the appropriate laws and regulations administered by the PBGC. Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans were partially made in the first quarter of 2015 with the remainder of approximately $14.5 million paid in the first quarter of 2016. The Company expects to make no additional benefit payments with respect to the termination of the non-qualified supplemental retirement plans. 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 these 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.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Long-term debt consisted of the following: (in thousands) December 31, 2016 December 31, 2015 Credit facility $ — $ 222,500 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 554,000 776,500 Less amounts due within one year 24,000 — Less unamortized debt discount 387 413 Less unamortized debt issuance costs 2,170 2,537 Total $ 527,443 $ 773,550 The aggregate maturities of Energen’s long-term debt as of December 31, 2016 are as follows: Years ending December 31, (in thousands) 2017 2018 2019 2020 2021 Thereafter $24,000 $— $— $— $400,000 $130,000 On January 23, 2017, Energen redeemed the $2 million of 7.40% Medium-term Notes, Series A, due July 24, 2017 and $5 million of 7.60% Medium-term Notes, Series A, due July 26, 2027. The $5 million of 7.60% Medium-term Notes has been classified as long-term debt due within one year on the consolidated balance sheets. 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 Facility: On September 2, 2014, Energen entered into a five -year syndicated secured credit facility with domestic and foreign lenders. On April 13, 2016, the borrowing base and aggregate commitments were reduced to $1.05 billion in association with the semi-annual redetermination required under the agreement. On October 25, 2016, the borrowing base was reaffirmed with no changes. Energen’s obligations under the 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, 2017. 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, 2016 . The following is a summary of information relating to Energen’s credit facility: (in thousands) December 31, 2016 December 31, 2015 Credit facility outstanding $ — $ 222,500 Available for borrowings 1,050,000 1,177,500 Total borrowing commitments $ 1,050,000 $ 1,400,000 Maximum amount outstanding at any month-end $ 214,500 $ 685,000 Average daily amount outstanding $ 33,642 $ 358,929 Weighted average interest rates based on: Average daily amount outstanding 1.72 % 1.60 % Amount outstanding at year-end — % 1.64 % Energen’s total interest expense was $36.9 million , $43.1 million and $37.8 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Energen’s total interest expense for the years ended December 31, 2016, 2015 and 2014 included amortization of debt issuance costs related to long-term debt, including our credit facility, of $3.3 million , $3.3 million and $5.7 million , respectively. Capitalized interest expense was $0.1 million and $0.2 million for the years ended December 31, 2016 and 2014, respectively. Capitalized interest expense for the year ended December 31, 2015 was not significant. At December 31, 2016, Energen paid commitment fees on the unused portion of available credit facility at a current annual rate of 30 basis points per annum. Energen paid commitment fees of $3.4 million , $4.1 million and $3.6 million for the years ended December 31, 2016, 2015 and 2014, respectively.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Taxes estimated to be payable currently: Federal $ (23,277 ) $ 3,972 $ 161,576 State 832 758 72,379 Total current (22,445 ) 4,730 233,955 Taxes deferred: Federal (62,205 ) (513,187 ) 144,645 State 5,012 (26,548 ) (34,447 ) Total deferred (57,193 ) (539,735 ) 110,198 Total income tax expense (benefit) $ (79,638 ) $ (535,005 ) $ 344,153 The components of Energen’s income taxes consisted of the following: Years ended December 31, (in thousands) 2016 2015 2014 Income tax expense (benefit) from continuing operations $ (79,638 ) $ (535,005 ) $ 40,728 Income tax expense from discontinued operations — — 17,928 Income tax expense from gain on disposal of discontinued operations — — 285,497 Total income tax expense (benefit) $ (79,638 ) $ (535,005 ) $ 344,153 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, 2016 December 31, 2015 Noncurrent Noncurrent Deferred tax assets: Minimum tax credit $ 64,203 $ 44,862 Allowance for doubtful accounts 222 253 Insurance and other accruals 3,151 2,807 Compensation accruals 13,895 11,650 Deferred compensation and other costs 5,401 8,693 Derivative instruments 22,402 — State net operating losses and other carryforwards 12,947 12,577 Other 313 — Total deferred tax assets 122,534 80,842 Valuation allowance (5,735 ) (3,235 ) Total deferred tax assets 116,799 77,607 Deferred tax liabilities: Depreciation and basis differences 603,324 620,629 Derivative instruments — 2,838 Other comprehensive income 854 141 Other 8,509 6,368 Total deferred tax liabilities 612,687 629,976 Net deferred tax liabilities $ (495,888 ) $ (552,369 ) Energen files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2016, the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $64.2 million . Energen has a federal net operating loss generated in the current year of $128 million , which the Company intends to carry back and fully utilize in the 2014 tax year. Energen made a reclassification of approximately $25.5 million between income tax receivable and deferred tax assets to reflect the impact of this federal net operating loss carryback. In addition, the federal net operating loss carryback will generate an additional minimum tax credit carryforward of $19.1 million . Energen has $8.8 million of state net operating loss and charitable contribution carryforwards which will expire beginning in 2024 through 2028. Energen Resources has $281 million of state net operating loss carryforwards which will expire beginning in 2026 through 2036. Energen Resources has a valuation allowance recorded against deferred tax assets of $5.7 million arising from certain of these state net operating losses and other state deferred tax assets that are not expected to be realized through reversals of its existing taxable temporary differences. Energen intends to fully reserve these assets until it is determined that deferred tax assets 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 differs 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) 2016 2015 2014 Income tax expense (benefit) at statutory federal income tax rate $ (86,503 ) $ (518,258 ) $ 49,130 Increase (decrease) resulting from: State income taxes, net of federal income tax benefit 925 (15,417 ) (459 ) Impact of state law changes (9 ) (3,075 ) (121 ) Impact of state deferred tax revaluation on San Juan properties (153 ) (1,241 ) (8,382 ) Change in deferred tax valuation allowance 2,500 1,305 552 Other, net 3,602 1,681 8 Total income tax expense (benefit) $ (79,638 ) $ (535,005 ) $ 40,728 Effective income tax rate (%) 32.22 36.13 29.01 In addition to other changes in state apportionment reflected in the state income taxes, net of federal income tax benefit above, Energen recognized $0.2 million , $1.2 million and $8.4 million of income tax benefit during 2016, 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, 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 Additions based on tax positions related to the current year 2,936 Additions for tax positions of prior years 1,484 Reductions for tax positions of prior years (99 ) Lapse of statute of limitations (1,300 ) Balance as of December 31, 2016 $ 14,210 The amount of unrecognized tax benefits at December 31, 2016 that would favorably impact Energen’s effective tax rate, if recognized, is $3.5 million . Energen recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2016 , 2015 , and 2014 , Energen recognized approximately $101,000 of expense, $2,000 of income and $27,000 of expense for interest (net of tax benefit) and penalties, respectively. Energen had approximately $0.3 million and $0.2 million for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2016 and 2015 , respectively. On February 8, 2017, the Company received notification from the Internal Revenue Service that the review of the Company's amended tax return for the 2012 tax year had concluded and the full amount of the refund claim of $0.9 million had been accepted. The Company expects to receive the refund in the first quarter of 2017. Energen’s tax returns for years 2013-2015 remain open and subject to examination by the IRS and major state taxing jurisdictions. Accordingly, it is reasonably possible that changes to the reserve for uncertain tax benefits may occur as a result of various audits and the expiration of the statute of limitations. As a result of the anticipated closing of certain statute of limitations, the Company expects approximately a range of $1 million to $4 million of uncertain tax position liabilities will be released in the next 12 months and will not significantly impact the Company’s effective rate.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2016
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. The PBGC is conducting an audit of the termination of the pension plan to ensure that Energen properly calculated and distributed benefits in accordance with plan provisions and in compliance with the appropriate laws and regulations administered by the PBGC. Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans were partially made in the first quarter of 2015 with the remainder of approximately $14.5 million paid in the first quarter of 2016. The Company expects to make no additional benefit payments with respect to the termination of the non-qualified supplemental retirement plans. Certain annuities associated with our non-qualified supplemental retirement plans remain of approximately $1.1 million and are included in other current liabilities and other long-term liabilities on the consolidated balance sheets. 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) 2016 2015 2016 2015 Pension Postretirement Benefits Accumulated benefit obligation $ 1,094 $ 15,729 Benefit obligation: Balance at beginning of period $ 15,729 $ 107,669 $ 6,488 $ 11,127 Service cost — — 94 392 Interest cost — 816 223 466 Actuarial (gain) loss (26 ) (683 ) 917 (1,185 ) Plan amendments — — (422 ) (4,071 ) Curtailment gain — — (477 ) — Benefits paid (14,609 ) (92,073 ) (1,376 ) (241 ) Balance at end of period $ 1,094 $ 15,729 $ 5,447 $ 6,488 Plan assets: Fair value of plan assets at beginning of period $ 27 $ 67,542 $ 10,369 $ 10,693 Actual return (loss) on plan assets (27 ) (289 ) 73 (83 ) Employer contributions 14,609 24,847 — — Benefits paid (14,609 ) (92,073 ) (1,376 ) (241 ) Fair value of plan assets at end of period $ — $ 27 $ 9,066 $ 10,369 Funded status of plans $ (1,094 ) $ (15,702 ) $ 3,619 $ 3,881 Noncurrent assets $ — $ — $ 3,619 $ 3,881 Current liabilities (121 ) (15,702 ) — — Noncurrent liabilities (973 ) — — — Net asset (liability) recognized $ (1,094 ) $ (15,702 ) $ 3,619 $ 3,881 Amounts recognized to accumulated other comprehensive income: Prior service credit, net of taxes $ — $ — $ (2,111 ) $ (2,646 ) Net actuarial loss, net of taxes — 2,179 643 205 Total accumulated other comprehensive income (loss) $ — $ 2,179 $ (1,468 ) $ (2,441 ) 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 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) 2016 2015 2014 Pension Plans Components of net periodic benefit cost: Service cost $ — $ — $ 6,808 Interest cost — 816 4,498 Expected long-term return on assets — — (4,386 ) Prior service cost amortization — — 202 Actuarial loss amortization — 737 4,995 Termination benefit charge — — 2,477 Settlement charge 3,325 29,767 4,082 Curtailment expense — — 254 Net periodic expense $ 3,325 $ 31,320 $ 18,930 Postretirement Benefit Plans Components of net periodic benefit cost: Service cost $ 94 $ 392 $ 253 Interest cost 223 466 661 Expected long-term return on assets (316 ) (457 ) (1,122 ) Prior service cost amortization (465 ) — — Actuarial gain amortization — — (653 ) Transition obligation amortization — — 44 Settlement charge 45 — — Curtailment gain (816 ) — — Net periodic (income) expense $ (1,235 ) $ 401 $ (817 ) Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows: Years ended December 31, (in thousands) 2016 2015 2014 Pension Plans Net actuarial (gain) loss experienced during the year $ — $ (394 ) $ 10,495 Net actuarial loss recognized as expense (3,352 ) (30,478 ) (25,433 ) Prior service cost recognized as expense — — (246 ) Curtailment loss — — (8,749 ) Total recognized in other comprehensive income (loss) (3,352 ) (30,872 ) (23,933 ) Postretirement Benefit Plans Net actuarial (gain) loss experienced during the year $ 682 $ (645 ) $ 7,649 Net actuarial gain (loss) recognized as expense (9 ) — 1,908 Prior service cost recognized as income 780 — — Prior service credit during the year (421 ) (4,071 ) — Prior service cost amortization 465 — — Transition obligation recognized as expense — — (48 ) Total recognized in other comprehensive income (loss) $ 1,497 $ (4,716 ) $ 9,509 In the first quarter of 2016, Energen incurred a settlement charge of $3.3 million for the payment of lump sums from the non-qualified supplemental retirement plans. In the three months ended March 31, 2016, Energen incurred a curtailment gain of $0.8 million in connection with the reduction in workforce. 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. Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2017 are included in the table below. (in thousands) Amortization of prior service credit $ (454 ) Amortization of net actuarial loss $ 9 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, 2016 , 2015 and 2014 . Assumptions: The weighted average rate assumptions to determine net periodic benefit costs were as follows: Years ended December 31, 2016 2015 2014 Pension Plans Discount rate — 0.96 % 3.66 % Expected long-term return on plan assets — — 7.00 % Rate of compensation increase for pay-related plans — — 3.63 % Postretirement Benefit Plans Discount rate 4.37 % 4.25 % 4.88 % Expected long-term return on plan assets 4.96 % 6.20 % 7.00 % Rate of compensation increase — — 3.60 % For the year ended December 31, 2015, the discount rate shown above represents the weighted average for the nonqualified supplemental retirement plan. 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, 2016 2015 Pension Plans Discount rate — 3.90 % Postretirement Benefit Plans Discount rate 4.30 % 4.70 % 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, 2016 2015 Health care cost trend rate assumed for next year — 7.75 % Rate to which the cost trend rate is assumed to decline — 5.00 % Year that rate reaches ultimate rate — 2026 Health care costs trend rates will not have a material impact to the accumulated postretirement benefit obligation as employees 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 fixed income investments and equities are used to meet future plan obligations on a long-term basis 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 2016 2015 Target 2016 2015 Asset category: Equity securities — — — 26 % 26 % 56 % Debt securities — — — 74 % 74 % 44 % Cash and cash equivalents — — 100 % — — — Total — — 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 Plan assets included in the funded status of the postretirement benefit plans were as follows: December 31, 2016 (in thousands) Level 1 Level 2 Total Cash and cash equivalents $ 10 $ — $ 10 United States equities 180 — 180 Global equities 2,158 — 2,158 Fixed income 6,718 — 6,718 Total $ 9,066 $ — $ 9,066 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 Energen had no Level 3 postretirement benefit plan assets. United States equities consist 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: 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) Postretirement Benefits 2017 $339 2018 $335 2019 $336 2020 $339 2021 $365 2022-2026 $1,567 Energen Employee Savings Plan (ESP): The Company sponsors the ESP for the benefit of substantially all employees. The ESP allows eligible employees to contribute a percentage of their annual compensation. The Company makes contributions matching a portion of the employee’s contribution and, additionally, makes employer supplemental contributions as a percentage of each employee’s compensation. Expense associated with Energen contributions to the ESP was $3.3 million , $5.7 million and $3.7 million for the years ended December 31, 2016 , 2015 and 2014 , respectively.

COMMON STOCK PLANS

COMMON STOCK PLANS	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
COMMON STOCK PLANS	COMMON STOCK PLANS Stock Incentive Plan: The Stock Incentive Plan provides for the grant of performance share awards and restricted stock units and restricted stock. The Stock Incentive Plan also provides for the grant of non-qualified stock options and incentive stock options to officers and key employees. Under the Stock Incentive Plan, established in 1997, 3,497,920 shares of Energen common stock are reserved for issuance, adjusted for stock splits, with 1,788,492 available for future grants as of December 31, 2016 . Performance Share Awards: The Stock Incentive Plan provides for the grant of performance share awards to eligible employees based on predetermined Energen performance criteria at the end of an award period. The Stock Incentive Plan provides that payment of earned performance share awards be made in the form of Energen common stock. A summary of performance share award activity as of December 31, 2016 , and transactions during the years ended December 31, 2016, 2015 and 2014 is presented below: Stock Incentive Plan Shares Weighted Average Price 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 Granted (three-year vesting period) 167,016 25.34 Vested and paid (74,176 ) 63.88 Forfeited (12,481 ) 72.30 Nonvested at December 31, 2016 336,442 $ 57.03 Energen recorded expense of $6.2 million , $6.7 million and $6.2 million for the years ended December 31, 2016, 2015 and 2014, respectively, for performance share awards with a related deferred income tax benefit of $2.2 million , $2.4 million and $2.3 million . As of December 31, 2016, there was $6.0 million of total unrecognized compensation cost related to performance share awards. These awards have a remaining weighted average requisite service period of 1.68 years. Restricted Stock: In addition, the Stock Incentive Plan provides for the grant of restricted stock and restricted stock units (restricted stock awards) which have been valued based on the quoted market price of Energen’s common stock at the date of grant. Restricted stock awards vest within three years from grant date. A summary of restricted stock award activity as of December 31, 2016 , and transactions during the years ended December 31, 2016 , 2015 and 2014 is presented below: Stock Incentive Plan Awards Weighted Average Price 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 Restricted stock units granted 197,473 29.89 Vested (56,337 ) 54.70 Forfeited (435 ) 40.73 Nonvested at December 31, 2016 325,643 $ 44.44 Energen recorded expense of $5.3 million , $6.0 million and $3.2 million for the years ended December 31, 2016 , 2015 and 2014 , respectively, related to restricted stock awards, with a related deferred income tax benefit of $1.9 million , $2.1 million and $1.2 million , respectively. As of December 31, 2016 , there was $2.4 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 1.77 years. Stock Options: The Stock Incentive Plan provides 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 provides 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 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, 2016 , and transactions during the years ended December 31, 2016 , 2015 and 2014 are presented below: Stock Incentive Plan Shares Weighted Average Exercise Price 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 Exercised (22,490 ) 44.60 Outstanding at December 31, 2016 710,901 $ 55.66 Exercisable at December 31, 2014 454,938 $ 51.88 Exercisable at December 31, 2015 622,156 $ 53.80 Exercisable at December 31, 2016 676,271 $ 54.79 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 Awards granted 2,439 107,868 Fair market value of stock option at grant $32.22 $27.57 Expected life of award 5.8 years 5.8 years Risk-free interest rate 1.93% 2.06% Annualized volatility rate 40.7% 40.7% Dividend yield 0.2% 0.8% Energen recorded stock option expense of $0.1 million , $0.4 million and $2.9 million during the years ended December 31, 2016 , 2015 and 2014 , respectively, with a related deferred tax benefit of $44,000 , $0.1 million and $1.1 million , respectively. The total intrinsic value of stock options exercised during the year ended December 31, 2016 , was $0.2 million . During the year ended December 31, 2016 , Energen received cash of $0.2 million from the exercise of stock options. Total intrinsic value for outstanding options as of December 31, 2016 , was $3.3 million and $3.3 million for exercisable options. The fair value of options vested for the year ended December 31, 2016 was $1.6 million . As of December 31, 2016 , there was an immaterial amount of unrecognized compensation cost related to outstanding nonvested stock options. The following table summarizes options outstanding as of December 31, 2016 : Stock Incentive Plan Range of Exercise Prices Shares Weighted Average Remaining Contractual Life $60.56 48,560 1.00 year $29.79 21,791 2.00 years $46.69 26,481 3.00 years $54.99 104,841 4.00 years $54.11 271,164 5.00 years $48.36 124,071 6.00 years $80.48 3,686 6.79 years $72.39 107,868 7.00 years $79.63 2,439 7.00 years $29.79-$80.48 710,901 4.91 years The weighted average remaining contractual life of currently exercisable stock options is 4.80 years as of December 31, 2016 . Stock Appreciation Rights Plan: The Energen Stock Appreciation Rights Plan provides 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, 2016 , and transactions during the years ended December 31, 2016 , 2015 and 2014 are presented below: Stock Appreciation Rights Plan Shares Weighted Average Exercise Price 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 Exercised/forfeited (12,338 ) 61.51 Outstanding at December 31, 2016 252,529 $ 52.46 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. Certain stock appreciation rights have been modified 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, 2016 : Grant date 1/22/2014 1/22/2014 1/22/2014 1/24/2013 1/24/2013 1/24/2013 1/24/2013 (modified) (modified) (modified) (modified) (modified) Awards granted 46,710 15,517 522 63,436 20,218 768 3,578 Fair market value of award $13.26 $8.82 $7.03 $20.26 $17.75 $16.19 $13.93 Expected life of award 3.56 years 2.13 years 1.63 years 3.03 years 2.13 years 1.63 years 1.00 year Risk-free interest rate 1.61% 1.24% 1.08% 1.48% 1.24% 1.08% 0.85% Annualized volatility rate 39.1% 39.1% 39.1% 39.1% 39.1% 39.1% 39.1% Dividend yield —% —% —% —% —% —% —% Grant date 1/26/2011 1/26/2011 1/27/2010 1/28/2009 2/4/2008 2/1/2007 (modified) Awards granted 182,199 7,785 171,749 305,257 67,093 85,906 Fair market value of award $14.34 $10.36 $16.83 $28.46 $4.38 $11.43 Expected life of award 2.03 years 1.00 year 1.54 years 1.04 years 0.55 years 0.04 years Risk-free interest rate 1.21% 0.85% 1.05% 0.86% 0.64% 0.42% Annualized volatility rate 39.1% 39.1% 39.1% 39.1% 39.1% 39.1% Dividend yield —% —% —% —% —% —% Expense associated with stock appreciation rights of $2.6 million was recorded for the year ended 2016. 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. During the year ended December 31, 2016 , the total intrinsic value of stock appreciation rights exercised was $51,000 . During the year ended December 31, 2016 , Energen paid $35,000 in settlement of stock appreciation rights. Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provides 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 are 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, 2016 , and transactions during the years ended December 31, 2016 , 2015 and 2014 are presented below: Petrotech Incentive Plan Shares 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 Paid (67,392) Forfeited (32,111) Outstanding at December 31, 2016 144,243 Energen recognized expense of $5.4 million , $3.0 million and $4.5 million during 2016 , 2015 and 2014 , respectively, related to these units. 1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allows 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, 2016 there were 573,024 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, 25,470 shares, 11,550 shares and 10,360 shares were awarded during the years ended December 31, 2016 , 2015 and 2014 , respectively, leaving 90,904 shares reserved for issuance as of December 31, 2016 . 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. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2016 and 2015. For the year ended December 31, 2014, Energen repurchased and retired 226,839 shares for $14.9 million pursuant to our repurchase authorization. As of December 31, 2016 , 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, 2016 , 2015 and 2014 , Energen acquired 88,320 shares, 73,126 shares and 32,768 shares, respectively, in connection with its stock compensation plans.

DERIVATIVE COMMODITY INSTRUMENT

DERIVATIVE COMMODITY INSTRUMENTS	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Open non-cash mark-to-market gains (losses) on derivative instruments $ (71,190 ) $ (281,752 ) $ 315,445 Closed gains (losses) on derivative instruments (17,287 ) 397,045 19,574 Gain (loss) on derivative instruments, net $ (88,477 ) $ 115,293 $ 335,019 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, 2016 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 $ 1,756 $ (1,706 ) $ 50 $ — $ — $ 50 Liabilities Derivative instruments 67,173 (1,706 ) 65,467 — — 65,467 Noncurrent derivative instruments 3,006 — 3,006 — — 3,006 Total derivatives $ (68,423 ) $ — $ (68,423 ) $ — $ — $ (68,423 ) (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 Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. Additionally, Energen is at risk of economic loss based upon the creditworthiness of our counterparties. We were in a net loss position with fifteen of our active counterparties and in a gain position with the remaining one at December 31, 2016 . The counterparty net gain position at December 31, 2016 , BP Corporation North America Inc., constituted approximately $0.1 million of Energen’s total net loss 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 Net gain recognized in other comprehensive income on derivatives (effective portion), net of tax of $23 — $ 37 Gain reclassified from accumulated other comprehensive income into income (effective portion) Gain (loss) on derivative instruments, net $ 21,612 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 2016 2015 2014 Gain (loss) recognized in income on derivatives Gain (loss) on derivative instruments, net $ (88,477 ) $ 115,293 $ 313,408 As of December 31, 2016, Energen entered into the following transactions for 2017 and subsequent years: Production Period Description Total Hedged Volumes Average Contract Price Oil 2017 NYMEX Swaps 6,060 MBbl $49.77 Bbl NYMEX Three-Way Collars 4,800 MBbl Ceiling sold price (call) $62.18 Bbl Floor purchased price (put) $45.00 Bbl Floor sold price (put) $35.00 Bbl 2018 NYMEX Three-Way Collars 3,240 MBbl Ceiling sold price (call) $65.03 Bbl Floor purchased price (put) $50.00 Bbl Floor sold price (put) $40.00 Bbl Oil Basis Differential 2017 WTI/WTI Basis Swaps 7,890 MBbl $(0.58) Bbl Natural Gas Liquids 2017 Liquids Swaps 45.4 MMGal $0.52 Gal 2018 Liquids Swaps 30.2 MMGal $0.60 Gal Natural Gas 2017 Basin Specific Swaps - Permian 14.7 Bcf $2.85 Mcf 2017 NYMEX Swaps 0.9 Bcf $3.29 Mcf Natural Gas Basis Differential 2017 Permian Swaps 0.9 Bcf $(0.29) Mcf WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing As of December 31, 2016 , the maximum term over which Energen has hedged exposures to the variability of cash flows is through December 31, 2018. Energen enters into three-way collars which are a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price, above the sold put, that the Company will receive for the contracted volumes. The Company will receive the market price for the contracted volumes if the market price is between the sold call and the purchased put. If, however, the market price for the commodity falls below the sold put strike price, the minimum price that the Company will receive for the contracted volumes equals the market price plus the excess of the purchased put strike price over the sold put strike price.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [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, 2016 (in thousands) Level 2 Level 3 Total Assets Derivative instruments $ 50 $ — $ 50 Liabilities Derivative instruments (57,927 ) (7,540 ) (65,467 ) Noncurrent derivative instruments (1,694 ) (1,312 ) (3,006 ) Net derivative liability $ (59,571 ) $ (8,852 ) $ (68,423 ) 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 The fair value of interest rate swaps was a $0.2 million liability at December 31, 2015 and was 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 $4.4 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) 2016 2015 2014 Balance at beginning of period $ (16,059 ) $ 24,436 $ 18,289 Realized gains (14,120 ) 13,145 22,208 Unrealized gains (losses) relating to instruments held at the reporting date* 5,745 (40,495 ) 2,981 Settlements during period 14,120 (13,145 ) (19,042 ) Transfer out of Level 3 1,462 — — Balance at end of period $ (8,852 ) $ (16,059 ) $ 24,436 *Includes $8.9 million in mark-to-market losses, $16.1 million in mark-to-market losses and $20.2 million in mark-to-market gains for the years ended December 31, 2016, 2015 and 2014, respectively. Changes in Fair Value Levels: The availability of observable market data is monitored to assess the appropriate classification for financial instruments within the fair value hierarchy. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the years ended December 31, 2016, 2015 and 2014, except for the transfer out of Level 3 noted below, there were no significant transfers in or out of Levels 1, 2, or 3. Transfer of Gas Basin Specific Contracts and Gas Basis Contracts: During 2016 the Company determined that its gas basin specific contracts and gas basis contracts met the requirements to be categorized as a Level 2 fair value. The transfer of these assets out of Level 3 was primarily the result of increased price observability of the inputs used in assessing the assets’ fair value throughout the full term of the derivatives. 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, 2016 Valuation Technique* Unobservable Input* Range Oil Basis - WTI/WTI 2017 $ (1,984 ) Discounted Cash Flow Forward Basis ($0.21 - $0.36) Bbl Natural Gas Liquids 2017 $ (5,556 ) Discounted Cash Flow Forward Basis $0.65 Gal 2018 $ (1,312 ) Discounted Cash Flow Forward Basis $0.64 Gal *Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis in Energen’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values. 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. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected field production performance. If a material event occurs, Energen makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, we will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows and values derived from purchase and sale agreements and similar support as applicable. Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These assumptions are classified as Level 3 fair value. See Note 14, Asset Impairment, for impairments recognized by Energen during the years ended December 31, 2016, 2015 and 2014. 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 and 2014 of $919 million and $473 million , respectively, 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 $559.9 million and $690.1 million and has a carrying value of $554.0 million and $776.5 million at December 31, 2016 and 2015, 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, natural gas liquids 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, natural gas liquids 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, natural gas liquids and natural gas, Plains Marketing, LP (Plains) and Shell Trading (US) Company (Shell), accounted for approximately 50 percent and 20 percent, respectively, of Energen’s accounts receivable for commodity sales as of December 31, 2016 . Energen’s other purchasers each accounted for less than 7 percent of these accounts receivable as of December 31, 2016 . During the year ended December 31, 2016 , Plains and Shell accounted for approximately 52 percent and 12 percent , respectively, of total revenues from oil, natural gas liquids and natural gas sales. All other oil and natural gas purchasers each accounted for less than 10 percent of total revenues for the year ended December 31, 2016 .

EXPLORATORY COSTS

EXPLORATORY COSTS	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Capitalized exploratory well costs at beginning of period $ 103,588 $ 119,439 $ 57,600 Additions pending determination of proved reserves 344,045 634,908 946,751 Reclassifications due to determination of proved reserves (282,637 ) (650,759 ) (882,254 ) Exploratory well costs charged to expense — — (2,658 ) Capitalized exploratory well costs at end of period $ 164,996 $ 103,588 $ 119,439 The following table sets forth capitalized exploratory wells costs: (in thousands) December 31, 2016 December 31, 2015 Exploratory wells in progress (drilling rig not released) $ 14,531 $ 1,760 Capitalized exploratory well costs for a period of one year or less 143,602 101,828 Capitalized exploratory well costs for a period greater than one year 6,863 — Total capitalized exploratory well costs $ 164,996 $ 103,588 At December 31, 2016, Energen had 59 gross exploratory wells either drilling or waiting on results from completion and testing in the Permian Basin. At December 31, 2016, Energen had two gross wells capitalized for a period greater than one year. These wells are scheduled for completion during 2017. No wells were capitalized for a period greater than one year as of December 31, 2015.

RECONCILIATION OF EARNINGS PER

RECONCILIATION OF EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
RECONCILIATION OF EARNINGS PER SHARE	RECONCILIATION OF EARNINGS PER SHARE Years ended December 31, (in thousands, except per share amounts) 2016 2015 2014 Net Loss Shares Per Share Amount Net Loss Shares Per Share Amount Net Income Shares Per Share Amount Basic EPS $ (167,513 ) 94,476 $ (1.77 ) $ (945,731 ) 76,078 $ (12.43 ) $ 568,032 72,897 $ 7.79 Effect of dilutive securities Stock options — — 216 Non-vested restricted stock — — 58 Performance share awards — — 104 Diluted EPS $ (167,513 ) 94,476 $ (1.77 ) $ (945,731 ) 76,078 $ (12.43 ) $ 568,032 73,275 $ 7.75 In periods of loss, shares that otherwise would have been included in diluted average commons shares outstanding are excluded. Energen had 330,690 and 355,915 of excluded shares for the years ended December 31, 2016 and 2015, respectively. 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) 2016 2015 2014 Stock options 539 114 114 Non-vested restricted stock — — 3 Performance share awards — — 2

EQUITY OFFERING

EQUITY OFFERING	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
EQUITY OFFERING	EQUITY OFFERING During the first quarter of 2016, Energen issued 18,170,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $381.1 million , after deducting offering expenses. Net proceeds from this offering were used to repay borrowings under our credit facility and for general corporate purposes. 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, 2016
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 4.2 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 quiet title action against Endeavor Energy Resources, L.P. (Endeavor) in the District Court of Howard County, Texas, to remove a cloud on the title to approximately 10,000 acres leased by Energen Resources in that county. Energen Resources believes the cloud on title arises from a prior, unreleased but partially terminated oil and gas lease covering the leased lands. Endeavor filed a counterclaim alleging Energen Resources tortiously interfered with a prospective contract seeking $300 million in damages. On April 28, 2016, the trial judge ruled with respect to the acreage not held by production that Endeavor’s lease terminated prior to the date Energen Resources entered into its lease and additionally ruled that Endeavor’s claim for tortuous interference will be dismissed with prejudice. The order left several ancillary issues for a later ruling. In November 2016, the trial judge entered a final and appealable judgment with respect to the remaining issues and that judgement has been appealed by Endeavor. New Mexico Audits: In 2011, Energen Resources received an Order to Perform Restructured Accounting and Pay Additional Royalties (the Order), following an audit performed by the Taxation and Revenue Department (the Department) of the State of New Mexico on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The Order addressed ONRR’s efforts to change accounting and reporting practices, and to unbundle fees charged by third parties that gather, compress and transport natural gas production. ONRR now maintains that all or some of such fees are not deductible. Energen Resources appealed the Order in 2011 and in July 2012, on a motion from ONRR, the Order was remanded. In August 2014, ONRR issued its Revised Order and Energen Resources appealed the Revised Order. In the Revised Order, ONRR ordered that Energen pay additional royalties on production from certain federal leases in the amount of $129,700 . At ONRR’s request the Revised Order was also remanded in August 2015. On April 15, 2016 ONRR issued its Second Revised Order. The Second Revised Order directs Energen Resources to pay additional royalties of $189,000 , replacing the previous demand of $129,700 . Energen had previously estimated that application of the ONRR position to all of the Company’s federal leases would result in ONRR claims up to approximately $24 million , plus interest and penalties from 2004 forward. ONRR began implementing its unbundling initiative in 2010, but seeks to implement its revisions retroactively, despite the fact that they conflict with previous audits, allowances and industry practice. Energen plans to appeal and vigorously contest the Second Revised Order, the predecessor orders and the findings. Management is unable, at this time, to determine a range of reasonably possible losses, and no amount has been accrued as of December 31, 2016 . Lease Obligations: Energen’s total lease payments included as operating lease expense were $22.6 million , $23.7 million and $24.1 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Minimum future rental payments required after 2016 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows: Years Ending December 31, (in thousands) 2017 2018 2019 2020 2021 2022 and thereafter $3,822 $2,614 $2,448 $— $— $—

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2016
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, 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 Liabilities incurred 230 Liabilities settled (758 ) Accretion expense 6,672 Revision in estimated cash flows (12,875 ) Reclassification associated with held for sale properties*** (1,715 ) Balance as of December 31, 2016 $ 81,544 *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. ***Adjustment to the reclassification of the asset retirement obligation associated with a series of asset sales of certain non-core Permian Basin Assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico.

ASSET IMPAIRMENT

ASSET IMPAIRMENT	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
ASSET IMPAIRMENT	ASSET IMPAIRMENT Impairments recognized by Energen are presented below: Years ended December 31, (in thousands) 2016 2015 2014 Continuing operations Permian Basin properties Central Basin Platform $ 187,043 $ 484,848 $ — Delaware Basin 21,288 607,303 90,594 Midland Basin — — 25,776 San Juan Basin properties 7,519 133,055 230,315 Permian Basin unproved leasehold properties 4,762 29,168 64,361 San Juan Basin unproved leasehold properties 40 37,934 5,755 Total asset impairments from continuing operations 220,652 1,292,308 416,801 Discontinued operations North Louisiana/East Texas oil and natural gas properties — — 1,936 Total asset impairments from discontinued operations — — 1,936 Total asset impairments $ 220,652 $ 1,292,308 $ 418,737 Non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement. Permian Basin: During the first quarter of 2016, Energen recognized non-cash impairment writedowns in the Permian Basin of $208.3 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. Our commodity price assumptions declined in the first quarter of 2016 by approximately 5 percent for oil and 4 percent for natural gas in comparable periods. 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. During 2016, Energen recognized unproved leasehold writedowns primarily on Permian Basin oil properties in the Delaware Basin and the Central Basin Platform of $4.8 million . 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 2014 unproved leasehold writedowns included $55.1 million of expected leasehold expirations. San Juan Basin: During the first quarter of 2016, Energen recognized non-cash impairment writedowns on held for sale properties in the San Juan Basin of $7.5 million to adjust the carrying amount of these properties to their fair value. 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 2014, non-cash impairment writedowns of $230.3 million 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 and direct market data 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. 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.

ACQUISITION AND DISPOSITION OF

ACQUISITION AND DISPOSITION OF PROPERTIES	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
ACQUISITION AND DISPOSITION OF PROPERTIES	ACQUISITION AND DISPOSITION OF PROPERTIES During June, July and August of 2016, Energen completed a series of asset sales of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico for an aggregate purchase price of $552 million . These transactions had closing dates of June 3, 7, 30, July 15 and August 9 of 2016 with various effective dates ranging from March 1, 2016 to June 30, 2016. Minor portions of the assets were transferred to other parties upon the exercise of preferential purchase rights under pre-existing joint operating agreements in the ordinary course of business. Pre-tax proceeds to Energen were approximately $532.9 million after purchase price adjustments of approximately $19 million related to the operations of the properties subsequent to the effective dates and other one-time adjustments including transfer payments and certain amounts due the buyer, but before consideration of transaction costs of approximately $5 million . In the year ended December 31, 2016, Energen recognized pre-tax gains of $246.3 million on the sales. Energen used proceeds from the sale to fund ongoing operations. 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 $143.7 million in various purchases and renewals of unproved leasehold largely in the Permian Basin, including approximately $77 million of acreage purchased in Lea County, New Mexico, during 2016. 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 .

HELD FOR SALE PROPERTIES AND DI

HELD FOR SALE PROPERTIES AND DISCONTINUED OPERATIONS	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
HELD FOR SALE PROPERTIES AND DISCONTINUED OPERATIONS	HELD FOR SALE PROPERTIES AND DISCONTINUED OPERATIONS The following table details San Juan Basin held for sale properties by major classes of assets and liabilities. These property sales in the San Juan Basin do not qualify for discontinued operations: (in thousands) December 31, 2015 Inventories $ 3,651 Oil and natural gas properties 305,386 Less accumulated depreciation, depletion and amortization (219,059 ) Other property and equipment, net 3,761 Total assets held for sale 93,739 Other long-term liabilities (12,789 ) Total liabilities held for sale (12,789 ) Total net assets held for sale $ 80,950 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 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. Energen’s results of operations and cash flows for the year ended December 31, 2014 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: Year ended December 31, (in thousands) 2014 Alagasco net income $ 40,646 Depreciation, depletion and amortization (408 ) General and administrative 3,337 Interest expense (17,306 ) Other income (347 ) Income tax expense 5,567 Alagasco income from discontinued operations 31,489 Energen income (loss) from discontinued operations (2,197 ) Income from discontinued operations $ 29,292 Year ended December 31, (in thousands, except per share data) 2014 Natural gas distribution revenues $ 397,648 Oil and natural gas revenues 5,199 Total revenues $ 402,847 Pretax income from discontinued operations $ 47,220 Income tax expense 17,928 Income From Discontinued Operations $ 29,292 Gain on disposal of discontinued operations, net $ 724,594 Income tax expense 285,497 Gain on Disposal of Discontinued Operations, net $ 439,097 Total Income From Discontinued Operations $ 468,389 Diluted Earnings Per Average Common Share Income from discontinued operations $ 0.40 Gain on disposal of discontinued operations, net 5.99 Total Income From Discontinued Operations $ 6.39 Basic Earnings Per Average Common Share Income from discontinued operations $ 0.40 Gain on disposal of discontinued operations, net 6.02 Total Income From Discontinued Operations $ 6.42 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. 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.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Interest paid, net of amount capitalized $ 35,919 $ 40,747 $ 32,172 Income taxes paid $ 562 $ 8,114 $ 219,505 Noncash investing activities: Accrued development, exploration costs and other capital $ 79,988 $ 79,206 $ 207,461 Capitalized asset retirement obligations costs $ 230 $ 981 $ 2,958 Receivable from sale of Alabama Gas Corporation $ — $ — $ 8,247 Noncash financing activities: Issuance of common stock for employee benefit plans $ 6,675 $ 5,758 $ 2,448 Treasury stock acquired in connection with tax withholdings $ 2,610 $ 4,722 $ 2,547

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects: (in thousands) Balance as of December 31, 2015 $ 263 Other comprehensive income before reclassifications (459 ) Amounts reclassified from accumulated other comprehensive income 1,601 Change in accumulated other comprehensive income (loss) 1,142 Balance as of December 31, 2016 $ 1,405 The following table provides details of the reclassifications out of accumulated other comprehensive income (loss): Years ended December 31, (in thousands) 2016 2015 2014 Amounts Reclassified Line Item Where Presented Gains (losses) on cash flow hedges: Commodity contracts $ — $ — $ 21,611 Gain (loss) on derivative instruments, net Interest rate swap — — (2,280 ) Interest expense Total cash flow hedges — — 19,331 Income tax expense — — (7,414 ) Net of tax — — 11,917 Pension and postretirement plans: Transition obligation — — (22 ) General and administrative Prior service cost 465 — (248 ) General and administrative Actuarial losses (3,058 ) (30,504 ) (21,932 ) General and administrative Total pension and postretirement plans (2,593 ) (30,504 ) (22,202 ) Income tax benefit 992 10,676 7,771 Net of tax (1,601 ) (19,828 ) (14,431 ) Total reclassifications for the period $ (1,601 ) $ (19,828 ) $ (2,514 )

RECENTLY ISSUED ACCOUNTING STAN

RECENTLY ISSUED ACCOUNTING STANDARDS	12 Months Ended
	Dec. 31, 2016
Accounting Changes and Error Corrections [Abstract]
RECENTLY ISSUED ACCOUNTING STANDARDS	RECENTLY ISSUED ACCOUNTING STANDARDS In August 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-15, Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update should be applied using the retrospective transition method. Adoption of this standard will only affect the presentation of the Company’s cash flows and is not expected to have a material impact on the Company’s consolidated financial statements. In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, which makes a number of changes meant to simplify and improve accounting for share-based payments. The amendment is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The adoption of the ASU is not expected to have a material impact on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02, Leases. This update increases transparency and comparability by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendment is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The primary effect of adopting the new standard will be to record assets and obligations on the balance sheet for contracts currently recognized as operating leases. We have identified certain applicable leases under the standard and are currently developing an inventory of all applicable leases. The Company is still evaluating the impact of this standard on our consolidated financial statements. 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. We reclassified the related prior year amount on the balance sheet to conform to the current year presentation. 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 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. The adoption of ASU No. 2015-03 did not have a material impact on the consolidated financial statements of Energen. The additional disclosures are included in Note 3, Long-Term Debt. 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 adoption of the amendments in this ASU did not impact the Company's financial position or results of operations. 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. The Company expects to adopt using the modified retrospective method of adoption on January 1, 2018. We continue to evaluate the impact of this standard on our individual customer contracts, however, due to the short length of our revenue cycle, we do not expect and have not identified any significant impacts to the consolidated financial statements.

SUMMARIZED QUARTERLY FINANCIAL

SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)	SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited) The following data summarizes quarterly operating results: Year ended December 31, 2016 (in thousands, except per share amounts) First Second Third Fourth Revenues $ 128,219 $ 105,765 $ 184,385 $ 114,520 Operating income (loss) $ (301,811 ) $ 68,875 $ 90,302 $ (68,596 ) Income (loss) from continuing operations $ (203,116 ) $ 36,759 $ 53,314 $ (54,470 ) Net income (loss) $ (203,116 ) $ 36,759 $ 53,314 $ (54,470 ) Diluted earnings per average common share Continuing operations $ (2.34 ) $ 0.38 $ 0.55 $ (0.56 ) Net income (loss) $ (2.34 ) $ 0.38 $ 0.55 $ (0.56 ) Basic earnings per average common share Continuing operations $ (2.34 ) $ 0.38 $ 0.55 $ (0.56 ) Net income (loss) $ (2.34 ) $ 0.38 $ 0.55 $ (0.56 ) 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 )

OIL AND NATURAL GAS OPERATIONS

OIL AND NATURAL GAS OPERATIONS (Unaudited)	12 Months Ended
	Dec. 31, 2016
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, 2016 December 31, 2015 Proved $ 7,543,464 $ 7,911,554 Unproved 196,888 150,674 Total capitalized costs 7,740,352 8,062,228 Accumulated depreciation, depletion and amortization 3,723,669 3,673,569 Capitalized costs, net $ 4,016,683 $ 4,388,659 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) 2016 2015 2014 Property acquisition: Proved $ 4,066 $ 1,866 $ 2,582 Unproved 143,667 85,690 68,514 Exploration 349,463 649,764 972,164 Development 89,624 372,177 408,949 Total costs incurred $ 586,820 $ 1,109,497 $ 1,452,209 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) 2016 2015 2014 Gross revenues* $ 532,889 $ 878,554 $ 1,679,213 Production (lifting costs) 214,652 285,760 376,495 Exploration expense 5,415 14,877 28,090 Depreciation, depletion and amortization including asset impairments 663,659 1,880,190 960,539 Accretion expense 6,672 7,108 7,608 Income tax expense (benefit) (123,153 ) (469,362 ) 99,469 Results of operations from producing activities $ (234,356 ) $ (840,019 ) $ 207,012 * The years ended December 31, 2016, 2015 and 2014 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $71.2 million , a pre-tax non-cash mark-to-market loss on derivatives of $281.8 million and a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million , respectively. Oil and Natural Gas Reserves: 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, 2016 , 2015 and 2014 . 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), 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, 2016 . Ryder Scott audited the proved reserve estimates for substantially all of the Permian Basin proved 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, 2016 Oil MBbl NGL MBbl Natural Gas MMcf Total MMBOE Proved reserves at beginning of period 210,691 71,713 433,904 354.7 Revisions of previous estimates (17,840 ) (6,800 ) (7,779 ) (26.0 ) Purchases 103 21 89 0.1 Extensions and discoveries 45,129 10,480 50,780 64.1 Production (13,213 ) (3,892 ) (27,204 ) (21.6 ) Sales (25,295 ) (13,476 ) (97,542 ) (55.0 ) Proved reserves at end of period 199,575 58,046 352,248 316.3 Proved developed reserves at end of period 101,202 29,767 187,117 162.1 Proved undeveloped reserves at end of period 98,373 28,279 165,131 154.2 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 0.0 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 29,695 141,209 130.0 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 2016 Activities: Energen had net downward reserve revisions during 2016 which totaled 26.0 MMBOE including approximately 10.6 MMBOE related to changes in year-end pricing and downward revisions of approximately 22.9 MMBOE of proved undeveloped reserves that will no longer be developed in the five-year time horizon due to development being delayed to focus on other assets with higher returns. Net upward reserve revisions of 7.5 MMBOE due to factors other than price included increased lateral length, lower lease operating expense and improved well performance partially offset by changes in plant yields. Energen purchased 0.1 MMBOE of reserves during 2016 primarily related to the acquisition of oil properties in the Permian Basin. During 2016, Energen had extensions and discoveries of 64.1 MMBOE of which 65 percent were proved undeveloped reserves and 35 percent were proved developed reserves. Extension drilling resulted in no discoveries with exploratory drilling providing 64.1 MMBOE of discoveries. During 2016, Energen had sales of 55 MMBOE primarily due to the sale of certain non-core Permian Basin assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico. 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 acquisition 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. 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) 2016 2015 2014 Future gross revenues $ 9,191,808 $ 11,714,729 $ 20,971,672 Future production costs 3,126,153 4,353,974 7,532,273 Future development costs 1,632,577 1,961,661 1,784,738 Future income tax expense 762,921 1,065,887 3,440,582 Future net cash flows 3,670,157 4,333,207 8,214,079 Discount at 10% per annum 2,320,350 2,299,859 3,994,423 Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 1,349,807 $ 2,033,348 $ 4,219,656 The following are the principal sources of changes in the standardized measure of discounted future net cash flows: Years ended December 31, (in thousands) 2016 2015 2014 Balance at beginning of year $ 2,033,348 $ 4,219,656 $ 4,017,841 Revisions to reserves proved in prior years: Net changes in prices, production costs and future development costs (221,639 ) (2,861,591 ) (1,147,028 ) Net changes due to revisions in quantity estimates (167,188 ) (404,708 ) (1,285,394 ) Development costs incurred, previously estimated 71,099 350,560 337,198 Accretion of discount 203,335 421,966 401,784 Changes in timing and other* (100,742 ) (903,975 ) 987,652 Total revisions (215,135 ) (3,397,748 ) (705,788 ) New field discoveries and extensions, net of future production and development costs 352,358 776,315 2,321,028 Sales of oil and gas produced, net of production costs (440,446 ) (514,380 ) (1,054,553 ) Purchases 1,733 8 4,241 Sales (235,222 ) (372,039 ) (21,092 ) Net change in income taxes (146,829 ) 1,321,536 (342,021 ) Net change in standardized measure of discounted future net cash flows (683,541 ) (2,186,308 ) 201,815 Balance at end of year $ 1,349,807 $ 2,033,348 $ 4,219,656 *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 ACCOUN32

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Principles of Consolidation	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.
Estimates	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.
Cash and Cash Equivalents	ash 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	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.
Accounts Receivable and Allowance for Doubtful Accounts	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.
Inventory	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.
Operating Revenues	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.
Property and Related Depletion	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.
Asset Impairments	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. 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 and sale agreements and similar support as applicable. Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These 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.
Acquisitions	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.
Held for Sale Properties and Discontinued Operations	Held for Sale Properties 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.
Derivative Commodity Instruments	Derivative Commodity Instruments We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps, options 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.
Fair Value Measurements	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 direct or indirect observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps and options priced in reference to NYMEX oil and natural gas prices, basin specific gas hedges and gas basis. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include oil basis and natural gas liquids swaps. We consider the frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While Energen does not have access to the specific assumptions used in its counterparties’ valuation models, 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.
Stock-Based Compensation	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.
Environmental Costs	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.
Income Taxes	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.
Earnings Per Share (EPS)	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.
Employee Benefit Plans	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. The Pension Benefit Guaranty Corporation (PBGC) is conducting an audit of the termination of the pension plan to ensure that Energen properly calculated and distributed benefits in accordance with plan provisions and in compliance with the appropriate laws and regulations administered by the PBGC. Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans were partially made in the first quarter of 2015 with the remainder of approximately $14.5 million paid in the first quarter of 2016. The Company expects to make no additional benefit payments with respect to the termination of the non-qualified supplemental retirement plans. 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 these 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.

RECENTLY ISSUED ACCOUNTING ST33

RECENTLY ISSUED ACCOUNTING STANDARDS (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Changes and Error Corrections [Abstract]
New Accounting Pronouncements	In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, which makes a number of changes meant to simplify and improve accounting for share-based payments. The amendment is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The adoption of the ASU is not expected to have a material impact on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02, Leases. This update increases transparency and comparability by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendment is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The primary effect of adopting the new standard will be to record assets and obligations on the balance sheet for contracts currently recognized as operating leases. We have identified certain applicable leases under the standard and are currently developing an inventory of all applicable leases. The Company is still evaluating the impact of this standard on our consolidated financial statements. 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. We reclassified the related prior year amount on the balance sheet to conform to the current year presentation. 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 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. The adoption of ASU No. 2015-03 did not have a material impact on the consolidated financial statements of Energen. The additional disclosures are included in Note 3, Long-Term Debt. 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 adoption of the amendments in this ASU did not impact the Company's financial position or results of operations. 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. The Company expects to adopt using the modified retrospective method of adoption on January 1, 2018. We continue to evaluate the impact of this standard on our individual customer contracts, however, due to the short length of our revenue cycle, we do not expect and have not identified any significant impacts to the consolidated financial statements.

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	Long-term debt consisted of the following: (in thousands) December 31, 2016 December 31, 2015 Credit facility $ — $ 222,500 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 554,000 776,500 Less amounts due within one year 24,000 — Less unamortized debt discount 387 413 Less unamortized debt issuance costs 2,170 2,537 Total $ 527,443 $ 773,550
Schedule of Aggregate Maturities of Long-Term Debt	The aggregate maturities of Energen’s long-term debt as of December 31, 2016 are as follows: Years ending December 31, (in thousands) 2017 2018 2019 2020 2021 Thereafter $24,000 $— $— $— $400,000 $130,000
Schedule of Credit Facilities	The following is a summary of information relating to Energen’s credit facility: (in thousands) December 31, 2016 December 31, 2015 Credit facility outstanding $ — $ 222,500 Available for borrowings 1,050,000 1,177,500 Total borrowing commitments $ 1,050,000 $ 1,400,000 Maximum amount outstanding at any month-end $ 214,500 $ 685,000 Average daily amount outstanding $ 33,642 $ 358,929 Weighted average interest rates based on: Average daily amount outstanding 1.72 % 1.60 % Amount outstanding at year-end — % 1.64 %

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Taxes estimated to be payable currently: Federal $ (23,277 ) $ 3,972 $ 161,576 State 832 758 72,379 Total current (22,445 ) 4,730 233,955 Taxes deferred: Federal (62,205 ) (513,187 ) 144,645 State 5,012 (26,548 ) (34,447 ) Total deferred (57,193 ) (539,735 ) 110,198 Total income tax expense (benefit) $ (79,638 ) $ (535,005 ) $ 344,153
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) 2016 2015 2014 Income tax expense (benefit) from continuing operations $ (79,638 ) $ (535,005 ) $ 40,728 Income tax expense from discontinued operations — — 17,928 Income tax expense from gain on disposal of discontinued operations — — 285,497 Total income tax expense (benefit) $ (79,638 ) $ (535,005 ) $ 344,153
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, 2016 December 31, 2015 Noncurrent Noncurrent Deferred tax assets: Minimum tax credit $ 64,203 $ 44,862 Allowance for doubtful accounts 222 253 Insurance and other accruals 3,151 2,807 Compensation accruals 13,895 11,650 Deferred compensation and other costs 5,401 8,693 Derivative instruments 22,402 — State net operating losses and other carryforwards 12,947 12,577 Other 313 — Total deferred tax assets 122,534 80,842 Valuation allowance (5,735 ) (3,235 ) Total deferred tax assets 116,799 77,607 Deferred tax liabilities: Depreciation and basis differences 603,324 620,629 Derivative instruments — 2,838 Other comprehensive income 854 141 Other 8,509 6,368 Total deferred tax liabilities 612,687 629,976 Net deferred tax liabilities $ (495,888 ) $ (552,369 )
Schedule of Effective Income Tax Rate Reconciliation	Total income tax expense from continuing operations differs 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) 2016 2015 2014 Income tax expense (benefit) at statutory federal income tax rate $ (86,503 ) $ (518,258 ) $ 49,130 Increase (decrease) resulting from: State income taxes, net of federal income tax benefit 925 (15,417 ) (459 ) Impact of state law changes (9 ) (3,075 ) (121 ) Impact of state deferred tax revaluation on San Juan properties (153 ) (1,241 ) (8,382 ) Change in deferred tax valuation allowance 2,500 1,305 552 Other, net 3,602 1,681 8 Total income tax expense (benefit) $ (79,638 ) $ (535,005 ) $ 40,728 Effective income tax rate (%) 32.22 36.13 29.01
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, 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 Additions based on tax positions related to the current year 2,936 Additions for tax positions of prior years 1,484 Reductions for tax positions of prior years (99 ) Lapse of statute of limitations (1,300 ) Balance as of December 31, 2016 $ 14,210

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2016 2015 Pension Postretirement Benefits Accumulated benefit obligation $ 1,094 $ 15,729 Benefit obligation: Balance at beginning of period $ 15,729 $ 107,669 $ 6,488 $ 11,127 Service cost — — 94 392 Interest cost — 816 223 466 Actuarial (gain) loss (26 ) (683 ) 917 (1,185 ) Plan amendments — — (422 ) (4,071 ) Curtailment gain — — (477 ) — Benefits paid (14,609 ) (92,073 ) (1,376 ) (241 ) Balance at end of period $ 1,094 $ 15,729 $ 5,447 $ 6,488 Plan assets: Fair value of plan assets at beginning of period $ 27 $ 67,542 $ 10,369 $ 10,693 Actual return (loss) on plan assets (27 ) (289 ) 73 (83 ) Employer contributions 14,609 24,847 — — Benefits paid (14,609 ) (92,073 ) (1,376 ) (241 ) Fair value of plan assets at end of period $ — $ 27 $ 9,066 $ 10,369 Funded status of plans $ (1,094 ) $ (15,702 ) $ 3,619 $ 3,881 Noncurrent assets $ — $ — $ 3,619 $ 3,881 Current liabilities (121 ) (15,702 ) — — Noncurrent liabilities (973 ) — — — Net asset (liability) recognized $ (1,094 ) $ (15,702 ) $ 3,619 $ 3,881 Amounts recognized to accumulated other comprehensive income: Prior service credit, net of taxes $ — $ — $ (2,111 ) $ (2,646 ) Net actuarial loss, net of taxes — 2,179 643 205 Total accumulated other comprehensive income (loss) $ — $ 2,179 $ (1,468 ) $ (2,441 )
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 2016 2015 Target 2016 2015 Asset category: Equity securities — — — 26 % 26 % 56 % Debt securities — — — 74 % 74 % 44 % Cash and cash equivalents — — 100 % — — — Total — — 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) 2016 2015 2014 Pension Plans Components of net periodic benefit cost: Service cost $ — $ — $ 6,808 Interest cost — 816 4,498 Expected long-term return on assets — — (4,386 ) Prior service cost amortization — — 202 Actuarial loss amortization — 737 4,995 Termination benefit charge — — 2,477 Settlement charge 3,325 29,767 4,082 Curtailment expense — — 254 Net periodic expense $ 3,325 $ 31,320 $ 18,930 Postretirement Benefit Plans Components of net periodic benefit cost: Service cost $ 94 $ 392 $ 253 Interest cost 223 466 661 Expected long-term return on assets (316 ) (457 ) (1,122 ) Prior service cost amortization (465 ) — — Actuarial gain amortization — — (653 ) Transition obligation amortization — — 44 Settlement charge 45 — — Curtailment gain (816 ) — — Net periodic (income) expense $ (1,235 ) $ 401 $ (817 )
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) 2016 2015 2014 Pension Plans Net actuarial (gain) loss experienced during the year $ — $ (394 ) $ 10,495 Net actuarial loss recognized as expense (3,352 ) (30,478 ) (25,433 ) Prior service cost recognized as expense — — (246 ) Curtailment loss — — (8,749 ) Total recognized in other comprehensive income (loss) (3,352 ) (30,872 ) (23,933 ) Postretirement Benefit Plans Net actuarial (gain) loss experienced during the year $ 682 $ (645 ) $ 7,649 Net actuarial gain (loss) recognized as expense (9 ) — 1,908 Prior service cost recognized as income 780 — — Prior service credit during the year (421 ) (4,071 ) — Prior service cost amortization 465 — — Transition obligation recognized as expense — — (48 ) Total recognized in other comprehensive income (loss) $ 1,497 $ (4,716 ) $ 9,509
Schedule of Estimated Amount to be Amortized from Accumulated Other Comprehensive Income	Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2017 are included in the table below. (in thousands) Amortization of prior service credit $ (454 ) Amortization of net actuarial loss $ 9
Schedule of Weighted Average Rate Assumptions	The weighted average rate assumptions to determine net periodic benefit costs were as follows: Years ended December 31, 2016 2015 2014 Pension Plans Discount rate — 0.96 % 3.66 % Expected long-term return on plan assets — — 7.00 % Rate of compensation increase for pay-related plans — — 3.63 % Postretirement Benefit Plans Discount rate 4.37 % 4.25 % 4.88 % Expected long-term return on plan assets 4.96 % 6.20 % 7.00 % Rate of compensation increase — — 3.60 % For the year ended December 31, 2015, the discount rate shown above represents the weighted average for the nonqualified supplemental retirement plan. 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, 2016 2015 Pension Plans Discount rate — 3.90 % Postretirement Benefit Plans Discount rate 4.30 % 4.70 %
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, 2016 2015 Health care cost trend rate assumed for next year — 7.75 % Rate to which the cost trend rate is assumed to decline — 5.00 % Year that rate reaches ultimate rate — 2026
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) Postretirement Benefits 2017 $339 2018 $335 2019 $336 2020 $339 2021 $365 2022-2026 $1,567
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
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, 2016 (in thousands) Level 1 Level 2 Total Cash and cash equivalents $ 10 $ — $ 10 United States equities 180 — 180 Global equities 2,158 — 2,158 Fixed income 6,718 — 6,718 Total $ 9,066 $ — $ 9,066 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
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

COMMON STOCK PLANS (Tables)

COMMON STOCK PLANS (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , and transactions during the years ended December 31, 2016, 2015 and 2014 is presented below: Stock Incentive Plan Shares Weighted Average Price 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 Granted (three-year vesting period) 167,016 25.34 Vested and paid (74,176 ) 63.88 Forfeited (12,481 ) 72.30 Nonvested at December 31, 2016 336,442 $ 57.03
Schedule of Restricted Stock Activity and Transactions	A summary of restricted stock award activity as of December 31, 2016 , and transactions during the years ended December 31, 2016 , 2015 and 2014 is presented below: Stock Incentive Plan Awards Weighted Average Price 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 Restricted stock units granted 197,473 29.89 Vested (56,337 ) 54.70 Forfeited (435 ) 40.73 Nonvested at December 31, 2016 325,643 $ 44.44
Schedule of Stock Option Activity and Transactions	A summary of stock option activity as of December 31, 2016 , and transactions during the years ended December 31, 2016 , 2015 and 2014 are presented below: Stock Incentive Plan Shares Weighted Average Exercise Price 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 Exercised (22,490 ) 44.60 Outstanding at December 31, 2016 710,901 $ 55.66 Exercisable at December 31, 2014 454,938 $ 51.88 Exercisable at December 31, 2015 622,156 $ 53.80 Exercisable at December 31, 2016 676,271 $ 54.79
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 Awards granted 2,439 107,868 Fair market value of stock option at grant $32.22 $27.57 Expected life of award 5.8 years 5.8 years Risk-free interest rate 1.93% 2.06% Annualized volatility rate 40.7% 40.7% Dividend yield 0.2% 0.8%
Schedule of Outstanding Stock Options by Range of Exercise Prices	The following table summarizes options outstanding as of December 31, 2016 : Stock Incentive Plan Range of Exercise Prices Shares Weighted Average Remaining Contractual Life $60.56 48,560 1.00 year $29.79 21,791 2.00 years $46.69 26,481 3.00 years $54.99 104,841 4.00 years $54.11 271,164 5.00 years $48.36 124,071 6.00 years $80.48 3,686 6.79 years $72.39 107,868 7.00 years $79.63 2,439 7.00 years $29.79-$80.48 710,901 4.91 years
Summary of Stock Appreciation Rights Activity	A summary of stock appreciation rights activity as of December 31, 2016 , and transactions during the years ended December 31, 2016 , 2015 and 2014 are presented below: Stock Appreciation Rights Plan Shares Weighted Average Exercise Price 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 Exercised/forfeited (12,338 ) 61.51 Outstanding at December 31, 2016 252,529 $ 52.46
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, 2016 : Grant date 1/22/2014 1/22/2014 1/22/2014 1/24/2013 1/24/2013 1/24/2013 1/24/2013 (modified) (modified) (modified) (modified) (modified) Awards granted 46,710 15,517 522 63,436 20,218 768 3,578 Fair market value of award $13.26 $8.82 $7.03 $20.26 $17.75 $16.19 $13.93 Expected life of award 3.56 years 2.13 years 1.63 years 3.03 years 2.13 years 1.63 years 1.00 year Risk-free interest rate 1.61% 1.24% 1.08% 1.48% 1.24% 1.08% 0.85% Annualized volatility rate 39.1% 39.1% 39.1% 39.1% 39.1% 39.1% 39.1% Dividend yield —% —% —% —% —% —% —% Grant date 1/26/2011 1/26/2011 1/27/2010 1/28/2009 2/4/2008 2/1/2007 (modified) Awards granted 182,199 7,785 171,749 305,257 67,093 85,906 Fair market value of award $14.34 $10.36 $16.83 $28.46 $4.38 $11.43 Expected life of award 2.03 years 1.00 year 1.54 years 1.04 years 0.55 years 0.04 years Risk-free interest rate 1.21% 0.85% 1.05% 0.86% 0.64% 0.42% Annualized volatility rate 39.1% 39.1% 39.1% 39.1% 39.1% 39.1% Dividend yield —% —% —% —% —% —%
Schedule of Incentive Units Activity	A summary of Petrotech unit activity as of December 31, 2016 , and transactions during the years ended December 31, 2016 , 2015 and 2014 are presented below: Petrotech Incentive Plan Shares 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 Paid (67,392) Forfeited (32,111) Outstanding at December 31, 2016 144,243

DERIVATIVE COMMODITY INSTRUME38

DERIVATIVE COMMODITY INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Open non-cash mark-to-market gains (losses) on derivative instruments $ (71,190 ) $ (281,752 ) $ 315,445 Closed gains (losses) on derivative instruments (17,287 ) 397,045 19,574 Gain (loss) on derivative instruments, net $ (88,477 ) $ 115,293 $ 335,019
Schedule of Offsetting Liabilities	The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets: (in thousands) December 31, 2016 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 $ 1,756 $ (1,706 ) $ 50 $ — $ — $ 50 Liabilities Derivative instruments 67,173 (1,706 ) 65,467 — — 65,467 Noncurrent derivative instruments 3,006 — 3,006 — — 3,006 Total derivatives $ (68,423 ) $ — $ (68,423 ) $ — $ — $ (68,423 ) (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
Schedule of Offsetting Assets	The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets: (in thousands) December 31, 2016 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 $ 1,756 $ (1,706 ) $ 50 $ — $ — $ 50 Liabilities Derivative instruments 67,173 (1,706 ) 65,467 — — 65,467 Noncurrent derivative instruments 3,006 — 3,006 — — 3,006 Total derivatives $ (68,423 ) $ — $ (68,423 ) $ — $ — $ (68,423 ) (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
Schedule of Derivative Assets and Liabilities at Fair Value	The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis: December 31, 2016 (in thousands) Level 2 Level 3 Total Assets Derivative instruments $ 50 $ — $ 50 Liabilities Derivative instruments (57,927 ) (7,540 ) (65,467 ) Noncurrent derivative instruments (1,694 ) (1,312 ) (3,006 ) Net derivative liability $ (59,571 ) $ (8,852 ) $ (68,423 ) 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
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 Net gain recognized in other comprehensive income on derivatives (effective portion), net of tax of $23 — $ 37 Gain reclassified from accumulated other comprehensive income into income (effective portion) Gain (loss) on derivative instruments, net $ 21,612
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 2016 2015 2014 Gain (loss) recognized in income on derivatives Gain (loss) on derivative instruments, net $ (88,477 ) $ 115,293 $ 313,408
Schedule of Hedging Transactions	As of December 31, 2016, Energen entered into the following transactions for 2017 and subsequent years: Production Period Description Total Hedged Volumes Average Contract Price Oil 2017 NYMEX Swaps 6,060 MBbl $49.77 Bbl NYMEX Three-Way Collars 4,800 MBbl Ceiling sold price (call) $62.18 Bbl Floor purchased price (put) $45.00 Bbl Floor sold price (put) $35.00 Bbl 2018 NYMEX Three-Way Collars 3,240 MBbl Ceiling sold price (call) $65.03 Bbl Floor purchased price (put) $50.00 Bbl Floor sold price (put) $40.00 Bbl Oil Basis Differential 2017 WTI/WTI Basis Swaps 7,890 MBbl $(0.58) Bbl Natural Gas Liquids 2017 Liquids Swaps 45.4 MMGal $0.52 Gal 2018 Liquids Swaps 30.2 MMGal $0.60 Gal Natural Gas 2017 Basin Specific Swaps - Permian 14.7 Bcf $2.85 Mcf 2017 NYMEX Swaps 0.9 Bcf $3.29 Mcf Natural Gas Basis Differential 2017 Permian Swaps 0.9 Bcf $(0.29) Mcf WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Liabilities at Fair Value	The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis: December 31, 2016 (in thousands) Level 2 Level 3 Total Assets Derivative instruments $ 50 $ — $ 50 Liabilities Derivative instruments (57,927 ) (7,540 ) (65,467 ) Noncurrent derivative instruments (1,694 ) (1,312 ) (3,006 ) Net derivative liability $ (59,571 ) $ (8,852 ) $ (68,423 ) 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
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) 2016 2015 2014 Balance at beginning of period $ (16,059 ) $ 24,436 $ 18,289 Realized gains (14,120 ) 13,145 22,208 Unrealized gains (losses) relating to instruments held at the reporting date* 5,745 (40,495 ) 2,981 Settlements during period 14,120 (13,145 ) (19,042 ) Transfer out of Level 3 1,462 — — Balance at end of period $ (8,852 ) $ (16,059 ) $ 24,436 *Includes $8.9 million in mark-to-market losses, $16.1 million in mark-to-market losses and $20.2 million in mark-to-market gains for the years ended December 31, 2016, 2015 and 2014, 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, 2016 Valuation Technique* Unobservable Input* Range Oil Basis - WTI/WTI 2017 $ (1,984 ) Discounted Cash Flow Forward Basis ($0.21 - $0.36) Bbl Natural Gas Liquids 2017 $ (5,556 ) Discounted Cash Flow Forward Basis $0.65 Gal 2018 $ (1,312 ) Discounted Cash Flow Forward Basis $0.64 Gal *Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

EXPLORATORY COSTS (Tables)

EXPLORATORY COSTS (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Capitalized exploratory well costs at beginning of period $ 103,588 $ 119,439 $ 57,600 Additions pending determination of proved reserves 344,045 634,908 946,751 Reclassifications due to determination of proved reserves (282,637 ) (650,759 ) (882,254 ) Exploratory well costs charged to expense — — (2,658 ) Capitalized exploratory well costs at end of period $ 164,996 $ 103,588 $ 119,439 The following table sets forth capitalized exploratory wells costs: (in thousands) December 31, 2016 December 31, 2015 Exploratory wells in progress (drilling rig not released) $ 14,531 $ 1,760 Capitalized exploratory well costs for a period of one year or less 143,602 101,828 Capitalized exploratory well costs for a period greater than one year 6,863 — Total capitalized exploratory well costs $ 164,996 $ 103,588

RECONCILIATION OF EARNINGS PE41

RECONCILIATION OF EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation	Years ended December 31, (in thousands, except per share amounts) 2016 2015 2014 Net Loss Shares Per Share Amount Net Loss Shares Per Share Amount Net Income Shares Per Share Amount Basic EPS $ (167,513 ) 94,476 $ (1.77 ) $ (945,731 ) 76,078 $ (12.43 ) $ 568,032 72,897 $ 7.79 Effect of dilutive securities Stock options — — 216 Non-vested restricted stock — — 58 Performance share awards — — 104 Diluted EPS $ (167,513 ) 94,476 $ (1.77 ) $ (945,731 ) 76,078 $ (12.43 ) $ 568,032 73,275 $ 7.75
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) 2016 2015 2014 Stock options 539 114 114 Non-vested restricted stock — — 3 Performance share awards — — 2

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Minimum Future Rental Payments	Minimum future rental payments required after 2016 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows: Years Ending December 31, (in thousands) 2017 2018 2019 2020 2021 2022 and thereafter $3,822 $2,614 $2,448 $— $— $—

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2016
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, 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 Liabilities incurred 230 Liabilities settled (758 ) Accretion expense 6,672 Revision in estimated cash flows (12,875 ) Reclassification associated with held for sale properties*** (1,715 ) Balance as of December 31, 2016 $ 81,544 *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. ***Adjustment to the reclassification of the asset retirement obligation associated with a series of asset sales of certain non-core Permian Basin Assets in the Delaware Basin in Texas and in the San Juan Basin in New Mexico.

ASSET IMPAIRMENT (Tables)

ASSET IMPAIRMENT (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Impairment of Long-Lived Assets Held and Used by Asset	Impairments recognized by Energen are presented below: Years ended December 31, (in thousands) 2016 2015 2014 Continuing operations Permian Basin properties Central Basin Platform $ 187,043 $ 484,848 $ — Delaware Basin 21,288 607,303 90,594 Midland Basin — — 25,776 San Juan Basin properties 7,519 133,055 230,315 Permian Basin unproved leasehold properties 4,762 29,168 64,361 San Juan Basin unproved leasehold properties 40 37,934 5,755 Total asset impairments from continuing operations 220,652 1,292,308 416,801 Discontinued operations North Louisiana/East Texas oil and natural gas properties — — 1,936 Total asset impairments from discontinued operations — — 1,936 Total asset impairments $ 220,652 $ 1,292,308 $ 418,737

HELD FOR SALE PROPERTIES AND 45

HELD FOR SALE PROPERTIES AND DISCONTINUED OPERATIONS (Tables)	12 Months Ended
	Dec. 31, 2016
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. These property sales in the San Juan Basin do not qualify for discontinued operations: (in thousands) December 31, 2015 Inventories $ 3,651 Oil and natural gas properties 305,386 Less accumulated depreciation, depletion and amortization (219,059 ) Other property and equipment, net 3,761 Total assets held for sale 93,739 Other long-term liabilities (12,789 ) Total liabilities held for sale (12,789 ) Total net assets held for sale $ 80,950 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: Year ended December 31, (in thousands) 2014 Alagasco net income $ 40,646 Depreciation, depletion and amortization (408 ) General and administrative 3,337 Interest expense (17,306 ) Other income (347 ) Income tax expense 5,567 Alagasco income from discontinued operations 31,489 Energen income (loss) from discontinued operations (2,197 ) Income from discontinued operations $ 29,292 Year ended December 31, (in thousands, except per share data) 2014 Natural gas distribution revenues $ 397,648 Oil and natural gas revenues 5,199 Total revenues $ 402,847 Pretax income from discontinued operations $ 47,220 Income tax expense 17,928 Income From Discontinued Operations $ 29,292 Gain on disposal of discontinued operations, net $ 724,594 Income tax expense 285,497 Gain on Disposal of Discontinued Operations, net $ 439,097 Total Income From Discontinued Operations $ 468,389 Diluted Earnings Per Average Common Share Income from discontinued operations $ 0.40 Gain on disposal of discontinued operations, net 5.99 Total Income From Discontinued Operations $ 6.39 Basic Earnings Per Average Common Share Income from discontinued operations $ 0.40 Gain on disposal of discontinued operations, net 6.02 Total Income From Discontinued Operations $ 6.42

SUPPLEMENTAL CASH FLOW INFORM46

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Interest paid, net of amount capitalized $ 35,919 $ 40,747 $ 32,172 Income taxes paid $ 562 $ 8,114 $ 219,505 Noncash investing activities: Accrued development, exploration costs and other capital $ 79,988 $ 79,206 $ 207,461 Capitalized asset retirement obligations costs $ 230 $ 981 $ 2,958 Receivable from sale of Alabama Gas Corporation $ — $ — $ 8,247 Noncash financing activities: Issuance of common stock for employee benefit plans $ 6,675 $ 5,758 $ 2,448 Treasury stock acquired in connection with tax withholdings $ 2,610 $ 4,722 $ 2,547

ACCUMULATED OTHER COMPREHENSI47

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)	12 Months Ended
	Dec. 31, 2016
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) Balance as of December 31, 2015 $ 263 Other comprehensive income before reclassifications (459 ) Amounts reclassified from accumulated other comprehensive income 1,601 Change in accumulated other comprehensive income (loss) 1,142 Balance as of December 31, 2016 $ 1,405
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) 2016 2015 2014 Amounts Reclassified Line Item Where Presented Gains (losses) on cash flow hedges: Commodity contracts $ — $ — $ 21,611 Gain (loss) on derivative instruments, net Interest rate swap — — (2,280 ) Interest expense Total cash flow hedges — — 19,331 Income tax expense — — (7,414 ) Net of tax — — 11,917 Pension and postretirement plans: Transition obligation — — (22 ) General and administrative Prior service cost 465 — (248 ) General and administrative Actuarial losses (3,058 ) (30,504 ) (21,932 ) General and administrative Total pension and postretirement plans (2,593 ) (30,504 ) (22,202 ) Income tax benefit 992 10,676 7,771 Net of tax (1,601 ) (19,828 ) (14,431 ) Total reclassifications for the period $ (1,601 ) $ (19,828 ) $ (2,514 )

SUMMARIZED QUARTERLY FINANCIA48

SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Operating Results	The following data summarizes quarterly operating results: Year ended December 31, 2016 (in thousands, except per share amounts) First Second Third Fourth Revenues $ 128,219 $ 105,765 $ 184,385 $ 114,520 Operating income (loss) $ (301,811 ) $ 68,875 $ 90,302 $ (68,596 ) Income (loss) from continuing operations $ (203,116 ) $ 36,759 $ 53,314 $ (54,470 ) Net income (loss) $ (203,116 ) $ 36,759 $ 53,314 $ (54,470 ) Diluted earnings per average common share Continuing operations $ (2.34 ) $ 0.38 $ 0.55 $ (0.56 ) Net income (loss) $ (2.34 ) $ 0.38 $ 0.55 $ (0.56 ) Basic earnings per average common share Continuing operations $ (2.34 ) $ 0.38 $ 0.55 $ (0.56 ) Net income (loss) $ (2.34 ) $ 0.38 $ 0.55 $ (0.56 ) 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 )

OIL AND NATURAL GAS OPERATION49

OIL AND NATURAL GAS OPERATIONS (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Schedule of Capitalized Costs	The following table sets forth capitalized costs: (in thousands) December 31, 2016 December 31, 2015 Proved $ 7,543,464 $ 7,911,554 Unproved 196,888 150,674 Total capitalized costs 7,740,352 8,062,228 Accumulated depreciation, depletion and amortization 3,723,669 3,673,569 Capitalized costs, net $ 4,016,683 $ 4,388,659
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) 2016 2015 2014 Property acquisition: Proved $ 4,066 $ 1,866 $ 2,582 Unproved 143,667 85,690 68,514 Exploration 349,463 649,764 972,164 Development 89,624 372,177 408,949 Total costs incurred $ 586,820 $ 1,109,497 $ 1,452,209
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) 2016 2015 2014 Gross revenues* $ 532,889 $ 878,554 $ 1,679,213 Production (lifting costs) 214,652 285,760 376,495 Exploration expense 5,415 14,877 28,090 Depreciation, depletion and amortization including asset impairments 663,659 1,880,190 960,539 Accretion expense 6,672 7,108 7,608 Income tax expense (benefit) (123,153 ) (469,362 ) 99,469 Results of operations from producing activities $ (234,356 ) $ (840,019 ) $ 207,012 * The years ended December 31, 2016, 2015 and 2014 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $71.2 million , a pre-tax non-cash mark-to-market loss on derivatives of $281.8 million and a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million , respectively.
Schedule of Proved Developed and Undeveloped Oil and Gas Reserves	Year ended December 31, 2016 Oil MBbl NGL MBbl Natural Gas MMcf Total MMBOE Proved reserves at beginning of period 210,691 71,713 433,904 354.7 Revisions of previous estimates (17,840 ) (6,800 ) (7,779 ) (26.0 ) Purchases 103 21 89 0.1 Extensions and discoveries 45,129 10,480 50,780 64.1 Production (13,213 ) (3,892 ) (27,204 ) (21.6 ) Sales (25,295 ) (13,476 ) (97,542 ) (55.0 ) Proved reserves at end of period 199,575 58,046 352,248 316.3 Proved developed reserves at end of period 101,202 29,767 187,117 162.1 Proved undeveloped reserves at end of period 98,373 28,279 165,131 154.2 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 0.0 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 29,695 141,209 130.0 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
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	Years ended December 31, (in thousands) 2016 2015 2014 Future gross revenues $ 9,191,808 $ 11,714,729 $ 20,971,672 Future production costs 3,126,153 4,353,974 7,532,273 Future development costs 1,632,577 1,961,661 1,784,738 Future income tax expense 762,921 1,065,887 3,440,582 Future net cash flows 3,670,157 4,333,207 8,214,079 Discount at 10% per annum 2,320,350 2,299,859 3,994,423 Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 1,349,807 $ 2,033,348 $ 4,219,656
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) 2016 2015 2014 Balance at beginning of year $ 2,033,348 $ 4,219,656 $ 4,017,841 Revisions to reserves proved in prior years: Net changes in prices, production costs and future development costs (221,639 ) (2,861,591 ) (1,147,028 ) Net changes due to revisions in quantity estimates (167,188 ) (404,708 ) (1,285,394 ) Development costs incurred, previously estimated 71,099 350,560 337,198 Accretion of discount 203,335 421,966 401,784 Changes in timing and other* (100,742 ) (903,975 ) 987,652 Total revisions (215,135 ) (3,397,748 ) (705,788 ) New field discoveries and extensions, net of future production and development costs 352,358 776,315 2,321,028 Sales of oil and gas produced, net of production costs (440,446 ) (514,380 ) (1,054,553 ) Purchases 1,733 8 4,241 Sales (235,222 ) (372,039 ) (21,092 ) Net change in income taxes (146,829 ) 1,321,536 (342,021 ) Net change in standardized measure of discounted future net cash flows (683,541 ) (2,186,308 ) 201,815 Balance at end of year $ 1,349,807 $ 2,033,348 $ 4,219,656 *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 PRE50

ORGANIZATION AND BASIS OF PRESENTATION - Sale of Alabama Gas Corporation (Details) - USD ($) $ in Thousands	Sep. 02, 2014	Dec. 31, 2014
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
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 PRE51

ORGANIZATION AND BASIS OF PRESENTATION - Workforce Reduction (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
One-time Termination Benefits
Restructuring Cost and Reserve [Line Items]
Restructuring and related cost, incurred charges	$ 5

SUMMARY OF SIGNIFICANT ACCOUN52

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Inventory valuation allowance			$ 700,000	$ 200,000
Allowance for doubtful accounts receivable			600,000	700,000
Short-term investments				0
Excess tax benefit from share-based compensation			$ 300,000	$ 1,100,000	$ 5,900,000
Curtailment gain	$ 14,500,000	$ 2,500,000
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 Lo

LONG-TERM DEBT - Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt, gross	$ 554,000	$ 776,500
Less amounts due within one year	24,000	0
Less unamortized debt discount	387	413
Unamortized Debt Issuance Expense	2,170	2,537
Long-term debt	527,443	773,550
Credit facility | Credit facility
Debt Instrument [Line Items]
Long-term debt, gross	$ 0	$ 222,500
Medium-term Notes | 7.40% Medium-term Notes, Series A, due July 24, 2017
Debt Instrument [Line Items]
Interest rate (in percentage)	7.40%	7.40%
Long-term debt, gross	$ 2,000	$ 2,000
Medium-term Notes | 7.36% Medium-term Notes, Series A, due July 24, 2017
Debt Instrument [Line Items]
Interest rate (in percentage)	7.36%	7.36%
Long-term debt, gross	$ 15,000	$ 15,000
Medium-term Notes | 7.23% Medium-term Notes, Series A, due July 28, 2017
Debt Instrument [Line Items]
Interest rate (in percentage)	7.23%	7.23%
Long-term debt, gross	$ 2,000	$ 2,000
Medium-term Notes | 7.32% Medium-term Notes, Series A, due July 28, 2022
Debt Instrument [Line Items]
Interest rate (in percentage)	7.32%	7.32%
Long-term debt, gross	$ 20,000	$ 20,000
Medium-term Notes | 7.60% Medium-term Notes, Series A, due July 26, 2027
Debt Instrument [Line Items]
Interest rate (in percentage)	7.60%	7.60%
Long-term debt, gross	$ 5,000	$ 5,000
Medium-term Notes | 7.35% Medium-term Notes, Series A, due July 28, 2027
Debt Instrument [Line Items]
Interest rate (in percentage)	7.35%	7.35%
Long-term debt, gross	$ 10,000	$ 10,000
Medium-term Notes | 7.125% Medium-term Notes, Series B, due February 15, 2028
Debt Instrument [Line Items]
Interest rate (in percentage)	7.125%	7.125%
Long-term debt, gross	$ 100,000	$ 100,000
Notes | 4.625% Notes, due September 1, 2021
Debt Instrument [Line Items]
Interest rate (in percentage)	4.625%	4.625%
Long-term debt, gross	$ 400,000	$ 400,000

LONG-TERM DEBT - Aggregate Matu

LONG-TERM DEBT - Aggregate Maturities (Details) $ in Thousands	Dec. 31, 2016USD ($)
Maturities of Long-term Debt [Abstract]
2,017	$ 24,000
2,018	0
2,019	0
2,020	0
2,021	400,000
Thereafter	$ 130,000

LONG-TERM DEBT - Additional Inf

LONG-TERM DEBT - Additional Information (Details) - USD ($)	Sep. 02, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jul. 23, 2017
Debt Instrument [Line Items]
Amount of debt redeemed		$ 554,000,000	$ 776,500,000
Cross default provision, minimum threshold amount		10,000,000
Committed financing available		$ 1,050,000,000	1,400,000,000
Loan limit percentage (less than)		10.00%
Cross default provision, minimum debt default amount (more than)		$ 75,000,000
Interest expense		36,899,000	43,108,000	$ 37,771,000
Amortization of debt issuance costs		3,300,000	3,300,000	5,700,000
Interest expense, capitalized		$ 100,000		200,000
Unused capacity, commitment fee percentage		0.30%
Debt related commitment fees		$ 3,400,000	4,100,000	$ 3,600,000
Syndicated Credit Facility | Credit Facility, September 2, 2014
Debt Instrument [Line Items]
Debt instrument, term	5 years
Debt covenant, debt to EBITDAX ratio (less than or equal to)		4
Debt covenant, current assets to current liabilities ratio (greater than or equal to)		1
Debt covenant, minimum net present value of proved reserves to consolidated debt, ratio (greater than or equal to)		1.50
Medium-term Notes | 7.40% Medium-term Notes, Series A, due July 24, 2017
Debt Instrument [Line Items]
Amount of debt redeemed		$ 2,000,000	$ 2,000,000
Percentage of debt redeemed		7.40%	7.40%
Medium-term Notes | 7.60% Medium-term Notes, Series A, due July 26, 2027
Debt Instrument [Line Items]
Amount of debt redeemed		$ 5,000,000	$ 5,000,000
Percentage of debt redeemed		7.60%	7.60%
Credit facility
Debt Instrument [Line Items]
Committed financing available		$ 1,050,000,000
Scenario, Forecast | Medium-term Notes | 7.40% Medium-term Notes, Series A, due July 24, 2017
Debt Instrument [Line Items]
Amount of debt redeemed					$ 2,000,000
Percentage of debt redeemed					7.40%
Scenario, Forecast | Medium-term Notes | 7.60% Medium-term Notes, Series A, due July 26, 2027
Debt Instrument [Line Items]
Amount of debt redeemed					$ 5,000,000
Percentage of debt redeemed					7.60%

LONG-TERM DEBT - Lines of Credi

LONG-TERM DEBT - Lines of Credit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Abstract]
Credit facility outstanding	$ 0	$ 222,500
Available for borrowings	1,050,000	1,177,500
Total borrowing commitments	1,050,000	1,400,000
Maximum amount outstanding at any month-end	214,500	685,000
Average daily amount outstanding	$ 33,642	$ 358,929
Average daily amount outstanding (in percentage)	1.72%	1.60%
Amount outstanding at year-end (in percentage)	0.00%	1.64%

INCOME TAXES - Components of In

INCOME TAXES - Components of Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Taxes estimated to be payable currently:
Federal	$ (23,277)	$ 3,972	$ 161,576
State	832	758	72,379
Total current	(22,445)	4,730	233,955
Taxes deferred:
Federal	(62,205)	(513,187)	144,645
State	5,012	(26,548)	(34,447)
Total deferred	(57,193)	(539,735)	110,198
Total income tax expense (benefit)	$ (79,638)	$ (535,005)	$ 344,153

INCOME TAXES - Components of 58

INCOME TAXES - Components of Income Taxes, Continuing and Discontinued Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income tax expense (benefit) from continuing operations	$ (79,638)	$ (535,005)	$ 40,728
Income tax expense from discontinued operations	0	0	17,928
Income tax expense from gain on disposal of discontinued operations	0	0	285,497
Total income tax expense (benefit)	$ (79,638)	$ (535,005)	$ 344,153

INCOME TAXES - Deferred Tax Ass

INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Full valuation allowance	$ 5,700
Deferred tax assets:
Total deferred tax assets, Noncurrent	122,534	$ 80,842
Valuation allowance, Noncurrent	(5,735)	(3,235)
Total deferred tax assets, net, Noncurrent	116,799	77,607
Deferred tax liabilities:
Total deferred tax liabilities, noncurrent	612,687	629,976
Deferred tax liabilities, net, noncurrent	(495,888)	(552,369)
Oil and Gas Operations
Income Tax Contingency [Line Items]
State net operating loss and charitable contribution about to expire	8,800
State operating loss carryforwards and other tax carryforwards portion about to expire	281,000
Deferred tax assets, Noncurrent
Income Tax Contingency [Line Items]
Minimum tax credit	64,203	44,862
Reclassification between income tax receivable and deferred tax assets	25,500
Additional alternative minimum tax	19,100
Deferred tax assets:
Minimum tax credit	64,203	44,862
Allowance for doubtful accounts	222	253
Insurance and other accruals	3,151	2,807
Compensation accruals	13,895	11,650
Deferred compensation and other costs	5,401	8,693
Derivative instruments	22,402	0
State net operating losses and other carryforwards	12,947	12,577
Other	313	0
Deferred tax liabilities, Noncurrent
Deferred tax liabilities:
Depreciation and basis differences	603,324	620,629
Derivative instruments	0	2,838
Other comprehensive income	854	141
Other	8,509	6,368
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)
Domestic Tax Authority
Income Tax Contingency [Line Items]
State net operating loss carrybacks, subject to expiration	$ 128,000

INCOME TAXES - Effective Income

INCOME TAXES - Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ (86,503)	$ (518,258)	$ 49,130
State income taxes, net of federal income tax benefit	925	(15,417)	(459)
Impact of state law changes	(9)	(3,075)	(121)
Impact of state deferred tax revaluation on San Juan properties	153	1,241	8,382
Change in deferred tax valuation allowance	2,500	1,305	552
Other, net	3,602	1,681	8
Total income tax expense (benefit)	$ (79,638)	$ (535,005)	$ 40,728
Effective income tax rate (in percentage)	32.22%	36.13%	29.01%

INCOME TAXES - Unrecognized Tax

INCOME TAXES - Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	Feb. 08, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance		$ 11,189	$ 17,530	$ 15,986
Additions based on tax positions related to the current year		2,936	2,378	3,873
Additions for tax positions of prior years		1,484		19
Reductions based on tax positions related to the current year			(6,589)
Reductions for tax positions of prior years		(99)	(345)	(954)
Lapse of statute of limitations		(1,300)	(1,785)	(1,394)
Unrecognized Tax Benefits, Ending Balance		14,210	11,189	17,530
Unrecognized tax benefits that would impact effective tax rate		3,500
Accrued interest (net of tax benefit) and penalties payments		300	200
Income tax interest expense (income) net of tax benefit and penalties		$ 101	$ 2	$ 27
Subsequent Event
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Reductions based on tax positions related to the current year	$ (900)
Minimum | Subsequent Event
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Reductions based on tax positions related to the current year	(1,000)
Maximum | Subsequent Event
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Reductions based on tax positions related to the current year	$ (4,000)

EMPLOYEE BENEFIT PLANS - Benefi

EMPLOYEE BENEFIT PLANS - Benefit Obligations (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Special termination benefits, annuities		$ (1,100)
Amounts recognized in balance sheet
Noncurrent assets		3,619	$ 3,881
Amounts recognized to accumulated other comprehensive income:
Total accumulated other comprehensive income (loss)		(1,405)	(263)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation		1,094	15,729
Benefit obligation:
Balance at beginning of period	$ 15,729	15,729	107,669
Service cost		0	0	$ 6,808
Interest cost		0	816	4,498
Actuarial (gain) loss		(26)	(683)
Plan amendments		0	0
Curtailment gain		0	0
Benefits paid		(14,609)	(92,073)
Balance at end of period		1,094	15,729	107,669
Plan assets:
Fair value of plan assets at beginning of period	27	27	67,542
Actual return (loss) on plan assets		(27)	(289)
Employer contributions		14,609	24,847
Benefits paid		(14,609)	(92,073)
Fair value of plan assets at end of period		0	27	67,542
Funded status of plans		(1,094)	(15,702)
Amounts recognized in balance sheet
Noncurrent assets		0	0
Current liabilities		(121)	(15,702)
Noncurrent liabilities		(973)	0
Net asset (liability) recognized		(1,094)	(15,702)
Amounts recognized to accumulated other comprehensive income:
Prior service credit, net of taxes		0	0
Net actuarial loss, net of taxes		0	2,179
Total accumulated other comprehensive income (loss)		0	2,179
Postretirement Benefits
Benefit obligation:
Balance at beginning of period	6,488	6,488	11,127
Service cost		94	392	253
Interest cost		223	466	661
Actuarial (gain) loss		917	(1,185)
Plan amendments		(422)	(4,071)
Curtailment gain	(800)	(477)	0
Benefits paid		(1,376)	(241)
Balance at end of period		5,447	6,488	11,127
Plan assets:
Fair value of plan assets at beginning of period	$ 10,369	10,369	10,693
Actual return (loss) on plan assets		73	(83)
Employer contributions		0	0
Benefits paid		(1,376)	(241)
Fair value of plan assets at end of period		9,066	10,369	10,693
Funded status of plans		3,619	3,881
Amounts recognized in balance sheet
Noncurrent assets		3,619	3,881
Current liabilities		0	0
Noncurrent liabilities		0	0
Net asset (liability) recognized		3,619	3,881
Amounts recognized to accumulated other comprehensive income:
Prior service credit, net of taxes		(2,111)	(2,646)
Net actuarial loss, net of taxes		643	205
Total accumulated other comprehensive income (loss)		(1,468)	(2,441)
Energen Employee Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized		$ 3,300	$ 5,700	$ 3,700

EMPLOYEE BENEFIT PLANS - Other

EMPLOYEE BENEFIT PLANS - Other Investment Assets (Details) - Nonqualified Supplemental Retirement Plans $ in Thousands	Dec. 31, 2015USD ($)
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 3,308
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,308
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,308
Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,308
Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0

EMPLOYEE BENEFIT PLANS - Net Pe

EMPLOYEE BENEFIT PLANS - Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Components of net periodic benefit cost:
Curtailment gain	$ 14,500	$ 2,500
Pension Benefits
Components of net periodic benefit cost:
Service cost			$ 0	$ 0	$ 6,808
Interest cost			0	816	4,498
Expected long-term return on assets			0	0	(4,386)
Prior service cost amortization			0	0	202
Actuarial (gain) loss amortization			0	737	4,995
Curtailment gain			0	0	2,477
Settlement charge			3,325	29,767	4,082
Curtailment expense			0	0	254
Net periodic expense			3,325	31,320	18,930
Postretirement Benefits
Components of net periodic benefit cost:
Service cost			94	392	253
Interest cost			223	466	661
Expected long-term return on assets			(316)	(457)	(1,122)
Prior service cost amortization			(465)	0	0
Actuarial (gain) loss amortization			0	0	(653)
Transition obligation amortization			0	0	44
Settlement charge			45	0	0
Curtailment expense			(816)	0	0
Net periodic expense			$ (1,235)	$ 401	$ (817)

EMPLOYEE BENEFIT PLANS - Othe65

EMPLOYEE BENEFIT PLANS - Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Prior service cost amortization				$ (176)	$ 0	$ 87
Curtailment gain	$ 14,500		$ 2,500
Pension Benefits
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net actuarial (gain) loss experienced during the year				0	394	(10,495)
Net actuarial (gain) loss recognized as expense				(3,352)	(30,478)	(25,433)
Prior service cost recognized as income (expense)				0	0	(246)
Curtailment loss				0	0	(8,749)
Total recognized in other comprehensive income (loss)				(3,352)	(30,872)	(23,933)
Settlement charges				27,300	7,600
Curtailment gain (loss)				0	0
Settlement charges expensed					3,700
Curtailment gain				0	0	2,477
Nonqualified Supplemental Retirement Plans
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Settlement charges	3,300	$ 2,500	1,800		400
Postretirement Benefits
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net actuarial (gain) loss experienced during the year				(682)	645	(7,649)
Net actuarial (gain) loss recognized as expense				(9)	0	1,908
Prior service cost recognized as income (expense)				780	0	0
Prior service credit during the year				(421)	(4,071)	0
Prior service cost amortization				465	0	0
Transition obligation recognized as expense				0	0	(48)
Total recognized in other comprehensive income (loss)				1,497	(4,716)	9,509
Curtailment gain (loss)	$ 800			477	0
Amortization of prior service credit				(454)
Amortization of net actuarial loss				9
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
Alagasco
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Curtailment gain (loss)			$ (300)

EMPLOYEE BENEFIT PLANS - Assump

EMPLOYEE BENEFIT PLANS - Assumptions (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year	0.00%	7.75%
Rate to which the cost trend rate is assumed to decline	0.00%	5.00%
Year that rate reaches ultimate rate		2,026
Pension Benefits
Pension Plans
Discount rate	0.00%	0.96%	3.66%
Expected long-term return on plan assets	0.00%	0.00%	7.00%
Rate of compensation increase for pay-related plans	0.00%	0.00%	3.63%
Postretirement Benefit Plans
Discount rate	0.00%	3.90%
Postretirement Benefits
Pension Plans
Discount rate	4.37%	4.25%	4.88%
Expected long-term return on plan assets	4.96%	6.20%	7.00%
Rate of compensation increase for pay-related plans	0.00%	0.00%	3.60%
Postretirement Benefit Plans
Discount rate	4.30%	4.70%

EMPLOYEE BENEFIT PLANS - Alloca

EMPLOYEE BENEFIT PLANS - Allocation of Plan Assets (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation	0.00%
Actual plan asset allocation	0.00%	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	26.00%
Actual plan asset allocation	26.00%	56.00%
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	74.00%
Actual plan asset allocation	74.00%	44.00%
Cash and cash equivalents | Pension Benefits
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation	0.00%
Actual plan asset allocation	0.00%	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 V

EMPLOYEE BENEFIT PLANS - Fair Value of Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	$ 27	$ 67,542
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		27
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Pension Benefits | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		27
Pension Benefits | Cash and cash equivalents | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		27
Pension Benefits | Cash and cash equivalents | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9,066	10,369	$ 10,693
Postretirement Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9,066	5,835
Postretirement Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	4,534
Postretirement Benefits | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10
Postretirement Benefits | Cash and cash equivalents | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10
Postretirement Benefits | Cash and cash equivalents | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0
Postretirement Benefits | United States equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	180	4,185
Postretirement Benefits | United States equities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	180	4,185
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	2,158	1,650
Postretirement Benefits | Global equities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,158	1,650
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	6,718	4,534
Postretirement Benefits | Fixed income | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,718	0
Postretirement Benefits | Fixed income | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	$ 4,534

EMPLOYEE BENEFIT PLANS - Cash F

EMPLOYEE BENEFIT PLANS - Cash Flows (Details) - Postretirement Benefits $ in Thousands	Dec. 31, 2016USD ($)
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
2,017	$ 339
2,018	335
2,019	336
2,020	339
2,021	365
2022-2026	$ 1,567

COMMON STOCK PLANS - Stock Ince

COMMON STOCK PLANS - Stock Incentive Plan (Details) - Stock Incentive Plan	Dec. 31, 2016shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for issuance (in shares)	3,497,920
Number of shares remaining for issuance (in shares)	1,788,492

COMMON STOCK PLANS - Performanc

COMMON STOCK PLANS - Performance Share Awards (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Weighted Average Price
Share-based compensation expense	$ 19,641	$ 12,910	$ 16,262
Performance share awards
Weighted Average Price
Share-based compensation expense	6,200	6,700	6,200
Tax benefit related to stock-based compensation	2,200	$ 2,400	$ 2,300
Unrecognized compensation cost	$ 6,000
Weighted average requisite service period	1 year 8 months 5 days
Performance share awards | Stock Incentive Plan
Shares
Nonvested, Beginning of Period (in shares)	256,083	212,968	160,819
Forfeited (in shares)	(12,481)
Vested and paid (in shares)	(74,176)	(77,257)	(14,097)
Nonvested, End of Period (in shares)	336,442	256,083	212,968
Weighted Average Price
Nonvested, Beginning of Period, Weighted Average Price (in dollars per share)	$ 80.43	$ 71.53	$ 62.13
Forfeited, Weighted Average Price (in dollars per share)	72.30
Vested and paid, Weighted Average Price (in dollars per share)	63.88	61.36	70.06
Nonvested, End of Period, Weighted Average Price (in dollars per share)	$ 57.03	$ 80.43	$ 71.53
Performance share awards | 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 (in shares)			937
Weighted Average Price
Granted, Weighted Average Price (in dollars per share)			$ 131.56
Performance share awards | 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	3 years	3 years
Shares
Granted (in shares)	167,016	120,372	65,309
Weighted Average Price
Granted, Weighted Average Price (in dollars per share)	$ 25.34	$ 83.94	$ 93.49

COMMON STOCK PLANS - Restricted

COMMON STOCK PLANS - Restricted Stock (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 19,641	$ 12,910	$ 16,262
Restricted Stock and Restricted Stock Units | Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	5,300	6,000	3,200
Tax benefit related to stock-based compensation	1,900	$ 2,100	$ 1,200
Unrecognized compensation cost	$ 2,400
Remaining requisite service period (in years)	1 year 9 months 8 days
Shares
Nonvested, Beginning of Period (in shares)	184,942	99,574	62,518
Granted (in shares)	197,473	99,814	48,904
Forfeited (in shares)	(435)
Vested (in shares)	(56,337)	(14,446)	(11,848)
Nonvested, End of Period (in shares)	325,643	184,942	99,574
Weighted Average Price
Nonvested, Beginning of Period, Weighted Average Price (in dollars per share)	$ 63.09	$ 59.60	$ 51.16
Granted, Weighted Average Price (in dollars per share)	29.89	65.15	71.91
Forfeited, Weighted Average Price (in dollars per share)	40.73
Vested and paid, Weighted Average Price (in dollars per share)	54.70	53.20	65.94
Nonvested, End of Period, Weighted Average Price (in dollars per share)	$ 44.44	$ 63.09	$ 59.60

COMMON STOCK PLANS - Stock Opti

COMMON STOCK PLANS - Stock Options (Details) - Stock Incentive Plan - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Shares
Remaining reserved for issuance (in shares)	1,788,492
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 (in shares)	733,391	757,071	1,191,044
Granted (in shares)			110,307
Exercised (in shares)	(22,490)	(23,680)	(544,280)
Outstanding, End of Period (in shares)	710,901	733,391	757,071
Exercisable (in shares)	676,271	622,156	454,938
Weighted Average Exercise Price
Outstanding, Beginning of Period, Weighted Average Exercise Price (in dollars per share)	$ 55.32	$ 54.88	$ 51.06
Granted, Weighted Average Exercise Price (in dollars per share)			72.55
Exercised, Weighted Average Exercise Price (in dollars per share)	44.60	41.42	50.09
Outstanding, End of Period, Weighted Average Exercise Price (in dollars per share)	55.66	55.32	54.88
Exercisable, Weighted Average Exercise Price (in dollars per share)	$ 54.79	$ 53.80	$ 51.88

COMMON STOCK PLANS - Stock Op74

COMMON STOCK PLANS - Stock Options, Valuation Assumptions (Details) - Stock options - Stock Incentive Plan - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)		110,307
4/15/2014
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	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 (in percentage)	1.93%
Annualized volatility rate (in percentage)	40.70%
Dividend yield (in percentage)	0.20%
1/22/2014
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	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 (in percentage)	2.06%
Annualized volatility rate (in percentage)	40.70%
Dividend yield (in percentage)	0.80%

COMMON STOCK PLANS - Stock Op75

COMMON STOCK PLANS - Stock Options, Textual (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 19,641	$ 12,910	$ 16,262
Stock options | Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	100	400	2,900
Tax benefit related to stock-based compensation	44	$ 100	$ 1,100
Intrinsic value of stock options exercised during period	200
Cash received from exercise of stock options	200
Intrinsic value for outstanding options	3,300
Intrinsic value for exercisable options	3,300
Fair value of vested options	$ 1,600

COMMON STOCK PLANS - Stock Op76

COMMON STOCK PLANS - Stock Options, Range of Exercise Prices (Details)	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Weighted average remaining contractual life of exercisable stock options	4 years 9 months 18 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 (in dollars per share)	$ 29.79
Number of outstanding options, Range of Exercise Prices, Upper Range Limit (in dollars per share)	$ 80.48
Stock Incentive Plan (in shares) | shares	710,901
Weighted Average Remaining Contractual Life	4 years 10 months 29 days
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 (in dollars per share)	$ 60.56
Stock Incentive Plan (in shares) | shares	48,560
Weighted Average Remaining Contractual Life	1 year
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 (in dollars per share)	$ 29.79
Stock Incentive Plan (in shares) | shares	21,791
Weighted Average Remaining Contractual Life	2 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 (in dollars per share)	$ 46.69
Stock Incentive Plan (in shares) | shares	26,481
Weighted Average Remaining Contractual Life	3 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 (in dollars per share)	$ 54.99
Stock Incentive Plan (in shares) | shares	104,841
Weighted Average Remaining Contractual Life	4 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 (in dollars per share)	$ 54.11
Stock Incentive Plan (in shares) | shares	271,164
Weighted Average Remaining Contractual Life	5 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 (in dollars per share)	$ 48.36
Stock Incentive Plan (in shares) | shares	124,071
Weighted Average Remaining Contractual Life	6 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 (in dollars per share)	$ 80.48
Stock Incentive Plan (in shares) | shares	3,686
Weighted Average Remaining Contractual Life	6 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 (in dollars per share)	$ 72.39
Stock Incentive Plan (in shares) | shares	107,868
Weighted Average Remaining Contractual Life	7 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 (in dollars per share)	$ 79.63
Stock Incentive Plan (in shares) | shares	2,439
Weighted Average Remaining Contractual Life	7 years

COMMON STOCK PLANS - 2004 Stock

COMMON STOCK PLANS - 2004 Stock Appreciation Rights Plan (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Share-based compensation expense (income)	$ (19,641)	$ (12,910)	$ (16,262)
Stock Appreciation Rights
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Share-based compensation expense (income)	2,600	$ (3,200)	$ (400)
Intrinsic value of stock options exercised during period	51
Settlement of stock appreciation rights	$ 35
Stock Appreciation Rights | 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 (in shares)	264,867	275,150	377,377
Granted (in shares)			62,749
Exercised/forfeited (in shares)	(12,338)	(10,283)	(164,976)
Outstanding, End of Period (in shares)	252,529	264,867	275,150
Weighted Average Exercise Price
Outstanding, Beginning of Period, Weighted Average Exercise Price (in dollars per share)	$ 52.88	$ 52.96	$ 49.48
Granted, Weighted Average Exercise Price (in dollars per share)			72.39
Exercised/forfeited, Weighted Average Exercise Price (in dollars per share)	61.51	55.18	52.37
Outstanding, End of Period, Weighted Average Exercise Price (in dollars per share)	$ 52.46	$ 52.88	$ 52.96
1/22/2014 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	46,710
Fair market value of stock option at grant (in dollars per share)	$ 13.26
Expected life of award	3 years 6 months 22 days
Risk-free interest rate (in percentage)	1.61%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
1/24/2013 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	63,436
Fair market value of stock option at grant (in dollars per share)	$ 20.26
Expected life of award	3 years 11 days
Risk-free interest rate (in percentage)	1.48%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
1/26/2011 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	182,199
Fair market value of stock option at grant (in dollars per share)	$ 14.34
Expected life of award	2 years 10 days
Risk-free interest rate (in percentage)	1.21%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
1/27/2010 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	171,749
Fair market value of stock option at grant (in dollars per share)	$ 16.83
Expected life of award	1 year 6 months 15 days
Risk-free interest rate (in percentage)	1.05%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
1/28/2009 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	305,257
Fair market value of stock option at grant (in dollars per share)	$ 28.46
Expected life of award	1 year 15 days
Risk-free interest rate (in percentage)	0.86%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
2/4/2008 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	67,093
Fair market value of stock option at grant (in dollars per share)	$ 4.38
Expected life of award	6 months 18 days
Risk-free interest rate (in percentage)	0.64%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
2/1/2007 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	85,906
Fair market value of stock option at grant (in dollars per share)	$ 11.43
Expected life of award	16 days
Risk-free interest rate (in percentage)	0.42%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
Workforce Reduction | 1/22/2014 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	15,517
Fair market value of stock option at grant (in dollars per share)	$ 8.82
Expected life of award	2 years 1 month 17 days
Risk-free interest rate (in percentage)	1.24%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
Workforce Reduction | 1/24/2013 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	20,218
Fair market value of stock option at grant (in dollars per share)	$ 17.75
Expected life of award	2 years 1 month 17 days
Risk-free interest rate (in percentage)	1.24%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
San Juan Basin properties | 1/22/2014 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	522
Fair market value of stock option at grant (in dollars per share)	$ 7.03
Expected life of award	1 year 7 months 17 days
Risk-free interest rate (in percentage)	1.08%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
San Juan Basin properties | 1/24/2013 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	768
Fair market value of stock option at grant (in dollars per share)	$ 16.19
Expected life of award	1 year 7 months 17 days
Risk-free interest rate (in percentage)	1.08%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
Black Warrior Basin | 1/24/2013 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	3,578
Fair market value of stock option at grant (in dollars per share)	$ 13.93
Expected life of award	1 year
Risk-free interest rate (in percentage)	0.85%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%
Black Warrior Basin | 1/26/2011 | Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted (in shares)	7,785
Fair market value of stock option at grant (in dollars per share)	$ 10.36
Expected life of award	1 year
Risk-free interest rate (in percentage)	0.85%
Annualized volatility rate (in percentage)	39.10%
Dividend yield (in percentage)	0.00%

COMMON STOCK PLANS - Other Plan

COMMON STOCK PLANS - Other Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based compensation expense	$ 19,641	$ 12,910	$ 16,262
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 (in shares)	243,746	213,870	173,292
Granted (in shares)			76,084
Paid (in shares)	(67,392)	(78,430)	(4,431)
Forfeited (in shares)	(32,111)	(22,158)	(31,075)
Outstanding, End of Period (in shares)	144,243	243,746	213,870
Share-based compensation expense	$ 5,400	$ 3,000	$ 4,500
Stock Equivalent Units | Petrotech Incentive Plan | Three years vesting period
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, vesting period		3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted (in shares)		128,519
Stock Equivalent Units | Petrotech Incentive Plan | Two years vesting period
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, vesting period		2 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted (in shares)		297
Stock Equivalent Units | Petrotech Incentive Plan | 16-month vesting period
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, vesting period		16 months
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted (in shares)		1,648
Management | 1997 Deferred Compensation Plan
Deferred Compensation Arrangements [Abstract]
Deferred compensation, reserved for issuance (in shares)	573,024
Director | Stock options | 1992 Energen Corporation Directors Stock Plan
Deferred Compensation Arrangements [Abstract]
Granted (in shares)	25,470	11,550	10,360
Number of shares remaining for issuance (in shares)	90,904

COMMON STOCK PLANS - Stock Repu

COMMON STOCK PLANS - Stock Repurchase Program (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	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]
Purchase and retirement of shares (in shares)	0	0	226,839
Purchase and retirement of shares, value			$ 2,000
Common Stock
Equity, Class of Treasury Stock [Line Items]
Stock repurchase program, authorized amount (up to)				$ 3,600,000
Stock repurchase program, remaining authorized repurchase amount	$ 3,373,161
Shares acquired in connection with stock compensation plans (in shares)	88,320	73,126	32,768

DERIVATIVE COMMODITY INSTRUME80

DERIVATIVE COMMODITY INSTRUMENTS - Gain (Loss) on Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Gain (loss) on derivative instruments, net	$ (88,477)	$ 115,293	$ 335,019
Commodity contracts
Derivative [Line Items]
Open non-cash mark-to-market gains (losses) on derivative instruments	(71,190)	(281,752)	315,445
Closed gains (losses) on derivative instruments	(17,287)	397,045	19,574
Gain (loss) on derivative instruments, net	$ (88,477)	$ 115,293	$ 335,019

DERIVATIVE COMMODITY INSTRUME81

DERIVATIVE COMMODITY INSTRUMENTS - Offsetting of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Liabilities
Total derivatives	$ (68,423)	$ 56,504
Current Assets
Assets
Gross Amounts Recognized at Fair Value	1,756	72,563
Gross Amounts Offset in the Balance Sheets		(15,600)
Gross Amounts Offset in the Balance Sheets	(1,706)
Net Amount Presented in the Balance Sheets	50	56,963
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Fair Value Presented in the Balance Sheets	50	56,963
Current Liabilities
Liabilities
Gross Amounts Recognized at Fair Value	67,173	16,059
Gross Amounts Offset in the Balance Sheets		(15,600)
Gross Amounts Offset in the Balance Sheets	(1,706)
Net Amount Presented in the Balance Sheets	65,467	459
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Fair Value Presented in the Balance Sheets	65,467	$ 459
Noncurrent Liabilities
Liabilities
Gross Amounts Recognized at Fair Value	3,006
Gross Amounts Offset in the Balance Sheets	0
Net Amount Presented in the Balance Sheets	3,006
Financial Instruments	0
Cash Collateral Received	0
Net Fair Value Presented in the Balance Sheets	$ 3,006

DERIVATIVE COMMODITY INSTRUME82

DERIVATIVE COMMODITY INSTRUMENTS - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)counterparty	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Derivative [Line Items]
Counterparties with whom company holds net loss positions | counterparty	1
Loss on fair value of derivatives	$ 88,477	$ (115,293)	$ (335,019)
Commodity contracts
Derivative [Line Items]
Loss on fair value of derivatives	88,477	$ (115,293)	$ (335,019)
BP Corporation North America, Inc. | Commodity contracts
Derivative [Line Items]
Loss on fair value of derivatives	$ 100

DERIVATIVE COMMODITY INSTRUME83

DERIVATIVE COMMODITY INSTRUMENTS - Cash Flow Hedging Relationship in Financial Statements (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2014USD ($)
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	$ 37
Gain (loss) recognized in other comprehensive income on derivatives	23
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

DERIVATIVE COMMODITY INSTRUME84

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Gain (Loss) on Derivative Instruments, Net
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in income on derivatives	$ (88,477)	$ 115,293	$ 313,408

DERIVATIVE COMMODITY INSTRUME85

DERIVATIVE COMMODITY INSTRUMENTS - Reclassification (Details)	12 Months Ended
	Dec. 31, 2016MBblsBcfMMgals$ / Mcf$ / bbl$ / gal
NYMEX Swaps | Oil | Production Period, Year One
Derivatives, Fair Value [Line Items]
Total Hedged Volumes (in MBbl and Bcf) | MBbls	6,060
Average Contract Price (in uadPerbbl, usdPergal and usdPerMcf)	49.77
NYMEX Swaps | Natural Gas | Production Period, Year One
Derivatives, Fair Value [Line Items]
Total Hedged Volumes (in MBbl and Bcf) | MBbls	0.9
Average Contract Price (in uadPerbbl, usdPergal and usdPerMcf)	3.29
NYMEX Three-Way Collars | Oil | Production Period, Year One
Derivatives, Fair Value [Line Items]
Total Hedged Volumes (in MBbl and Bcf) | MBbls	4,800
NYMEX Three-Way Collars | Oil | Production Period, Year Two
Derivatives, Fair Value [Line Items]
Total Hedged Volumes (in MBbl and Bcf) | MBbls	3,240
WTI/WTI Basis Swaps | Oil | Production Period, Year One
Derivatives, Fair Value [Line Items]
Total Hedged Volumes (in MBbl and Bcf) | MBbls	7,890
Average Contract Price (in uadPerbbl, usdPergal and usdPerMcf)	(0.58)
Liquids Swaps | Natural Gas Liquids | Production Period, Year One
Derivatives, Fair Value [Line Items]
Total Hedged Volumes (in MBbl and Bcf) | MMgals	45.4
Average Contract Price (in uadPerbbl, usdPergal and usdPerMcf) | $ / gal	0.52
Liquids Swaps | Natural Gas Liquids | Production Period, Year Two
Derivatives, Fair Value [Line Items]
Total Hedged Volumes (in MBbl and Bcf) | MMgals	30.2
Average Contract Price (in uadPerbbl, usdPergal and usdPerMcf) | $ / gal	0.60
Basin Specific Swaps - Permian | Natural Gas | Production Period, Year One
Derivatives, Fair Value [Line Items]
Total Hedged Volumes (in MBbl and Bcf) | Bcf	14.7
Underlying, Derivative (in usdPerMcf) | $ / Mcf	2.85
Permian Swaps | Natural Gas Basis Differential | Production Period, Year One
Derivatives, Fair Value [Line Items]
Total Hedged Volumes (in MBbl and Bcf) | Bcf	0.9
Underlying, Derivative (in usdPerMcf) | $ / Mcf	(0.29)
Short | Ceiling sold price (call) | Oil | Production Period, Year One
Derivatives, Fair Value [Line Items]
Derivative, Cap Price (in usdPerbbl)	62.18
Short | Ceiling sold price (call) | Oil | Production Period, Year Two
Derivatives, Fair Value [Line Items]
Derivative, Cap Price (in usdPerbbl)	65.03
Short | Floor purchased/sold price (put) | Oil | Production Period, Year One
Derivatives, Fair Value [Line Items]
Derivative, Floor Price (in usdPerbbl)	35
Short | Floor purchased/sold price (put) | Oil | Production Period, Year Two
Derivatives, Fair Value [Line Items]
Derivative, Floor Price (in usdPerbbl)	40
Long | Floor purchased/sold price (put) | Oil | Production Period, Year One
Derivatives, Fair Value [Line Items]
Derivative, Floor Price (in usdPerbbl)	45
Long | Floor purchased/sold price (put) | Oil | Production Period, Year Two
Derivatives, Fair Value [Line Items]
Derivative, Floor Price (in usdPerbbl)	50

FAIR VALUE MEASUREMENTS - Deriv

FAIR VALUE MEASUREMENTS - Derivative Instruments, Fair Value (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Assets
Derivative instruments	$ 50	$ 56,963
Liabilities
Derivative instruments	(65,467)	(459)
Derivative Liability, Noncurrent	(3,006)
Net derivative asset (liability)	(68,423)	56,504
Level 2
Assets
Derivative instruments	50	69,864
Liabilities
Derivative instruments	(57,927)	2,699
Derivative Liability, Noncurrent	(1,694)
Net derivative asset (liability)	(59,571)	72,563
Level 3
Assets
Derivative instruments	0	(12,901)
Liabilities
Derivative instruments	(7,540)	(3,158)
Derivative Liability, Noncurrent	(1,312)
Net derivative asset (liability)	$ (8,852)	$ (16,059)

FAIR VALUE MEASUREMENTS - Addit

FAIR VALUE MEASUREMENTS - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)customer	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Concentration Risk [Line Items]
Impact of ten percent change in commodity prices	$ 4,400
Sale of short-term investments	$ 0	$ 919,000	$ 473,000
Number of large customers | customer	2
Plains Marketing | Accounts receivable
Concentration Risk [Line Items]
Concentration of credit risk (less than 9 percent)	50.00%
Plains Marketing | Total operating revenues
Concentration Risk [Line Items]
Concentration of credit risk (less than 9 percent)	52.00%
Shell Trading | Accounts receivable
Concentration Risk [Line Items]
Concentration of credit risk (less than 9 percent)	20.00%
Shell Trading | Total operating revenues
Concentration Risk [Line Items]
Concentration of credit risk (less than 9 percent)	12.00%
Remaining Customer Concentration Risk | Accounts receivable
Concentration Risk [Line Items]
Concentration of credit risk (less than 9 percent)	7.00%
Other Oil and Natural Gas Purchasers | Total operating revenues
Concentration Risk [Line Items]
Concentration of credit risk (less than 9 percent)	10.00%
Estimate of Fair Value Measurement
Concentration Risk [Line Items]
Fair value of long-term debt	$ 559,900	690,100
Reported Value Measurement
Concentration Risk [Line Items]
Fair value of long-term debt	$ 554,000	776,500
Swap | Credit facility
Concentration Risk [Line Items]
Interest rate cash flow hedge liability at fair value		$ 200

FAIR VALUE MEASUREMENTS - Der88

FAIR VALUE MEASUREMENTS - Derivative Instruments Change in Fair Value of Level 3 (Details) - Derivative Commodity Instruments - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period		$ (16,059)	$ 24,436	$ 18,289
Realized gains		(14,120)	13,145	22,208
Unrealized gains (losses) relating to instruments held at the reporting date	[1]	5,745	(40,495)	2,981
Settlements during period		14,120	(13,145)	(19,042)
Transfer out of Level 3		1,462	0	0
Balance at end of period		(8,852)	(16,059)	24,436
Mark-to-market gains (losses)		$ (8,900)	$ (16,100)	$ 20,200
[1]	Includes $8.9 million in mark-to-market losses, $16.1 million in mark-to-market losses and $20.2 million in mark-to-market gains for the years ended December 31, 2016, 2015 and 2014, respectively.

FAIR VALUE MEASUREMENTS - Level

FAIR VALUE MEASUREMENTS - Level 3 Fair Value Measurements of Derivative Commodity Instruments (Details) - Discounted Cash Flow Valuation Technique - Level 3 $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / bblgal
Oil | WTI/WTI Basis Swaps | 2017
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value	$ (1,984)
Natural Gas Liquids | 2017
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value	$ (5,556)
Fair value inputs, derivative, nonmonetary notional amount (gal) | gal	0.65
Natural Gas Liquids | 2018
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value	$ (1,312)
Fair value inputs, derivative, nonmonetary notional amount (gal) | gal	0.64
Minimum | Oil | WTI/WTI Basis Swaps | 2017
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount, price per unit (usdperbbl) | $ / bbl	0.21
Maximum | Oil | WTI/WTI Basis Swaps | 2017
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount, price per unit (usdperbbl) | $ / bbl	0.36

EXPLORATORY COSTS - Capitalized

EXPLORATORY COSTS - Capitalized Exploratory Well Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)well	Dec. 31, 2015USD ($)well	Dec. 31, 2014USD ($)
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized exploratory well costs at beginning of period	$ 103,588	$ 119,439	$ 57,600
Additions pending determination of proved reserves	344,045	634,908	946,751
Reclassifications due to determination of proved reserves	(282,637)	(650,759)	(882,254)
Exploratory well costs charged to expense	0	0	(2,658)
Capitalized exploratory well costs at end of period	164,996	103,588	$ 119,439
Capitalized Exploratory Well Costs [Abstract]
Exploratory wells in progress (drilling rig not released)	14,531	1,760
Capitalized exploratory well costs for a period of one year or less	143,602	101,828
Capitalized exploratory well costs for a period greater than one year	6,863	0
Total capitalized exploratory well costs	$ 164,996	$ 103,588
Number of wells capitalized for a period greater than one year | well		0
Wells in process of drilling | well	59

RECONCILIATION OF EARNINGS PE91

RECONCILIATION OF EARNINGS PER SHARE - Reconciliation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income (Loss)	$ (54,470)	$ 53,314	$ 36,759	$ (203,116)	$ (590,806)	$ (227,904)	$ (111,601)	$ (15,420)	$ (167,513)	$ (945,731)	$ 568,032
Basic Shares Outstanding (in shares)									94,475,797	76,078,371	72,896,579
Basic earnings per average common share (in dollars per share)	$ (0.56)	$ 0.55	$ 0.38	$ (2.34)	$ (7.50)	$ (2.89)	$ (1.52)	$ (0.21)	$ (1.77)	$ (12.43)	$ 7.79
Effect of dilutive securities
Net Income (Loss), Diluted EPS	$ (54,470)	$ 53,314	$ 36,759	$ (203,116)	$ (590,806)	$ (227,904)	$ (111,601)	$ (15,420)	$ (167,513)	$ (945,731)	$ 568,032
Diluted Shares Outstanding (in shares)									94,475,797	76,078,371	73,274,631
Diluted earnings per average common share (in dollars per share)	$ (0.56)	$ 0.55	$ 0.38	$ (2.34)	$ (7.50)	$ (2.89)	$ (1.52)	$ (0.21)	$ (1.77)	$ (12.43)	$ 7.75
Stock options
Effect of dilutive securities
Effect of dilutive securities (in shares)									0	0	216,000
Non-vested restricted stock
Effect of dilutive securities
Effect of dilutive securities (in shares)									0	0	58,000
Performance share awards
Effect of dilutive securities
Effect of dilutive securities (in shares)									0	0	104,000

RECONCILIATION OF EARNINGS PE92

RECONCILIATION OF EARNINGS PER SHARE - Antidilutive Securities (Details) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of diluted EPS (in shares)	330,690	355,915
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of diluted EPS (in shares)	539,000	114,000	114,000
Non-vested restricted stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of diluted EPS (in shares)	0	0	3,000
Performance share awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of diluted EPS (in shares)	0	0	2,000

EQUITY OFFERING - Narrative (De

EQUITY OFFERING - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Proceeds from issuance of common stock net of offering expense	$ 381,100
Proceeds from issuance of common stock net of offering expenses		$ 398,600	$ 381,261	$ 399,600	$ 23,053
Common Stock
Class of Stock [Line Items]
Shares issued for stock offering (in shares)	18,170,000		18,170,000	5,700,000
Shares issued (in shares)		5,700,000

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Additional Information (Details) gal in Thousands, a in Thousands	Nov. 04, 2015USD ($)a	Dec. 31, 2008gal	Dec. 31, 2016USD ($)MMBoe	Apr. 15, 2016USD ($)
Unfavorable Regulatory Action
Site Contingency [Line Items]
Order for payment of additional royalties				$ 189,000
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			4.2
Pending Litigation | Energen vs. Endeavor Energy Resources
Site Contingency [Line Items]
Number of acres with cloud on the title | a	10
Pending Litigation | Endeavor Energy Resources
Site Contingency [Line Items]
Amount of counterclaim	$ 300,000,000
Minimum | Unfavorable Regulatory Action
Site Contingency [Line Items]
Order for payment of additional royalties			$ 129,700
Maximum | Unfavorable Regulatory Action
Site Contingency [Line Items]
Order for payment of additional royalties			$ 24,000,000

COMMITMENTS AND CONTINGENCIES95

COMMITMENTS AND CONTINGENCIES - Lease Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Total lease payments	$ 22,600	$ 23,700	$ 24,100
Operating Leases, Future Minimum Payments Due [Abstract]
2,017	3,822
2,018	2,614
2,019	2,448
2,020	0
2,021	0
2022 and thereafter	$ 0

ASSET RETIREMENT OBLIGATIONS -

ASSET RETIREMENT OBLIGATIONS - Components of Changes in ARO (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning	$ 89,990	$ 94,060	$ 108,533
Liabilities incurred	230	981	2,266
Liabilities settled	(758)	(686)	(1,543)
Accretion expense	6,672	7,108	7,859
Revision in estimated cash flows	(12,875)		(692)
Reclassification associated with held for sale properties	(1,715)	(11,473)	(23,747)
Balance of ARO, end	$ 81,544	$ 89,990	94,060
Accretion expense of discontinued operations			$ 251

ASSET IMPAIRMENT - Summary of I

ASSET IMPAIRMENT - Summary of Impairments (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment			$ 220,652	$ 1,292,308	$ 416,801
Assets impairments from discontinued operations			0	0	1,936
Total asset impairments			220,652	1,292,308	418,737
Central Basin Platform
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment			187,043	484,848	0
Delaware Basin
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment		$ 90,600	21,288	607,303	90,594
Midland Basin
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment		$ 25,800	0	0	25,776
San Juan Basin properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment	$ 7,500		7,519	133,055	230,315
Permian Basin Unproved Leasehold Properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment			4,762	29,168	64,361
San Juan Basin unproved leasehold properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment			40	37,934	5,755
North Louisiana/East Texas oil and natural gas properties
Impaired Long-Lived Assets Held and Used [Line Items]
Assets impairments from discontinued operations			$ 0	$ 0	$ 1,936

ASSET IMPAIRMENT - Additional I

ASSET IMPAIRMENT - Additional Information (Details) $ in Thousands	3 Months Ended					6 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)MMBoe	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)MMBoe	Dec. 31, 2016USD ($)MMBoe	Dec. 31, 2015USD ($)MMBoe	Dec. 31, 2014USD ($)MMBoe	Mar. 31, 2014USD ($)
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment							$ 220,652	$ 1,292,308	$ 416,801
Increase (decrease) in commodity price assumptions (in percentage)							3.00%
Price curve, term							5 years
Proved developed reserves at end of period (in mmboe) | MMBoe		184				264.5	162.1	184	264.5
Assets impairments from discontinued operations							$ 0	$ 0	$ 1,936
Permian Basin unproved leasehold properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment	$ 208,300
Central Basin Platform
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment							187,043	484,848	0
Midland Basin
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment						$ 25,800	0	0	25,776
Delaware Basin
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment						$ 90,600	21,288	607,303	90,594
Permian Basin Unproved Leasehold Properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment							4,762	29,168	64,361
Permian Basin Unproved Leasehold Properties, Expiration
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment									55,100
San Juan Basin properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment	$ 7,500						7,519	$ 133,055	$ 230,315
Proved developed reserves at end of period (in mmboe) | MMBoe		16,930				69,038		16,930	69,038
San Juan Proved and Unproved Properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment		$ 133,100
San Juan Basin unproved leasehold properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment							40	$ 37,934	$ 5,755
North Louisiana/East Texas
Impaired Long-Lived Assets Held and Used [Line Items]
Sales price										$ 30,300
Assets impairments from discontinued operations							$ 0	0	$ 1,936
Oil Reserves
Impaired Long-Lived Assets Held and Used [Line Items]
Increase (decrease) in commodity price assumptions (in percentage)	(5.00%)		(12.00%)	(19.00%)
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
Natural Gas
Impaired Long-Lived Assets Held and Used [Line Items]
Increase (decrease) in commodity price assumptions (in percentage)	(4.00%)		(6.00%)	(12.00%)

ACQUISITION AND DISPOSITION O99

ACQUISITION AND DISPOSITION OF PROPERTIES - Additional Information (Details) a in Thousands, $ in Millions	Mar. 31, 2015USD ($)	Oct. 31, 2014USD ($)a	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)MBoe
Business Acquisition [Line Items]
Payments to acquire unproved leasehold properties			$ 143.7	$ 85.7	$ 68.5
San Juan Basin properties
Business Acquisition [Line Items]
Cash received from sale of oil properties	$ 384
Purchase price adjustments	11
Transaction costs	2.8
Pre-tax gain on disposal	27
Sale of assets	$ 395
Proved reserves (in mboe) | MBoe					69,038
Payments to acquire unproved leasehold properties		$ 22.8
Net acres | a		15
Lea County
Business Acquisition [Line Items]
Payments to acquire unproved leasehold properties			77
Disposal Group, Not Discontinued Operations | Permian and San Juan Basin
Business Acquisition [Line Items]
Disposal group, consideration			552
Disposal Group, Held-for-sale, Not Discontinued Operations | Permian and San Juan Basin
Business Acquisition [Line Items]
Cash received from sale of oil properties			532.9
Purchase price adjustments			19
Transaction costs			5
Pre-tax gain on disposal			$ 246.3

HELD FOR SALE PROPERTIES AND100

HELD FOR SALE PROPERTIES AND DISCONTINUED OPERATIONS - Balance Sheet (Details) - San Juan Basin properties $ in Thousands	Dec. 31, 2015USD ($)
Assets of Disposal Group, Including Discontinued Operation [Abstract]
Inventories	$ 3,651
Oil and natural gas properties	305,386
Less accumulated depreciation, depletion and amortization	(219,059)
Other property and equipment, net	3,761
Total assets held-for-sale	93,739
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]
Other long-term liabilities	(12,789)
Total liabilities held-for-sale	(12,789)
Total held-for-sale properties	$ 80,950

HELD FOR SALE PROPERTIES AND101

HELD FOR SALE PROPERTIES AND DISCONTINUED OPERATIONS - Additional Information (Details) - USD ($) $ in Thousands	Sep. 02, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal of discontinued operations, net				$ 724,594
Assets impairments from discontinued operations		$ 0	$ 0	1,936
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
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	$ 0	$ 1,936

HELD FOR SALE PROPERTIES AND102

HELD FOR SALE PROPERTIES AND DISCONTINUED OPERATIONS - Income Statement (Details) - USD ($) $ / shares in Units, $ in Thousands	Sep. 02, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Natural gas distribution revenues				$ 397,648
Oil and natural gas revenues				5,199
Total revenues				402,847
Pretax income from discontinued operations				47,220
Income tax expense		$ 0	$ 0	17,928
Income From Discontinued Operations		0	0	29,292
Gain on disposal of discontinued operations, net				724,594
Income tax expense		0	0	285,497
Gain on Disposal of Discontinued Operations, net		0	0	439,097
Income From Discontinued Operations		$ 0	$ 0	$ 468,389
Diluted earnings per average common share
Income from discontinued operations (in dollars per share)				$ 0.40
Gain on disposal of discontinued operations, net (in dollars per share)				5.99
Total Income From Discontinued Operations (in dollars per share)		$ 0	$ 0	6.39
Basic earnings per average common share
Income from discontinued operations (in dollars per share)				0.40
Gain on disposal of discontinued operations, net (in dollars per share)				6.02
Total Income From Discontinued Operations (in dollars per share)		$ 0	$ 0	$ 6.42
Alabama Gas Corporation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Alagasco net income				$ 40,646
Depreciation, depletion and amortization				(408)
General and administrative				3,337
Interest expense				(17,306)
Other income				(347)
Income tax expense				5,567
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Gain on disposal of discontinued operations, net	$ 726,500
Income From Discontinued Operations				31,489
Parent Company
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Income From Discontinued Operations				$ (2,197)

SUPPLEMENTAL CASH FLOW INFOR103

SUPPLEMENTAL CASH FLOW INFORMATION - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Elements [Abstract]
Interest paid, net of amount capitalized	$ 35,919	$ 40,747	$ 32,172
Income taxes paid	562	8,114	219,505
Noncash investing activities:
Accrued development, exploration costs and other capital	79,988	79,206	207,461
Capitalized asset retirement obligations costs	230	981	2,958
Receivable from sale of Alabama Gas Corporation	0	0	8,247
Noncash financing activities:
Issuance of common stock for employee benefit plans	6,675	5,758	2,448
Treasury stock acquired in connection with tax withholdings	$ 2,610	$ 4,722	$ 2,547

ACCUMULATED OTHER COMPREHENS104

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) - Rollforward of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Other comprehensive income before reclassifications	$ (459)
Amounts reclassified from accumulated other comprehensive income	1,601	$ 19,828	$ 2,514
Change in accumulated other comprehensive income (loss)	1,142
AOCI Including Portion Attributable to Noncontrolling Interest
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance as of December 31, 2015	263
Balance as of December 31, 2016	$ 1,405	$ 263

ACCUMULATED OTHER COMPREHENS105

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) - Reclassifications of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Gains (losses) on cash flow hedges:
Commodity contracts									$ (88,477)	$ 115,293	$ 335,019
Income (Loss) From Continuing Operations Before Income Taxes									(247,151)	(1,480,736)	140,371
Income tax expense									79,638	535,005	(40,728)
Income (Loss) From Continuing Operations	$ (54,470)	$ 53,314	$ 36,759	$ (203,116)	$ (590,806)	$ (227,904)	$ (111,601)	$ (15,420)	(167,513)	(945,731)	99,643
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax									(1,601)	(19,828)	(2,514)
Transition obligation
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax									0	0	(22)
Prior service cost
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax									465	0	(248)
Actuarial losses
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax									(3,058)	(30,504)	(21,932)
Pension and Postretirement Plans
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax									(2,593)	(30,504)	(22,202)
Income tax benefit									992	10,676	7,771
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax									1,601	19,828	14,431
Commodity contracts
Gains (losses) on cash flow hedges:
Commodity contracts									(88,477)	115,293	335,019
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	0	19,331
Income tax expense									0	0	(7,414)
Income (Loss) From Continuing Operations									0	0	11,917
Reclassification out of Accumulated Other Comprehensive Income | Commodity contracts | Cash Flow Hedges
Gains (losses) on cash flow hedges:
Commodity contracts									0	0	21,611
Reclassification out of Accumulated Other Comprehensive Income | Interest rate swap | Cash Flow Hedges
Gains (losses) on cash flow hedges:
Interest rate swap									$ 0	$ 0	$ (2,280)

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Selected Quarterly Financial Information [Abstract]
Revenues	$ 114,520	$ 184,385	$ 105,765	$ 128,219	$ 192,799	$ 295,571	$ 168,326	$ 221,858	$ 532,889	$ 878,554	$ 1,679,213
Operating income (loss)	(68,596)	90,302	68,875	(301,811)	(915,550)	(348,214)	(161,678)	(12,409)	(211,230)	(1,437,851)	176,961
Income (loss) from continuing operations	(54,470)	53,314	36,759	(203,116)	(590,806)	(227,904)	(111,601)	(15,420)	(167,513)	(945,731)	99,643
Net Income (loss)	$ (54,470)	$ 53,314	$ 36,759	$ (203,116)	$ (590,806)	$ (227,904)	$ (111,601)	$ (15,420)	$ (167,513)	$ (945,731)	$ 568,032
Diluted earnings per average common share
Continuing operations (in dollars per share)	$ (0.56)	$ 0.55	$ 0.38	$ (2.34)	$ (7.50)	$ (2.89)	$ (1.52)	$ (0.21)	$ (1.77)	$ (12.43)	$ 1.36
Net income (loss) (in dollars per share)	(0.56)	0.55	0.38	(2.34)	(7.50)	(2.89)	(1.52)	(0.21)	(1.77)	(12.43)	7.75
Basic earnings per average common share
Continuing operations (in dollars per share)	(0.56)	0.55	0.38	(2.34)	(7.50)	(2.89)	(1.52)	(0.21)	(1.77)	(12.43)	1.37
Net income (loss) (in dollars per share)	$ (0.56)	$ 0.55	$ 0.38	$ (2.34)	$ (7.50)	$ (2.89)	$ (1.52)	$ (0.21)	$ (1.77)	$ (12.43)	$ 7.79

OIL AND NATURAL GAS OPERATIO107

OIL AND NATURAL GAS OPERATIONS (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Proved	$ 7,543,464	$ 7,911,554
Unproved	196,888	150,674
Total capitalized costs	7,740,352	8,062,228
Accumulated depreciation, depletion and amortization	3,723,669	3,673,569
Capitalized costs, net	$ 4,016,683	$ 4,388,659

OIL AND NATURAL GAS OPERATIO108

OIL AND NATURAL GAS OPERATIONS (Unaudited) - Costs Incurred (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property acquisition:
Proved	$ 4,066	$ 1,866	$ 2,582
Unproved	143,667	85,690	68,514
Exploration	349,463	649,764	972,164
Development	89,624	372,177	408,949
Total costs incurred	$ 586,820	$ 1,109,497	$ 1,452,209

OIL AND NATURAL GAS OPERATIO109

OIL AND NATURAL GAS OPERATIONS (Unaudited) - Results of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reserve Quantities [Line Items]
Gross revenues	$ 532,889	$ 878,554	$ 1,679,213
Production (lifting costs)	214,652	285,760	376,495
Exploration expense	5,415	14,877	28,090
Depreciation, depletion and amortization including asset impairments	663,659	1,880,190	960,539
Accretion expense	6,672	7,108	7,608
Income tax expense (benefit)	(123,153)	(469,362)	99,469
Results of operations from producing activities	(234,356)	(840,019)	207,012
Commodity contracts
Reserve Quantities [Line Items]
Open non-cash mark-to-market gains (losses) on derivative instruments	$ (71,190)	$ (281,752)	$ 315,445

OIL AND NATURAL GAS OPERATIO110

OIL AND NATURAL GAS OPERATIONS (Unaudited) - Oil and Gas Operations (Details)	12 Months Ended
	Dec. 31, 2016MMBoeMBblsMMcf	Dec. 31, 2015MMBoeMBblsMMcf	Dec. 31, 2014MMBoeMBblsMMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period, total (in mmboe) | MMBoe	354.7	372.7	347.8
Revisions of previous estimates, total (in mmboe) | MMBoe	(26)	(58.9)	(75.7)
Purchases, total (in mmboe) | MMBoe	0.1	0	0.1
Extensions and discoveries, total (in mmboe) | MMBoe	64.1	132.6	130
Production, total (in mmboe) | MMBoe	(21.6)	(24)	(25.8)
Sales, total (in mmboe) | MMBoe	(55)	(67.7)	(3.7)
Proved reserves at end of period, total (in mmboe) | MMBoe	316.3	354.7	372.7
Proved developed reserves at end of period (in mmboe) | MMBoe	162.1	184	264.5
Proved undeveloped reserves at end of period (in mmboe) | MMBoe	154.2	170.7	108.2
Oil Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period (in mbbls and mmcf)	210,691	181,227	164,870
Revisions of previous estimates (in mbbls and mmcf)	(17,840)	(39,537)	(48,548)
Purchases (in mbbls and mmcf)	103	2	88
Extensions and discoveries (in mbbls and mmcf)	45,129	83,319	76,722
Production (in mbbls and mmcf)	(13,213)	(14,023)	(11,818)
Sales (in mbbls and mmcf)	(25,295)	(297)	(87)
Proved reserves at end of period (in mbbls and mmcf)	199,575	210,691	181,227
Proved developed reserves at end of period (in mbbls and mmcf)	101,202	108,319	118,697
Proved undeveloped reserves at end of period (in mbbls and mmcf)	98,373	102,372	62,530
Natural Gas Liquids Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period (in mbbls and mmcf)	71,713	73,463	63,011
Revisions of previous estimates (in mbbls and mmcf)	(6,800)	(11,979)	(15,165)
Purchases (in mbbls and mmcf)	21	1	26
Extensions and discoveries (in mbbls and mmcf)	10,480	25,530	29,695
Production (in mbbls and mmcf)	(3,892)	(4,065)	(4,104)
Sales (in mbbls and mmcf)	(13,476)	(11,237)	0
Proved reserves at end of period (in mbbls and mmcf)	58,046	71,713	73,463
Proved developed reserves at end of period (in mbbls and mmcf)	29,767	36,374	47,621
Proved undeveloped reserves at end of period (in mbbls and mmcf)	28,279	35,339	25,842
Natural Gas Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period (in mbbls and mmcf) | MMcf	433,904	707,926	719,725
Revisions of previous estimates (in mbbls and mmcf) | MMcf	(7,779)	(44,176)	(71,806)
Purchases (in mbbls and mmcf) | MMcf	89	2	116
Extensions and discoveries (in mbbls and mmcf) | MMcf	50,780	143,022	141,209
Production (in mbbls and mmcf) | MMcf	(27,204)	(35,604)	(59,562)
Sales (in mbbls and mmcf) | MMcf	(97,542)	(337,266)	(21,756)
Proved reserves at end of period (in mbbls and mmcf) | MMcf	352,248	433,904	707,926
Proved developed reserves at end of period (in mbbls and mmcf) | MMcf	187,117	236,112	589,074
Proved undeveloped reserves at end of period (in mbbls and mmcf) | MMcf	165,131	197,792	118,852

OIL AND NATURAL GAS OPERATIO111

OIL AND NATURAL GAS OPERATIONS (Unaudited) - Oil and Gas Operations, Activities (Details)	12 Months Ended
	Dec. 31, 2016MMBoe	Dec. 31, 2015MMBoe	Dec. 31, 2014MMBoepay_addwell_location
Reserve Quantities [Line Items]
Reserves included in engineer estimates (in percentage)	99.00%
Revisions of previous estimates (in mmboe)	(26)	(58.9)	(75.7)
Purchases (in mmboe)	0.1	0	0.1
Extensions and discoveries (in mmboe)	64.1	132.6	130
Percentage of undeveloped portion of proved reserves	65.00%	78.00%	70.00%
Percentage of developed portion of proved reserves	35.00%	22.00%	30.00%
Sales (in mmboe)	55	67.7	3.7
Extension Drilling
Reserve Quantities [Line Items]
Extensions and discoveries (in mmboe)		3.1	89.6
Exploratory Drilling
Reserve Quantities [Line Items]
Extensions and discoveries (in mmboe)	64.1	129.5	40.4
Price Related Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)	11	(38)	3.9
No Longer Expected to be Drilled
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)	(22.9)
No Longer Expected to Be Drilled Beyond Five Years
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)			(53.4)
Expected to Be Drilled Beyond Five Years
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)		(8.2)
San Juan Basin properties
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)			1.6
Extensions and discoveries (in mmboe)			1.1
Number of well locations | well_location			16
Pay-add locations | pay_add			10
San Juan Basin properties | Price Related Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)			4.4
San Juan Basin properties | Higher Operating Costs
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)			(1.5)
Permian Basin unproved leasehold properties
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)	7.5	(5.5)	(77.3)
Extensions and discoveries (in mmboe)			128.6
Number of well locations | well_location			361
Permian Basin unproved leasehold properties | Interference Caused by Welbore Placement Geometry
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)		(5)
Permian Basin unproved leasehold properties | Higher Operating Costs
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)			(5.4)
Permian Basin unproved leasehold properties | Reclassifying as Unproved
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)			(53.4)
Permian Basin unproved leasehold properties | Well Performance Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)			(13.3)
Permian Basin unproved leasehold properties | Change in Year-End Pricing Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates (in mmboe)			(0.5)
North Louisiana/East Texas oil and natural gas properties
Reserve Quantities [Line Items]
Sales (in mmboe)			3.7

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, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future gross revenues				$ 9,191,808	$ 11,714,729	$ 20,971,672
Future production costs				3,126,153	4,353,974	7,532,273
Future development costs				1,632,577	1,961,661	1,784,738
Future income tax expense				762,921	1,065,887	3,440,582
Future net cash flows				3,670,157	4,333,207	8,214,079
Discount at 10% per annum				2,320,350	2,299,859	3,994,423
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	$ 1,349,807	$ 2,033,348	$ 4,219,656
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	2,033,348	4,219,656	4,017,841
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(221,639)	(2,861,591)	(1,147,028)
Net changes due to revisions in quantity estimates	(167,188)	(404,708)	(1,285,394)
Development costs incurred, previously estimated	71,099	350,560	337,198
Accretion of discount	203,335	421,966	401,784
Changes in timing and other	(100,742)	(903,975)	987,652
Total revisions	(215,135)	(3,397,748)	(705,788)
New field discoveries and extensions, net of future production and development costs	352,358	776,315	2,321,028
Sales of oil and gas produced, net of production costs	(440,446)	(514,380)	(1,054,553)
Purchases	1,733	8	4,241
Sales	(235,222)	(372,039)	(21,092)
Net change in income taxes	(146,829)	1,321,536	(342,021)
Net change in standardized measure of discounted future net cash flows	(683,541)	(2,186,308)	201,815
Balance at end of year	$ 1,349,807	$ 2,033,348	$ 4,219,656