10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2015

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___

Commission file number 1-7810

Energen Corporation

(Exact name of registrant as specified in its charter)

Alabama	63-0757759
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

605 Richard Arrington Jr. Boulevard North, Birmingham, Alabama 35203-2707	35203-2707
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code

(205) 326-2700

Securities Registered Pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, $0.01 par value	New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES x NO o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES o NO x

Indicate by a check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. YES x NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES x NO o

Indicate by a check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO x

Aggregate market value of the voting stock held by non-affiliates of the registrant as of June 30, 2015: $5,283,012,351

Number of shares outstanding of the registrant’s common stock as of February 5, 2016: 78,791,451 shares

DOCUMENTS INCORPORATED BY REFERENCE

Energen Corporation Proxy Statement to be filed on or about March 21, 2016 (Part III, Item 10-14)

	ENERGEN CORPORATION 2015 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
		Page
Industry Glossary		3
Cautionary Statement Regarding Forward-Looking Statements		5
	PART I
Item 1.	Business	7
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	19
Item 2.	Properties	20
Item 3.	Legal Proceedings	23
Item 4.	Mine Safety Disclosures	23
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
	Purchases of Equity Securities	25
Item 6.	Selected Financial Data	27
Item 7.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	29
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 8.	Financial Statements and Supplementary Data	47
Item 9.	Changes in and Disagreements with Accountants on Accounting and
	Financial Disclosure	95
Item 9A.	Controls and Procedures	95
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	96
Item 11.	Executive Compensation	96
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	96
Item 13.	Certain Relationships and Related Transactions, and Director Independence	96
Item 14.	Principal Accountant Fees and Services	96
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	97
Signatures		100

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INDUSTRY GLOSSARY   For a more complete definition of certain terms defined below, as well as other terms and concepts applicable to successful efforts accounting, please refer to Rule 4-10(a) of Regulation S-X, promulgated pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, each as amended.
Basin	A large natural depression on the earth’s surface in which sediments accumulate.
Basis	The difference between the futures price for a commodity and the corresponding cash spot price. This commonly is related to factors such as product quality, location and contract pricing.
Basin Specific	A type of derivative contract whereby the contract’s settlement price is based on specific geographic basin indices.
Bbl	A standard barrel containing 42 United States gallons.
Bcf	One billion cubic feet of natural gas.
BOE	One barrel of oil equivalent, a standard conversion used to express oil and natural gas volumes on a comparable oil equivalent basis. Natural gas equivalents are determined under the relative energy content method by using the ratio of six Mcf of natural gas to one barrel of oil.
Cash Flow Hedge	The designation of a derivative instrument to reduce exposure to variability in cash flows from the forecasted sale of oil, natural gas liquids or natural gas production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted sale.
Collar	A contractual arrangement that effectively establishes a price range between a floor and a ceiling for the underlying commodity. The purchaser bears the risk of fluctuation between the minimum (or floor) price and the maximum (or ceiling) price.
Development Costs	Costs necessary to gain access to, prepare and equip development wells in areas of proved reserves.
Development Well	A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Downspacing	An increase in the number of available drilling locations as a result of a regulatory commission order.
Dry Well	An exploratory or a development well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Exploration Expenses	Costs primarily associated with drilling unsuccessful exploratory wells in undeveloped properties or exploratory geological and geophysical activities.
Exploratory Well	A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.
Field	An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Futures Contract	An exchange-traded contractual arrangement to buy or sell a standard quantity and quality of a commodity at a specified future date and price. Such contracts offer liquidity and minimal credit risk exposure but lack the flexibility of swap contracts.
Hedging	The use of derivative commodity instruments such as futures, swaps, options and collars to help reduce financial exposure to commodity price volatility.
Gross Well or Acre	A well or acre in which a working interest is owned.
LIBOR	London Interbank Offered Rate.
MBbl	One thousand barrels of oil.
MBOE	One thousand BOE.
MBOE/d	One thousand BOE per day.
Mcf	One thousand cubic feet of natural gas.
MMBOE	One million BOE.
MMcf	One million cubic feet of natural gas.
MMcfe	One million cubic feet of natural gas equivalent.
MMgal	One million gallons of natural gas liquids.

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Natural Gas Liquids (NGL)	Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and other hydrocarbons.
Net Well or Acre	A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.
NYMEX	New York Mercantile Exchange.
Operational Enhancement	Any action undertaken to improve production efficiency of oil and natural gas wells and/or reduce well costs.
Operator	The company responsible for exploration, development and production activities for a specific project.
Pay-Add	An operation within a currently producing wellbore that attempts to access and complete an additional pay zone(s) while maintaining production from the existing completed zone(s).
Pay Zone	The stratigraphic horizon from which oil and natural gas is produced.
Production (Lifting) Costs	Costs incurred to operate and maintain wells.
Productive Well	An exploratory or a development well that is not a dry well.
Proved Developed Reserves	The portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves	Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved Reserves-to-Production Ratio	Ratio expressing years of supply determined by dividing the remaining recoverable proved reserves at year end by actual annual production volumes. The reserve-to-production ratio is a statistical indicator with certain limitations, including predictive value. The ratio varies over time as changes occur in production levels and remaining recoverable proved reserves.
Proved Undeveloped Reserves (PUD)	The portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
Recompletion	An operation within an existing wellbore whereby a completion in one pay zone is abandoned in order to attempt a completion in a different pay zone.
Reservoir	A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
SEC	The United States Securities and Exchange Commission.
Service Well	A well employed for the introduction into an underground stratum of water, gas or other fluid under pressure or disposal of salt water produced with oil or other waste.
Sidetrack Well	A new section of wellbore drilled from an existing well.
Swap	A contractual arrangement in which two parties, called counterparties, effectively agree to exchange or “swap” variable and fixed rate payment streams based on a specified commodity volume. The contracts allow for flexible terms such as specific quantities, settlement dates and location but also expose the parties to counterparty credit risk.
Undeveloped Acreage	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working Interest	Ownership interest in the oil and natural gas properties that is burdened with the cost of development and operation of the property.
Workover	A major remedial operation on a completed well to restore, maintain, or improve the well’s production such as deepening the well or plugging back to produce from a shallow formation.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

All statements, other than statements of historical fact, appearing in this report constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, and are noted in Energen’s disclosure and analysis as permitted by the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among other things, statements about our expectations, beliefs, intentions or business strategies for the future, statements concerning our outlook with regard to the timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, the nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, the timing and success of specific projects, operating costs and other expenses, proved oil and natural gas reserves, liquidity and capital resources, outcomes and effects of litigation, claims and disputes and derivative activities. In particular, forward-looking statements may include words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “forecast”, “foresee”, “intend”, “may”, “plan”, “potential”, “predict”, “project”, “seek”, “will” or other words or expressions concerning matters that are not historical facts. These statements involve certain risks and uncertainties that may cause actual results to differ materially from expectations as of the date of this filing.

Factors that could cause actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the following:

• volatility of oil, natural gas liquids and natural gas prices;

• uncertainties about the estimates of our proved oil, natural gas liquids and natural gas reserves;

• drilling risks;

• risks associated with our concentration of operations in the Permian Basin of west Texas and New Mexico and the San Juan Basin in New Mexico;

• competition in the oil and natural gas industry;

• the adequacy of our capital resources, access to financing and liquidity;

• operational risks including risks of personal injury, property damage and environmental damage;

• changes in the regulatory environment at the federal, state, or local level and our ability to comply with regulations promulgated by the various regulatory bodies;

• changes in and the effects of environmental and other governmental regulation that applies to our operations, including new legislation or regulation of hydraulic fracturing, water use and disposal, permitting, climate change and other legal requirements;

• instability in the domestic and global capital and credit markets;

• financial strength of the parties with whom we do business, including other working interest owners, providers of midstream services, providers of oilfield services, purchasers of our oil, natural gas liquids and natural gas and the counterparties to our derivative contracts;

• changes in domestic and global economic and business conditions that impact the demand for oil, natural gas liquids and natural gas;

• changes in domestic and global supplies of oil, natural gas and natural gas liquids arising from economic and business conditions (including actions by the Organization of the Petroleum Exporting Countries);

• uncertainties about our ability to successfully execute our business and financial plans and strategies, including but not limited to our ability to economically develop our proved oil, natural gas liquids and natural gas reserves and to replace those reserves as scheduled as well our ability to project future rates of production and the timing of development expenditures;

• risks associated with our ability to execute on property acquisitions and divestitures including market liquidity, price levels, timing and financing associated with such transactions;

• the effectiveness of and our ability to use derivative instruments as part of our risk management activities;

• the costs and effects of litigation; and

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• acts of nature, sabotage, terrorism or other malicious intentional acts (including cyber-attacks), war and other similar acts that disrupt operations or cause damage greater than covered by insurance.

See Item 1A, Risk Factors, for a discussion of risk factors that may affect Energen and cause material variances from forward-looking statement expectations. The Item 1A, Risk Factors, discussion is incorporated by reference into this forward-looking statement disclosure.

Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. We base our forward-looking statements on information currently available to us, and we undertake no obligation to update or revise any of these statements, whether as a result of changes in underlying factors, new information, future events or other developments.

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PART I

ITEM 1.BUSINESS

General

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 in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Headquartered in Birmingham, Alabama, our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources). At December 31, 2015, our remaining San Juan Basin properties were classified as held for sale and, subsequent to year-end, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale.

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 the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. See Note 16, Discontinued Operations and Held for Sale Properties, for further information regarding the sale of Alagasco.

Energen was incorporated in 1978 in connection with a corporate reorganization completed in 1979 which resulted in Energen becoming the parent company to Energen Resources, which was formed in 1971, and Alagasco. Alagasco was formed by merger in 1948. As noted above, Alagasco was sold in 2014 to Laclede.

Energen maintains a web site with the address www.energen.com. Information contained on this web site is not incorporated by reference into this report. Energen makes available free of charge through its web site the annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports. Also, these reports are available in print upon shareholder request. These reports are available as soon as reasonably practicable after being electronically filed with or furnished to the Securities and Exchange Commission. Energen’s web site also includes its Business Conduct Guidelines, Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter and Governance and Nominations Committee Charter, each of which is available in print upon shareholder request.

Narrative Description of Business

• Oil and Natural Gas Operations

General: Energen’s operations focus on increasing production and adding proved reserves through the development of oil, natural gas liquids and natural gas properties. In addition, Energen explores for and develops new reservoirs, primarily in areas in which it has an operating presence. All oil, natural gas liquids and natural gas production is sold to third parties. Energen operates its properties for its own interest and that of its joint interest owners. This role includes overall project management and day-to-day decision-making relative to project operations.

At the end of 2015, Energen’s proved reserves totaled 354.7 MMBOE. Substantially all of these proved reserves are located in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Approximately 52 percent of Energen’s year-end proved reserves are proved developed reserves. Energen’s proved reserves are long-lived, with a year-end proved reserves-to-production ratio of 15 years. Oil, natural gas liquids and natural gas represent approximately 59 percent, 20 percent and 21 percent, respectively, of Energen’s proved reserves.

Property Acquisitions and Dispositions: In March 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 held for sale properties totaled 69,038 MBOE.

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In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million. The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations.

In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million. Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 that was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013.

Growth Strategy: Energen is focused on increasing its oil, natural gas liquids and natural gas production and proved reserves largely through active development and/or exploratory programs in the Permian Basin. The Company seeks to expand its footprint primarily through acquisitions of proved properties and unproved leasehold within areas of existing operations. Energen operated approximately 96 percent of its proved reserves at December 31, 2015.

Energen’s capital spending plans for 2016 target a total investment of approximately $250 million, the bulk of which will focus on drilling and development activities on its existing properties, all targeting the liquids-rich Permian Basin. Energen may choose to allocate additional capital during the year for property acquisitions and/or increased drilling and development activities.

Energen’s development activities can result in the addition of new proved reserves and can serve to reclassify proved undeveloped reserves to proved developed reserves. Proved reserve disclosures are provided annually, although changes to reserve classifications occur throughout the year. Accordingly, additions of new proved reserves from development activities can occur throughout the year and may result from numerous factors including, but not limited to, regulatory approvals for drilling unit downspacing that increase the number of available drilling locations; changes in the economic or operating environments that allow previously uneconomic locations to be added; technological advances that make reserve locations available for development; successful development of existing proved undeveloped reserve locations that reclassify adjacent probable locations to proved undeveloped reserve locations; increased knowledge of field geology and engineering parameters relative to oil and natural gas reservoirs; and changes in management’s intent to develop certain opportunities.

During the three years ended December 31, 2015, Energen’s development and exploratory efforts have added 299 MMBOE of proved reserves from the drilling of 883 gross development, exploratory and service wells (including one sidetrack well) and 154 well recompletions and pay-adds. In 2015, Energen’s successful development and exploratory wells and other activities added approximately 133 MMBOE of proved reserves; Energen drilled 190 gross development, exploratory and service wells (including one sidetrack well), performed some 19 well recompletions and pay-adds, and conducted other operational enhancements. Energen’s production from continuing operations totaled 24 MMBOE in 2015, including 3.8 MMBOE from our held for sale properties. In 2016, production is estimated to range from 19.5 MMBOE to 20.3 MMBOE, with a midpoint of 19.9 MMBOE, including approximately 17.6 MMBOE of estimated production from proved reserves owned at December 31, 2015. Production estimates do not include amounts on held for sale properties or potential future acquisitions.

Drilling Activity: The following table sets forth the total number of net productive and dry exploratory and development wells drilled:

Years ended December 31,	2015	2014	2013
Development:
Productive	50.8	80.2	169.5
Dry	—	—	—
Total	50.8	80.2	169.5
Exploratory:
Productive	98.5	109.4	89.1
Dry	2.0	1.0	0.9
Total	100.5	110.4	90.0

As of December 31, 2015, Energen was participating in the drilling of 1 gross (1 net) development and 1 gross (1 net) exploratory wells. In addition to the development wells drilled, Energen drilled 12.9, 22.5 and 9.8 net service wells during 2015, 2014 and 2013, respectively. Energen had no service wells in process as of December 31, 2015. Also, as of December 31, 2015, Energen

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had 48 gross (48 net) drilled but uncompleted wells in the Midland Basin, of which we plan to complete 46 gross (46 net) in 2016.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2015, and developed and undeveloped acreage as of the latest practicable date prior to year end:

	Gross	Net
Oil wells	5,345	3,513
Gas wells	554	415
Developed acreage	443,139	319,578
Undeveloped acreage	186,054	136,216

There was one well with multiple completions at December 31, 2015. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Texas and New Mexico.

Concentration of Credit Risk:Revenues and related accounts receivable from oil and natural gas operations primarily are generated from the sale of produced oil and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect Energen’s overall exposure to credit risk, either positively or negatively, in that our oil and natural gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen considers the credit quality of its purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The two largest purchasers of Energen’s oil and natural gas, Plains Marketing, LP (Plains) and Shell Trading (US) Company, accounted for approximately 47 percent and 21 percent, respectively, of Energen’s accounts receivable for commodity sales as of December 31, 2015. Energen’s other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2015. During the year ended December 31, 2015, Plains accounted for approximately 33 percent of total revenues, excluding the impact of non-cash mark-to-market open derivatives. All other oil and natural gas purchasers each accounted for less than 10 percent of total revenues for the year ended December 31, 2015.

Risk Management: Energen attempts to lower the commodity price risk associated with its oil and natural gas business through the use of swaps and basis swaps. Energen has policies in place to limit hedging to not more than 80 percent of its estimated annual production; however, Energen’s credit facility contains a covenant that operates to limit hedging at a lower threshold in certain circumstances. Energen recognizes all derivatives on the balance sheet and measures all derivatives at fair value. Prior to June 30, 2013, the Company utilized cash flow hedge accounting, where applicable, for its derivative transactions. Effective June 30, 2013, Energen discontinued the use of cash flow hedge accounting and dedesignated all remaining derivative commodity instruments that were previously designated as cash flow hedges.

See the Cautionary Statement Regarding Forward-Looking Statements preceding Item 1, Business, and Item 1A, Risk Factors, for further discussion with respect to price and other risks.

• Environmental Matters and Climate Change

Various federal, state and local environmental laws and regulations apply to the operations of Energen. 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.

Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend and interpret existing laws and regulations. Such law and regulation changes may occur with little prior notification, subject Energen to cost increases, and impose restrictions and limitations on our operations. Examples of law and regulatory changes with the potential to materially impact Energen include, but are not limited to, measures dealing with hydraulic fracturing, emission limits and reporting and the repeal of certain oil and natural gas tax incentives and deductions.

Energen regularly utilizes hydraulic fracturing in its drilling and completion activities. Energen’s first widespread use of hydraulic fracturing occurred during the 1980s when we successfully pioneered the exploration and development of coalbed methane in Alabama’s Black Warrior Basin.

Hydraulic fracturing is a well-established reservoir stimulation technique used throughout the oil and natural gas industry for more than 60 years. After a well has been drilled, hydraulic fracturing is used during the completion process to form small

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fractures in the target formation through which the natural gas and/or oil can flow. The fractures are created when a water-based fluid is pumped at a calculated rate and pressure into the natural gas- or crude oil-bearing rock. The fracture fluid is a mixture composed primarily of water and sand or inert ceramic, sand-like grains; it also contains a small percentage of special purpose chemical additives (which are highly diluted-typically less than one percent by volume) that can vary by project. The millimeter-thick cracks or fractures in the target formation are propped open by the sand, thereby allowing the crude oil or natural gas to flow from tight (low permeability) reservoirs into the well bore.

Various states in which we operate have adopted a variety of well construction, set back, and disclosure regulations limiting how drilling can be performed and requiring various degrees of chemical and water usage disclosure for operators that employ hydraulic fracturing. We are complying with these additional regulations as part of our routine operations and within the normal execution of our business plan. The adoption of additional federal or state regulations, however, could impose significant new costs and challenges. For example, adoption of new hydraulic fracturing permitting requirements could significantly delay or prevent new drilling. Adoption of new regulatory restrictions on the use of hydraulic fracturing could reduce the amount of oil and gas able to be recovered from our proved reserves. The degree to which additional oil and natural gas industry regulation may impact our future operations and results will depend on the extent to which we utilize the regulated activity and whether the geographic locations in which we operate are subject to the new regulation.

Existing federal, state and local environmental laws and regulations also have the potential to increase costs, reduce liquidity, delay operations and otherwise alter business operations. These existing laws and regulations include, but are not limited to, the Clean Air Act; the Clean Water Act; Oil Pollution Prevention: Spill Prevention, Control, and Countermeasure regulations; Toxic Substances Control Act; Resource Conservation and Recovery Act; and the Federal Endangered Species Act. Compliance with these and other environmental laws and regulations is undertaken as part of Energen’s routine operations. Energen does not separately track costs associated with these routine compliance activities.

Climate change, whether arising through natural occurrences or human activities, may have a significant impact upon the operations of Energen. Volatile weather patterns and the resulting environmental impact may adversely affect our results of operations, financial position and cash flows. We are unable to predict the timing or manifestation of climate change or reliably estimate the impact to Energen. However, climate change could affect our operations as follows:

• sustained increases or decreases to the supply and demand of oil, natural gas liquids and natural gas;

• potential disruption to third-party facilities to which Energen delivers. Such facilities include third-party oil and gas gathering, transportation, processing and storage facilities and are typically limited in number and geographically concentrated.

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.

• Employees

The Company has approximately 470 employees. On January 22, 2016, we reduced our workforce as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. Energen believes that its relations with employees are good.

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ITEM 1A. RISK FACTORS

The future success and continued viability of our business, like any venture, is subject to many recognized and unrecognized risks and uncertainties. Such risks and uncertainties could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by management. The following list identifies and briefly summarizes certain risk factors. The list should not be viewed as complete or comprehensive, as the risks below are not the only risks facing Energen. Energen could also be affected by other risks and uncertainties in addition to those described herein. If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected; and such events could impair our ability to implement business plans or complete development activities as scheduled. Further, the trading price of our shares could decline; and shareholders could lose part or all of their investment. In addition, such risks may prevent us from complying with our financial and non-financial covenants and may result in a default under our credit facility or other long-term debt.

We undertake no obligation to correct or update such risk factors whether as a result of new information, future events or otherwise. These risk factors should be read in conjunction with our disclosure specific to forward-looking statements made elsewhere in this report under the heading Cautionary Statement Regarding Forward-Looking Statements.

Risks Related to Our Business

If oil and natural gas prices remain at their current levels for an extended period of time or continue to decline, it could adversely affect our financial condition and results of operations.

Our revenues, cash flows and earnings are influenced predominantly by the amount of oil and natural gas we produce and the prices we receive for production. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. For example, during the year ended December 31, 2015, commodity prices changed significantly, with the settlement price for West Texas Intermediate (WTI) crude oil ranging from a high of approximately $61.43 per barrel to a low of approximately $34.73 per barrel and settlement prices for Henry Hub natural gas ranging from a high of approximately $3.23 per Mcf to a low of approximately $1.76 per Mcf. Commodity price weakness has continued into 2016 and, through February 12, 2016, the WTI settlement price of crude oil had a low of approximately $26.21 per barrel, with a February 12, 2016 closing price of approximately $29.44 per barrel, and the Henry Hub settlement price of natural gas had a low of approximately $1.97 per Mcf, with a February 12, 2016 closing price of approximately $1.97 per Mcf.

In addition to reducing our revenue, cash flows and earnings, depressed prices for oil and natural gas may adversely affect us in a variety of ways. If commodity prices do not improve or further decrease, some of our exploration and development projects could become uneconomic, and we may also have to make significant downward adjustments to our estimated proved reserves and our estimates of the present value of those reserves. If these price effects occur, or if our estimates of production or economic factors change, accounting rules may require us to writedown, as a noncash impairment loss in our statements of income, the carrying value of our proved oil and natural gas properties. Lower commodity prices may also result in a reduction in the amount we are permitted to borrow under our credit facility and adversely impact our ability to meet financial ratios contained in our debt agreements, especially those calculated by reference to the value of our reserves, earnings or cash flows, which could reduce the amount we are permitted to borrow under our credit facility or result in an event of default. We could also be required to reduce our capital spending on exploration and development, which will adversely affect our ability to replace our reserves and could result in the loss of leasehold. As more fully disclosed in Note 1, Organization and Basis of Presentation, in the Notes to Financial Statements, and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Liquidity”, the Company discusses its plans regarding liquidity and covenant compliance for 2016.

Commodity prices for crude oil and natural gas are volatile, and a substantial reduction in commodity prices could adversely affect our financial condition and results of operations.

Our business is significantly impacted by commodity prices, and historical markets for oil, natural gas liquids and natural gas have been volatile. Energen’s revenues, operating results, profitability and cash flows depend primarily upon the prices realized for our oil, natural gas liquids and natural gas production.

Approximately 59 percent of our December 31, 2015 proved reserves are oil. As a result, changes in oil prices have a greater impact on our business than changes of comparable magnitude in natural gas prices. Commodity prices for oil, natural gas liquids and natural gas are reflections of supply and demand and are subject to many factors that are beyond our control, including:

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• the domestic and foreign supply of oil, natural gas liquids and natural gas, including the ability of the members of the Organization of the Petroleum Exporting Countries and other exporting countries to agree on and maintain oil price and production controls;

• the level of consumer demand for oil, natural gas liquids and natural gas;

• global or regional oil and natural gas inventory levels;

• the availability, proximity and capacity of transportation facilities and processing facilities;

• global economic conditions;

• commodity price disparities between delivery points and applicable index prices;

• the supply, demand and pricing of alternative sources of energy or fuels and the effects of energy conservation efforts or technological advances in energy consumption;

• weather conditions;

• changes in political conditions in major oil and natural gas producing regions and

• domestic, local and foreign governmental regulations and taxes.

The decline since late 2014 in oil, natural gas liquids and natural gas prices has reduced our revenue and cash flows and, unless commodity prices improve, this trend will likely continue or worsen. Lower oil, natural gas liquids and natural gas prices also potentially reduce the amount of oil and natural gas that we can economically produce resulting in a reduction in the proved oil and natural gas reserves we could recognize. Thus, significant and sustained commodity price reductions could materially and adversely affect our financial condition and results of operations which could impact our ability to maintain or increase our current levels of borrowing, our ability to repay current or future indebtedness, our ability to refinance our current indebtedness or obtain additional capital on attractive terms.

We engage in derivative risk management activities in order to reduce our risks associated with commodity price fluctuations. We currently have significantly fewer hedges in place for 2016 and at lower price levels than in 2015 and may not be able to execute new hedges at acceptable volumes or price levels.

Revenues realized from hedging have also been significantly impacted by substantial reductions in oil, natural gas liquids and natural gas prices. During 2015, our hedges included 11,180 MBbl of crude oil production at an average NYMEX price of $82.34 per barrel and 29 Bcf of natural gas production at an average NYMEX equivalent price of $4.33 per Mcf. We currently have 2016 hedges of approximately 1,086 MBbl of our crude oil production hedged at an average NYMEX price of $63.80 per barrel. In addition, we have hedges of 6.6 Bcf of natural gas production at a NYMEX equivalent price of $2.47 per Mcf. Unless 2016 commodity prices increase, the net prices we will receive for our 2016 production will decline significantly from 2015 which will adversely affect our revenues and cash flows during 2016. Further, there is no assurance that commodity prices will not decline further and our ability to hedge against future commodity price declines may be significantly limited.

Our oil and natural gas proved reserves are estimates, and actual future production may vary significantly and may also be negatively impacted by our inability to invest in production on planned timelines.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures. Reserve estimation is a subjective process involving the estimation of volumes to be recovered from underground accumulations of oil and natural gas that are unable to be measured in an exact manner. The reserve estimation process is dependent upon and subject to multiple variables and assumptions, including:

• oil, natural gas liquids and natural gas prices;

• timing of development expenditures;

• the quality, quantity and interpretation of available geological, geophysical and engineering data;

• the geologic characteristics of the reservoirs;

• future operating costs, property, severance, excise and other taxes and costs and

• the effects of compliance with regulatory and contractual requirements.

Additionally, in the event we are unable to fully invest or must alter the timing of our planned investment expenditures, our future revenues, production and proved reserves could be negatively affected.

The value of our proved reserves as of December 31, 2015 calculated using SEC pricing is higher than the fair market value of our proved reserves calculated using current market prices.

Our estimated proved reserves as of December 31, 2015 and related PV-10 and Standardized Measure were calculated under SEC rules using the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices of $50.28 per barrel

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of crude oil, $0.41 per gallon of natural gas liquids and $2.59 per Mcf for natural gas. Those average prices are significantly above average prices experienced during late 2015 and early 2016, and, unless commodity prices improve, our estimated reserves and related present value calculations thereof will decline substantially from our December 31, 2015 calculations, and we may incur related impairment charges, which will materially adversely affect our results of operations in the period incurred.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could impact our expenses or our production volumes.

Drilling involves many risks, including the risk that no commercially productive oil or natural gas reservoirs will be located or economically developed. Our future drilling activities may not be successful and, if unsuccessful, such failure could have a material adverse effect on our future results of operations and financial condition. Anticipated drilling plans and capital expenditures may also be delayed, curtailed or canceled which could result in actual drilling and capital expenditures being substantially different than currently planned, due to:

• delays resulting from compliance with regulatory or contractual requirements, which may include limitations on hydraulic

fracturing or the emission of greenhouse gases;

• unexpected or unusual pressure or irregularities in geological formations;

• unexpected drilling conditions;

• declines in oil, natural gas liquids or natural gas prices;

• adverse weather conditions, such as tornadoes, snow and ice storms;

• delays in, limited availability of, or cost to obtain personnel and equipment necessary to complete our drilling,

completion and operating activities;

• equipment or facility failures and accidents or malfunctions resulting in blowouts, fires, explosions, uncontrollable flows of oil, natural gas or well fluids, surface cratering and other events;     

• title related issues;

• fracture stimulation failures;

• restricted access to land for drilling;

• reductions in availability of financing at acceptable rates;

• strategic changes implemented by management and

• limitations in the market for oil, natural gas liquids and natural gas.

While all drilling, whether developmental, extension or exploratory, involves these risks, exploratory and extension drilling involve greater risks of dry holes or failure to find and exploit commercially productive quantities of oil and natural gas. We expect to continue to experience exploration and abandonment expense in 2016 and future years.

Our concentration of producing properties in the Permian Basin of west Texas and the San Juan Basin of New Mexico makes us vulnerable to risks associated with operating in limited geographic areas.

At December 31, 2015, approximately 95 percent and 5 percent of our total estimated proved reserves were attributable to properties located in the Permian Basin of west Texas and San Juan Basin of New Mexico, respectively. As a result of this geographic concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by:

• governmental regulation;

• state politics;

• processing or transportation capacity constraints;

• market limitations;

• water shortages, including restrictions on water usage or other drought related conditions or

• interruption of the processing or transportation of oil, natural gas liquids or natural gas.

Our industry is highly competitive which makes it challenging for us to acquire properties to replace our proved oil and natural gas reserves, market oil and natural gas and locate and secure qualified personnel.

We operate in a highly competitive environment for acquiring properties to replace our proved oil and natural gas reserves, marketing oil and natural gas and locating and securing qualified personnel. Many of our current and potential competitors may possess greater financial, technical and personnel resources than we do. Those competitors may be willing to pay more for exploratory prospects and productive oil and natural gas properties, as well as for trained personnel. Our ability to acquire properties and to find and develop proved reserves in the future will depend on our ability to evaluate and select suitable properties and to execute

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transactions in an intensely competitive environment. Our failure to acquire properties, market oil and natural gas and secure trained personnel could have a material adverse effect on our production, revenues and results of operations.

Our business is capital intensive, and we may not be able to obtain the needed capital, financing, or refinancing of our current indebtedness on satisfactory terms or at all.

Our exploration, development and acquisition activities are capital intensive and constitute the primary use of our capital resources. We make and expect to continue to make significant capital expenditures for the exploration, development and acquisition of oil, natural gas liquids and natural gas reserves. We have historically funded our capital expenditures through cash flows from operations, our credit facility or other borrowings, debt and equity markets and property sales. We expect that we will continue to fund a portion of our capital expenditures with borrowings under our credit facility, from the proceeds of debt and equity issuances and from proceeds from property sales. However, the current commodity price environment and conditions in our industry may result in a lack of access to capital on attractive terms or at all. Thus, no assurance can be given that we will be able to access either the debt or equity capital markets, or be able to sell properties for attractive prices, to repay any such future borrowings.

If our borrowing capacity decreases, for any reason, we may have limited ability to obtain the capital necessary to support our future operations. If we are unable to obtain necessary financing with appropriate terms, we could experience a decline in our operations. Specifically, a failure to secure additional financing, or necessary refinancing, could result in a reduction of our operations relating to the development of future prospects, which in turn could lead to a decline in our proved oil and natural gas reserves and could adversely affect our future production, revenues and results of operations. Further, we could realize a loss of acreage through lease expirations, and we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

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 on April 1 and October 1 of each year and for event-driven unscheduled redeterminations. On October 20, 2015, the borrowing base and aggregate commitments were reduced to $1.4 billion from $1.6 billion in association with the semi-annual redetermination required under the agreement. As of December 31, 2015, the Company had $222.5 million outstanding under its revolving credit facility. If commodity prices remain at current levels, we would expect a further reduction in our borrowing base at the next scheduled redetermination on April 1, 2016, and such reduction could be significant. A lowering of our borrowing base could require us to immediately repay indebtedness in excess of the borrowing base, or we might need to further secure the lenders with additional collateral, if available. If our borrowing base decreases, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed to fund our capital expenditures, our ability to access the capital markets may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control.

We are also subject to financial and non-financial covenants under the terms of our credit facility. The financial covenants in our credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other noncash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0. As of December 31, 2015, we were in compliance with our covenants. However, factors including those outside of our control may prevent us from maintaining compliance with the financial and non-financial covenants, including our total debt to EBITDAX covenant, at future measurement dates in 2016 and beyond. Such factors may include further commodity price declines, lack of liquidity in property and capital markets and our continuing ability to execute on our business plan. In the event that we are unable to remain in compliance with our financial and non-financial covenants, we would seek covenant relief at a scheduled redetermination date or at an interim date, as appropriate, during 2016. However, no assurances can be given with respect to such relief. If any such covenant violations are not waived by the lenders such violation would result in an event of default that could trigger acceleration of payment of the amounts outstanding under our credit facility and long term note agreements, which is an aggregate balance outstanding of $776.5 million at December 31, 2015. Additionally, the lenders could refuse to make additional loans under the credit facility, take possession of any collateral, and exercise other remedies or rights that may be available to them, all of which could have a material adverse effect on the business and financial condition of the Company. As more fully disclosed in Note 1, Organization and Basis of Presentation, in the Notes to Financial Statements, and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Liquidity”, the Company discusses its plans regarding liquidity and covenant compliance for 2016.

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We recently announced the discontinuance of dividend payments and, therefore, only appreciation in the price of our common stock will provide a return to our stockholders.

Although we have paid cash dividends on our common stock in the past, in February 2016 our board of directors announced the discontinuance of dividend payments. We currently intend to retain future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying cash dividends on our common stock in 2016. Any payment of future dividends will be at the discretion of our board of directors and will depend on our results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other considerations that our board of directors deems relevant.

Our San Juan Basin properties were classified as held for sale at December 31, 2015 and, subsequent to December 31, 2015, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale. and recent declines in prices for crude oil and natural gas could adversely affect our ability to sell these properties and the prices we may obtain for the sale of such properties, which could adversely affect our revenue, cash flows, financial condition, our ability to fund our capital spending and our ability to comply with financial covenants under our credit agreement.

Market conditions for crude oil and natural gas, particularly the recent decline in prices for crude oil and natural gas, could adversely affect market prices for oil and gas reserves. If we are unable to sell the properties we are seeking to sell or at prices which meet or exceed the fair value, our revenue, cash flows and financial condition may be adversely affected. Many companies that might otherwise be interested in pursuing the acquisition of these properties may not have the desire or the financial ability to pursue these acquisitions in the current depressed commodities price environment. This may reduce the pool of potential buyers and our competitors may be able to utilize the oil and gas market downturn to obtain properties at steep discounts and to execute transactions in an intensely competitive market. Our failure to dispose of properties, or at the sales prices which we anticipate, could have a material adverse effect on our revenues, cash flows, financial condition and our ability to comply with financial covenants under our credit agreement.

The nature of our operations involves many operational risks including the risk of personal injury, property damage and environmental damage, and our insurance policies do not cover all such risks.

Inherent in our oil and natural gas production activities are a variety of hazards and operational risks, including, but not limited to:

• pipeline and storage leaks, ruptures and spills;

• equipment malfunctions and mechanical failures;

• fires and explosions;

• well blowouts, explosions and cratering;

• uncontrollable flows of oil, natural gas or well fluids;

• vandalism;

• pollution;

• releases of toxic gases;

• adverse weather conditions or natural disasters and

• soil, surface and water or groundwater contamination from petroleum constituents, hydraulic fracturing fluid, or produced water.

Such events could result in loss of human life, significant damage to or destruction of property, environmental pollution or other damage, impairment or suspension of our operations, repair and remediation costs, regulatory investigations and penalties or lawsuits and other substantial financial losses. Furthermore, our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including those noted above. Additionally, the location of certain of our pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.

In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks and losses; and the insurance coverages are subject to retention levels and coverage limits. We may elect not to obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Furthermore, we could be subject to the credit risk of our insurers if we make a claim under our insurance policies. There is no guarantee that we will be able to obtain or maintain our insurance in the future at rates we deem economical and that the insurance we may desire will be offered by insurers. Losses and liabilities arising from uninsured or under-insured events or insurer insolvency, in the event of a claim, could materially and adversely affect our business, financial condition or results of operations.

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We are subject to extensive regulation, including numerous federal, state and local laws and regulations as well as legislation and regulations restricting the emissions of “greenhouse gases” that may require significant expenditures or impose significant restrictions on our operations.

We are subject to extensive federal, state and local regulation which significantly influences our operations. Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations. Such changes can subject us to significant tax or increased expenditures and can impose significant restrictions and limitations on our operations. Noncompliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial cleanups, and natural resource damages or other liabilities. Furthermore, we may incur significant costs to remain in compliance with or to return to compliance with applicable regulations if they are revised or reinterpreted or if governmental policies or laws change related to our operations.

The subject of climate change continues to receive attention from many parties including legislators and governmental agencies.

If additional legislation or regulatory programs to reduce emissions of greenhouse gases are adopted, it could require us to incur increased operating costs, such as those for purchasing and operating emissions control systems, acquiring emissions allowances or complying with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming and using oil and natural gas, and thereby negatively impact the demand for the oil, natural gas liquids and natural gas we produce. Consequently, legislation and regulatory programs related to greenhouse gases could adversely affect our production, revenues and results of operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect our production.

Energen regularly utilizes hydraulic fracturing in its drilling and completion activities, and hydraulic fracturing is a common practice that is used in the oil and gas industry to stimulate production of hydrocarbons from tight (low permeability) formations. After a well has been drilled, hydraulic fracturing is used during the completion process to form small fractures in the target formation through which the oil, natural gas liquids or natural gas can flow. The fractures are created when a water-based fluid is pumped at a calculated rate and pressure into the crude oil- or natural gas-bearing rock. The fracture fluid is a mixture composed primarily of water and sand or inert ceramic, sand-like grains; it also contains a small percentage of special purpose chemical additives (which are highly diluted-typically less than one percent by volume) that can vary by project. The millimeter-thick cracks or fractures in the target formation are propped open by the sand, thereby allowing the crude oil or natural gas to flow from tight reservoirs into the well bore.

The hydraulic fracturing process is typically regulated by state oil and gas commissions. However, under the Safe Drinking Water Act’s Underground Injection Control Program, the EPA has assumed regulatory authority of hydraulic fracturing involving diesel additives and issued revised permitting guidance in February 2014 requiring facilities to obtain permits to use diesel additives in hydraulic fracturing activities. Legislation intended to provide for federal regulation of hydraulic fracturing and require disclosure of the chemicals used has been introduced and considered by the U.S. Congress. In addition, Texas and New Mexico, two states in which we operate, have adopted, and other states have considered adopting, regulations that could impose new or stricter permitting, disclosure and well construction requirements on companies that perform hydraulic fracturing. Consideration and efforts to regulate hydraulic fracturing by local, state and federal authorities continue and local land use restrictions, such as county and city ordinances, may also restrict or prohibit any type of drilling or hydraulic fracturing. If additional federal, state or local restrictions are adopted in the areas we operate or plan to operate, we may incur significant costs to comply with the requirements, experience delays or have to curtail our exploration, development, or production activities. Additionally, such restrictions could reduce the amount of oil and gas that we are able to recover from our proved reserves.

Our operations are dependent on the availability, use and disposal of water; and restrictions on our ability to acquire or dispose of water could cause us to incur substantial costs in the acquisition, usage and disposal of water.

Water is a key component of both the drilling and hydraulic fracturing processes. Historically, we have been able to obtain water from various local sources for use in our operations. Texas has recently experienced periods of severe drought conditions that have persisted for several years. Local water districts may restrict the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply during drought conditions. If we are unable to obtain water to use in our operations from local sources, we may have to incur substantial costs to produce oil and natural gas and it may make it uneconomical to produce in that area. Our drilling procedures produce water of which we must dispose. We could be unable to dispose of our wastewater or face increased costs and procedures for disposal as a result of changes in federal or local legislation governing the disposal of drilling wastewater.

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We periodically evaluate our proved and unproved oil and natural gas properties for impairment and could be required to recognize non-cash charges in our statements of income in future periods. If commodity prices for oil, natural gas liquids or natural gas decline or our drilling efforts are unsuccessful, we may be required to writedown the carrying values of certain oil and natural gas properties.

We periodically review the carrying value of our proved and unproved oil and natural gas properties for possible impairment on a field-by-field basis. We monitor our oil and natural gas properties as well as the market and business environments in which we operate and make assessments about events that could result in potential impairment issues, which include, but are not limited to, downward commodity price trends, unanticipated increased operating costs and lower than expected production performance. If a material event occurs, we perform an evaluation to determine whether the asset is impaired. If the undiscounted net future cash flows determined by such evaluations is insufficient to fully recover the cost invested in the respective project, we will record an impairment loss in our statements of income. We recorded $1.3 billion of impairments during 2015 and, if the depressed commodity price environment continues, we may be required to record additional impairments during 2016.

We are exposed to counterparty credit risk as a result of our concentrated customer base and to the risks associated with other companies with whom we do business experiencing financial distress.

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 a small number of 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 a limited number of customers in the energy marketing industry has the potential to adversely affect our overall exposure to credit risk based on changes in economic, industry or other conditions specific to a single customer or to the energy marketing industry generally. We consider the credit quality of our customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent company guarantee.

In addition, we rely on other working interest owners in our wells to pay their proportionate share of costs and on oilfield service companies and midstream companies for services associated with the drilling and completion of wells and for certain midstream services. A continuation or worsening of the depressed commodity price environment may result in a material adverse impact on the liquidity and financial position of the companies with whom we do business, resulting in delays in payment of, or non-payment of, amounts owing to us and similar impacts. These events could have an adverse impact on our financial condition, results of operations and cash flows, and it is difficult to predict how long the current depressed commodity price environment will continue and the ultimate impact it will have on the companies with which we do business.

We are subject to financing and interest rate exposure risks. Volatility in global financial markets, negative operating results, certain strategic business decisions, or other matters resulting in a downgrade in, or a negative outlook with respect to, our credit ratings could negatively impact our cost of and our ability to access capital for future development and working capital needs.

We rely on access to credit markets, and turmoil or volatility in the global financial markets could lead to a contraction in credit availability and negatively impact our ability to finance our operations. Global financial market turmoil, as has been experienced in last decade, could materially affect our operations, liquidity and financial condition through the adverse impacts such turmoil can have on the debt and equity capital markets. Market volatility and credit market disruption may severely limit credit availability, and issuer credit ratings can change rapidly. A significant reduction in cash flows from operations or the availability of credit could limit our ability to pursue acquisition opportunities or reduce cash flow used for drilling which could materially and adversely affect our ability to achieve our planned growth and operating results.

The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for lenders and Energen. In addition to operating results, business decisions relating to recapitalization, refinancing, restructuring, acquisition and disposition transactions involving Energen may negatively impact market and rating agency considerations regarding the credit of Energen, and management periodically considers these types of transactions.

Our derivative risk management activities may limit our potential gains and involve other risks that could result in financial losses.

Although we make use of futures, swaps, options, collars and fixed-price contracts to mitigate price risk, fluctuations in future oil, natural gas liquids and natural gas prices could materially affect our financial position, results of operations and cash flows. Furthermore, such risk mitigation activities may cause our financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not been implemented. The changes in the fair market

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value of our derivative contracts as reported in our consolidated statements of income may result in significant non-cash gains or losses.

The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality and that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options, collars and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave us financially exposed to our counterparties and result in material adverse financial consequences to Energen. The adverse effect could be increased if the adverse event was widespread enough to move market prices against our position.

Derivatives reform legislation which has been adopted by the U.S. Congress, or additions to or changes in the legislation, could negatively impact our ability to use derivative instruments as part of our risk management activities.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets. The Commodities Futures Trading Commission (CFTC) and the SEC have adopted, or are in the process of adopting, rules and regulations covering, among other derivative transactions, transactions linked to crude oil and natural gas prices.  We believe Energen’s derivative transactions qualify for the end-user exception which exempts them from certain Dodd-Frank Act swap clearing and exchange-trading requirements pursuant to final regulations adopted by the CFTC and SEC.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require Energen, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we believe we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to mitigate our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as dealers, may change the cost and availability of our future derivative arrangements. The changes in the regulation of swaps may result in certain market participants deciding to curtail or stop engaging in derivative activities. If we reduce our use of derivatives as a result of the Dodd Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and our results of operations.

Our operations depend on the use of third-party facilities, and an interruption of our ability to utilize these facilities may adversely affect our financial condition and results of operations.

Energen delivers to third-party facilities. These facilities include third-party oil and natural gas gathering, transportation, processing and storage facilities. Energen relies on such facilities for access to market for our oil, natural gas liquids and natural gas production. Such facilities are typically limited in number and geographically concentrated. A lack of available capacity on these facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties for Energen. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act, maintenance or otherwise could have an adverse effect on our revenues and results of operations.

The success of our future operations is dependent on our future drilling activities and our ability to economically develop our oil, natural gas liquids and natural gas reserves; and our expectations regarding future drilling and development activities are subject to uncertainties that could significantly alter the occurrence or timing of such activities, as they are expected to be realized over multiple years.

We have identified drilling locations and prospects for future drilling, including development and exploratory drilling activities. Our ability to successfully and economically drill and develop these locations depends on a number of factors, including:

• prices of oil, natural gas liquids and natural gas;

• current laws or regulations or changes in the laws or regulations in the identified and prospective locations;

• the availability and cost of capital;

• seasonal and other weather conditions;

• regulatory approvals;

• negotiation of agreements with third parties;

• access to and availability of required equipment, supplies and personnel and

• drilling results.

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Because of the factors noted above, we cannot provide any guarantee regarding the timing or success of future drilling activities; and our actual drilling activities may materially differ from our current expectations, including potential delays, curtailment or cancellation of anticipated drilling plans and capital expenditures.

Energen has limited control over activities on properties which we do not operate, which could materially reduce our production and revenues.

Energen operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. For properties we do not operate, we have limited ability to control the operation or future development of the properties or the amount of capital expenditures that we are required to fund with respect to them. An operator’s failure to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in our best interest could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others is dependent on a number of factors, including the operator's timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Our dependence on the operator and other working interest owners for these projects and our limited ability to control the operation and future development of these properties could negatively affect the realization of our expected returns on capital in drilling or acquisition activities and could lead to unexpected costs in the future.

Our business could be negatively impacted by security threats, including cybersecurity threats and related disruptions.

We face a variety of security threats, including cybersecurity threats to access sensitive information or render data or systems unusable, threats to the security of our facilities and infrastructure or those of third parties, including processing plants and pipelines, and threats from terrorist acts. Current procedures and controls may not be sufficient to prevent security breaches from occurring, and we could have to implement additional procedures and controls to mitigate the effects of potential breaches and monitor for potential security threats resulting in increased capital and operating costs. In the event of a security breach, losses of sensitive information, critical infrastructure or capabilities essential to our operations could occur and could have a material adverse effect on our reputation, operations, financial position and results of operations. Cybersecurity attacks are sophisticated and prevalent and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, other electronic security breaches that could cause disruptions in critical systems, unauthorized release of confidential information and data corruption. As we rely on our information technology infrastructure to process, transmit and store electronic information critical for the efficient operation of our business and day-to-day operations, such attacks could lead to a material disruption in our business, including the theft, destruction, loss, misappropriation or release of confidential data or other business information, financial losses, loss of business, potential liability and damage our reputation.

ITEM 1B.UNRESOLVED STAFF COMMENTS

None

19

ITEM 2.    PROPERTIES

The corporate headquarters of Energen and Energen Resources are located in leased office space in Birmingham, Alabama. See the discussion under Item 1, Business, for further information related to Energen’s business operations. Information concerning Energen’s production and proved reserves is summarized in the table below and included in Note 21, Oil and Natural Gas Operations (Unaudited), in the Notes to Financial Statements. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the future outlook and expectations for Energen and additional information regarding production, revenue and production costs.

Energen focuses on increasing its production and proved reserves through the development and exploration of onshore North American oil and natural gas properties. Energen maintains district offices in Midland, Texas and Farmington, New Mexico.

The major areas of operations include (1) the Permian Basin and (2) the San Juan Basin as highlighted on the above map. At December 31, 2015, our San Juan Basin properties were classified as held for sale.

The following table sets forth the production volumes, proved reserves and proved reserves-to-production ratio by area:

	Year ended
	December 31, 2015	December 31, 2015	December 31, 2015
	Production Volumes (MBOE)	Proved Reserves (MBOE)	Proved Reserves-to-Production Ratio
Permian Basin	20,664	337,008	16.31 years
San Juan Basin*	3,322	16,930	5.10 years
Other	36	784	21.78 years
Total	24,022	354,722	14.77 years

*San Juan Basin assets were classified as held for sale as of December 31, 2015.

20

The following table sets forth proved reserves by area as of December 31, 2015:

	Oil MBbl	NGL MBbl	Natural Gas MMcf	Total MBOE
Permian Basin	207,593	66,023	380,358	337,008
San Juan Basin*	2,829	5,668	50,588	16,930
Other	269	22	2,958	784
Total	210,691	71,713	433,904	354,722

*San Juan Basin assets were classified as held for sale as of December 31, 2015.

See Note 21, Oil and Natural Gas Operations (Unaudited), in the Notes to Financial Statements for the changes to proved reserves during the years ended December 31, 2015, 2014 and 2013 of oil, natural gas liquids and natural gas.

The following table sets forth proved developed reserves by area as of December 31, 2015:

	Oil MBbl	NGL MBbl	Natural Gas MMcf	Total MBOE
Permian Basin	106,123	30,932	184,095	167,736
San Juan Basin*	1,927	5,420	49,059	15,525
Other	269	22	2,958	784
Total	108,319	36,374	236,112	184,045

*San Juan Basin assets were classified as held for sale as of December 31, 2015.

The following table sets forth proved undeveloped reserves by area as of December 31, 2015:

	Oil MBbl	NGL MBbl	Natural Gas MMcf	Total MBOE
Permian Basin	101,470	35,091	196,263	169,272
San Juan Basin*	902	248	1,529	1,405
Total	102,372	35,339	197,792	170,677

*San Juan Basin assets were classified as held for sale as of December 31, 2015.

The following table sets forth the reconciliation of proved undeveloped reserves:

Year ended December 31, 2015	Total MMBOE
Balance at beginning of period	108.2
Undeveloped reserves transferred to developed reserves	(17.4)
Revisions	(23.5)
Extensions and discoveries	103.4
Balance at end of period	170.7

Proved undeveloped reserves transferred to proved developed reserves reflect capital expenditures of approximately $232 million during the year ended December 31, 2015 in development of previously proved undeveloped reserves. Proved undeveloped reserves additions included proved undeveloped reserve locations one offset away from producing wells and proved undeveloped reserve locations that are more than one offset away from producing wells using reliable technology and where our geologic interpretation and experience indicate the reservoirs are continuous across those locations. The technologies associated with these additions to proved reserve estimates included analysis of well production data, geophysical data, wireline data, core data and interpretation of zonal analysis. Negative revisions are due to 11.9 MMBOE related to changes in year end pricing, 8.2 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period and 3.3 MMBOE of Wolfcamp reserves due to interference caused by our wellbore placement geometry.

21

Estimated proved reserves as of December 31, 2015 are based upon studies for each of our properties prepared by Company engineers and audited by Ryder Scott Company, L.P. (Ryder Scott) and Hickman McClaine and Associates, Inc. (Hickman McClaine), independent oil and gas reservoir engineers. Calculations were prepared using geological and engineering methods widely used and referred to by professionals in the industry and in accordance with SEC guidelines.

A Senior Vice President at Ryder Scott is the technical person primarily responsible for overseeing the audit of the reserves. The Senior Vice President has a Bachelor of Science degree in Mechanical Engineering and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. He has been employed by Ryder Scott since 1982 and also serves as chief technical advisor of unconventional reserves evaluation. A Petroleum Consultant at Hickman McClaine is the technical person primarily responsible for overseeing the audit of the reserves. He has a Bachelor of Science degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. He has been employed by Hickman McClaine since 1983. Energen Resources’s Vice President of Acquisitions and Reservoir Engineering is the technical person primarily responsible for overseeing reserves on behalf of Energen. His background includes a Bachelor of Science degree in Mechanical Engineering and membership in the Society of Petroleum Engineers. He is a registered Professional Engineer in the State of Alabama with more than 30-years experience evaluating oil and natural gas properties and estimating reserves.

Energen relies upon certain internal controls when preparing its reserve estimations. These internal controls include review by the reservoir engineering managers to ensure the correct reserve methodology has been applied for each specific property and that the reserves are properly categorized in accordance with SEC guidelines. The reservoir engineering managers also affirm the accuracy of the data used in the reserve and associated rate forecast, provide a review of the procedures used to input pricing data and provide a review of the working and net revenue interest factors to ensure that factors are adequately reflected in the engineering analysis.

Net production forecasts are compared to historical sales volumes to check for reasonableness, and operating costs and severance taxes calculated in the reserve report are compared to historical accounting data to help ensure proper cost estimates are used. A reserve table is generated comparing the previous year’s reserves to current year reserve estimates to determine variances. This table is reviewed by the Vice President of Acquisitions and Reservoir Engineering and the Chief Operating Officer of Energen Resources. Revisions and additions are investigated and explained.

Reserve estimates of proved reserves are sent to independent reservoir engineers for audit and verification. For 2015, approximately 99 percent of all proved reserves were audited by the independent reservoir engineers which audit engineering procedures, check the reserve estimates for reasonableness and check that the reserves are properly classified.

The following table sets forth the standard pressure base in pounds-force per square inch absolute (psia) for each state in which Energen has wells:

Texas	14.65 psia
New Mexico	15.025 psia

The following table sets forth the total net productive oil and natural gas wells by area as of December 31, 2015, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

	Gross Wells	Net Wells	Net Developed Acreage	Net Undeveloped Acreage
Permian Basin	5,327	3,483	216,515	80,242
San Juan Basin*	492	439	82,955	49,398
Other	80	6	20,108	6,576
Total	5,899	3,928	319,578	136,216

*San Juan Basin assets were classified as held for sale as of December 31, 2015.

22

The following table sets forth expiration dates for gross and net undeveloped acreage at year end as of December 31, 2015:

	Years ending December 31,
	2016		2017		2018		Thereafter
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian	33,617	22,986	26,596	16,189	13,954	15,420	29,520	25,647
San Juan/other*	12,309	4,992	16,712	9,179	12,352	11,930	40,994	29,873
Total	45,926	27,978	43,308	25,368	26,306	27,350	70,514	55,520

*Other includes a total of 14,694 gross (6,576 net) acreage principally located in Alabama, Wyoming, Kentucky, Louisiana and Texas, where Energen does not currently have plans for development.

In the ordinary course of business based on our evaluation of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future.

At December 31, 2015, Energen had approximately 354.7 MMBOE total proved reserves which included 170.7 MMBOE of proved undeveloped reserves. We had approximately 24.7 MMBOE or 14.4 percent of our proved undeveloped reserves on leased acreage which is not held by production. The continuous development provisions of these leases extend the primary terms upon the satisfaction of certain conditions. These provisions generally require at least one well be drilled on such leases prior to the expiration of the primary term and that subsequent wells be drilled within a time period that is specific to each lease but ranges from 60 days to 180 days. Once a lease is fully developed, it remains in effect as long as production is maintained from the lease. Our drilling plans provide for the development of these proved undeveloped reserves prior to the expiration of the initial primary term or under the extended primary term as provided for under the continuous development provisions of our lease agreements.

Energen sells oil, natural gas liquids, and natural gas under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity (firm volumes). Energen is contractually committed to deliver approximately 0.9 Bcf (net) of natural gas from the San Juan Basin through March 2016. We expect to fulfill delivery commitments through production of existing proved reserves.

ITEM 3.    LEGAL PROCEEDINGS

Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Various pending or threatened legal proceedings are in progress currently. See Note 12, Commitments and Contingencies, in the Notes to Financial Statements for further discussion with respect to legal proceedings.

ITEM 4.    MINE SAFETY DISCLOSURES

None

23

EXECUTIVE OFFICERS OF THE REGISTRANT

Name	Age	Position (1)
James T. McManus, II	57	Chairman, Chief Executive Officer and President of Energen (2)
Charles W. Porter, Jr.	51	Vice President, Chief Financial Officer and Treasurer of Energen (3)
John S. Richardson	58	President and Chief Operating Officer of Energen Resources (4)
J. David Woodruff, Jr.	59	Vice President, General Counsel and Secretary of Energen (5)
David A. Godsey	61	Senior Vice President – Exploration and Geology of Energen Resources (6)
Russell E. Lynch, Jr.	42	Vice President and Controller of Energen (7)

Notes:    

(1) All executive officers of Energen have been employed by Energen or a subsidiary for the past five years except for Mr. Godsey. Officers serve at the pleasure of the Board of Directors.

(2) Mr. McManus has been employed by the Company in various capacities since 1986. He was elected Executive Vice President and Chief Operating Officer of Energen Resources in October 1995 and President of Energen Resources in April 1997. He was elected President and Chief Operating Officer of Energen effective January 1, 2006 and Chief Executive Officer of Energen and each of its subsidiaries effective July 1, 2007. He was elected Chairman of the Board of Energen and each of its subsidiaries effective January 1, 2008. Mr. McManus serves as a Director of Energen and each of its subsidiaries.

(3) Mr. Porter has been employed by the Company in various financial capacities since 1989. He was elected Controller of Energen Resources in 1998. In 2001, he was elected Vice President – Finance of Energen Resources. He was elected Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries effective January 1, 2007.

(4) Mr. Richardson has been employed by the Company in various capacities since 1985. He was elected Vice President – Acquisitions and Engineering of Energen Resources in 1997. He was elected Executive Vice President and Chief Operating Officer of Energen Resources effective January 1, 2006. He was elected President and Chief Operating Officer of Energen Resources effective January 23, 2008.

(5) Mr. Woodruff has been employed by the Company in various capacities since 1986. He was elected Vice President-Legal and Assistant Secretary of Energen and each of its subsidiaries in April 1991. He was elected General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2003. He also served as Vice President –Corporate Development of Energen from 1995 to 2010.

(6) Mr. Godsey was employed by the Company in December 2012 as Senior Vice President – Exploration and Geology of Energen Resources. He served as Geoscience Manager Permian Basin for Cheasapeake Energy from April 2003 to December 2012. He also served from December 1999 to April 2003 as Project Geologist for EOG Resources, Inc.

(7) Mr. Lynch has been employed by the Company in various capacities since 2001. He was elected Vice President and Controller of Energen effective January 1, 2009. He was elected Vice President and Controller of Energen Resources effective January 22, 2016.

24

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Quarterly Market Prices and Dividends Paid Per Share
Quarter ended	High	Low	Close	Dividends Paid
March 31, 2014	$83.65	$65.35	$80.81	$0.15
June 30, 2014	$90.66	$76.42	$88.88	$0.15
September 30, 2014	$90.50	$71.24	$72.24	$0.15
December 31, 2014	$73.21	$53.78	$63.76	$0.02
March 31, 2015	$71.75	$57.71	$66.00	$0.02
June 30, 2015	$77.12	$65.53	$68.30	$0.02
September 30, 2015	$69.11	$43.75	$49.86	$0.02
December 31, 2015	$61.98	$39.99	$40.99	$0.02

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On January 25, 2016, there were 4,383 holders of record of Energen common stock. In February 2016, we announced the discontinuance of dividend payments. Accordingly, we do not expect to pay cash dividends on Energen common stock in 2016. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors. 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.

The following table summarizes information concerning purchases of equity securities by the issuer:

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares that May Yet Be Purchased Under the Plans**
October 1, 2015 - October 31, 2015	545	*	$	59.66	—	3,373,161
November 1, 2015 - November 30, 2015	—		—		—	3,373,161
December 1, 2015 - December 31, 2015	5,569	*	48.40		—	3,373,161
Total	6,114		$	49.40	—	3,373,161

*Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans.

**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.

25

PERFORMANCE GRAPH

Energen Corporation — Comparison of Five-Year Cumulative Shareholder Returns

This graph compares the total shareholder returns of Energen, the Standard & Poor’s Composite Stock Index (S&P 500) and the Standard & Poor’s Supercomposite Oil & Gas Exploration & Production Index (S15OILP). The graph assumes $100 invested at the per-share closing price of the common stock on the New York Exchange Composite Tape on December 31, 2010, in the Company and each of the indices. Total shareholder return includes reinvested dividends.

As of December 31,	2010		2011		2012		2013		2014		2015
S&P 500	$	100	$	102	$	118	$	157	$	178	$	181
Energen	$	100	$	105	$	96	$	152	$	138	$	89
S15OILP	$	100	$	92	$	94	$	121	$	106	$	69

26

ITEM 6.    SELECTED FINANCIAL DATA

The selected financial data as set forth below should be read in conjunction with the consolidated financial statements and the Notes to Financial Statements included in this Form 10-K.

SELECTED FINANCIAL AND COMMON STOCK DATA

Years ended December 31, (dollars in thousands, except per share amounts)	2015			2014		2013		2012		2011
INCOME STATEMENT
Total revenues	$	878,554		$	1,679,213	$	1,206,293	$	1,090,948	$	834,700
Income from continuing operations	$	(945,731	)	$	99,643	$	141,881	$	204,621	$	174,686
Net income	$	(945,731	)	$	568,032	$	204,554	$	253,562	$	259,624
Diluted earnings per average common share from continuing operations	$	(12.43	)	$	1.36	$	1.96	$	2.83	$	2.42
Diluted earnings per average common share	$	(12.43	)	$	7.75	$	2.82	$	3.51	$	3.59
BALANCE SHEET
Total property, plant and equipment, net	$	4,350,690		$	5,199,137	$	5,118,088	$	4,698,951	$	3,807,305
Total assets	$	4,613,693		$	6,138,258	$	6,622,212	$	6,175,890	$	5,237,416
Long-term debt	$	776,087		$	1,038,563	$	1,093,541	$	903,500	$	904,454
Total shareholders’ equity	$	2,895,860		$	3,414,604	$	2,858,019	$	2,676,690	$	2,432,163
COMMON STOCK DATA
Cash dividends paid per common share	$	0.08		$	0.47	$	0.58	$	0.56	$	0.54
Diluted average common shares outstanding (000)	76,078			73,275		72,471		72,316		72,332
Price range:
High	$	77.12		$	90.66	$	89.92	$	58.24	$	65.44
Low	$	39.99		$	53.78	$	44.46	$	40.13	$	37.22
Close	$	40.99		$	63.76	$	70.75	$	45.09	$	50.00

27

SELECTED BUSINESS DATA

Years ended December 31, (dollars in thousands, except per unit data)	2015			2014		2013			2012			2011
Oil, natural gas liquids and natural gas sales from continuing operations
Oil	$	631,663		$	988,868	$	961,055		$	766,105		$	570,413
Natural gas liquids	48,856			110,918		91,407			81,313			101,818
Natural gas	82,742			244,408		203,855			159,377			210,813
Total	$	763,261		$	1,344,194	$	1,256,317		$	1,006,795		$	883,044
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	(242,227	)	$	271,200	$	(43,261	)	$	58,786		$	(37,473	)
Natural gas liquids	—			287		(652		)	479			(114		)
Natural gas	(39,525		)	43,958		(3,919		)	(515		)	—
Total	$	(281,752	)	$	315,445	$	(47,832	)	$	58,750		$	(37,587	)
Closed gains (losses) on derivative instruments
Oil	$	346,404		$	4,377	$	(52,694	)	$	(35,954	)	$	(67,205	)
Natural gas liquids	—			6,218		10,795			4,146			(14,240		)
Natural gas	50,641			8,979		39,707			57,211			70,688
Total	$	397,045		$	19,574	$	(2,192	)	$	25,403		$	(10,757	)
Total revenues	$	878,554		$	1,679,213	$	1,206,293		$	1,090,948		$	834,700
Production volumes from continuing operations
Oil (MBbl)	14,023			11,814		10,364			8,749			6,300
Natural gas liquids (MMgal)	170.7			172.3		135.8			108.1			91.4
Natural gas (MMcf)	35,604			58,602		58,104			59,166			54,132
Production volumes from continuing operations (MBOE)	24,022			25,684		23,281			21,183			17,499
Total production volumes (MBOE)	24,022			25,849		25,362			24,066			20,448
Proved reserves
Oil (MBbl)	210,691			181,227		164,870			155,348			129,578
Natural gas liquids (MBbl)	71,713			73,463		63,011			56,155			53,957
Natural gas (MMcf))	433,904			707,926		719,725			809,128			957,368
Total (MBOE)	354,722			372,678		347,835			346,359			343,099
Costs per BOE from continuing operations
Oil, natural gas liquids and natural gas production expenses	$	9.51		$	10.68	$	11.06		$	9.55		$	9.11
Production and ad valorem taxes	$	2.39		$	3.97	$	4.04		$	3.58		$	3.82
Depreciation, depletion and amortization	$	24.72		$	21.36	$	19.45		$	16.17		$	12.19
Exploration expense	$	0.62		$	1.09	$	0.60		$	0.62		$	0.74
General and administrative expense	$	6.21		$	4.75	$	4.89		$	3.71		$	4.41
Net capital expenditures	$	1,040,610		$	1,372,510	$	1,104,745		$	1,291,211		$	1,115,452

28

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW OF BUSINESS

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 primarily in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources). At December 31, 2015, our remaining San Juan Basin properties were classified as held for sale and, subsequent to year-end, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale.

Energen is focused on increasing its oil, natural gas liquids and natural gas production and proved reserves largely through active development and/or exploratory programs in the Permian Basin. The Company seeks to expand its footprint primarily through acquisitions of proved properties and unproved leasehold within areas of existing operations. All oil, natural gas liquids and natural gas production is sold to third parties. Energen operates properties for its own interest and that of its joint interest owners. This role includes overall project management and day-to-day decision-making relative to project operations.

FINANCIAL AND OPERATING PERFORMANCE

Overview of Year-to-Date 2015 Results and Activities

During the year ended December 31, 2015 as compared to the same period in the prior year, we:

• expanded development and exploratory activities in the Permian Basin, increasing production by 19.5 percent or 3,366 MBOE;

• experienced a significant decline in commodity prices;

• recognized non-cash impairments on certain oil properties in the Delaware Basin and Central Basin Platform of the Permian Basin of $1,092.2 million pre-tax;

• recognized non-cash impairments on certain held for sale properties in the San Juan Basin of $133.1 million pre-tax (see Note 15, Acquisition and Disposition of Properties, in the Notes to Financial Statements);

• recognized unproved leasehold writedowns on San Juan Basin properties of $37.9 million pre-tax;

• recognized unproved leasehold writedowns on Permian Basin oil properties of $29.2 million pre-tax;

• issued 5,700,000 additional shares of common stock through a public equity offering receiving net proceeds of approximately $398.6 million and

• completed the sale of the majority of our natural gas assets in the San Juan Basin in New Mexico and Colorado for an aggregate purchase price of approximately $395 million on March 31, 2015.

Year ended December 31, 2015 vs year ended December 31, 2014

Energen’s net loss for the year ended December 31, 2015 totaled $945.7 million ($12.43 per diluted share) compared to the year ended December 31, 2014 net income of $568.0 million ($7.75 per diluted share). Energen’s loss from continuing operations totaled $945.7 million ($12.43 per diluted share) in 2015 as compared with income from continuing operations of $99.6 million ($1.36 per diluted share) in 2014. Energen did not have discontinued operations for the current year. Income from discontinued operations was $468.4 million ($6.39 per diluted share) in 2014 largely due to the sale of Alagasco. This change in income (loss) from continuing operations was primarily the result of:

• lower realized oil, natural gas liquids and natural gas commodity prices (approximately $428 million after-tax);

• year-over-year after-tax $382.9 million loss on open derivatives (resulting from an after-tax $181.3 million non-cash loss on open derivatives for 2015 and an after-tax $201.8 million non-cash gain on open derivatives for 2014);

• non-cash impairments on certain Permian Basin oil properties in the Delaware Basin (approximately $388.3 million after-tax) and in the Central Basin Platform (approximately $310.1 million after-tax);

• non-cash impairments on certain held for sale properties in the San Juan Basin (approximately $85.1 million after-tax);

• decreased natural gas and natural gas liquids production volumes (approximately $62 million after-tax);

• higher depreciation, depletion and amortization (DD&A) expense (approximately $29 million after-tax);

• unproved leasehold writedowns on San Juan Basin properties (approximately $24.3 million after-tax);

• additional unproved leasehold writedowns primarily on Permian Basin properties in the Delaware Basin (approximately $18.7 million after-tax);

• increased general and administrative expense (approximately $17 million after-tax) and

• increased interest expense (approximately $3 million after-tax)

29

partially offset by:

• gain on closed derivatives (approximately $242 million after-tax);

• non-cash impairments in 2014 on certain gas properties in the San Juan Basin (approximately $143.7 million after-tax);

• higher oil production volumes (approximately $118 million after-tax);

• non-cash impairments in 2014 on certain oil properties in the Permian Basin (approximately $70.9 million after-tax);

• unproved leasehold writedowns in 2014 on Permian Basin oil properties (approximately $39 million after-tax) and unproved leasehold writedowns on San Juan Basin properties (approximately $3.7 million after-tax);

• decreased oil, natural gas liquids and natural gas production expense (approximately $29 million after-tax);

• lower production and ad valorem taxes (approximately $29 million after-tax);

• gain on sale of the majority of our natural gas assets in the San Juan Basin (approximately $17.3 million after tax) and

• lower exploration expense (approximately $8 million after-tax).

Year ended December 31, 2014 vs year ended December 31, 2013

For the year ended December 31, 2014, Energen’s net income totaled $568.0 million ($7.75 per diluted share) as compared to net income of $204.6 million ($2.82 per diluted share) in 2013. Energen’s income from continuing operations totaled $99.6 million ($1.36 per diluted) in 2014 as compared with $141.9 million ($1.96 per diluted) in 2013. Income from discontinued operations for 2014 was $468.4 million ($6.39 per diluted share) as compared with income of $62.7 million ($0.86 per diluted share) from 2013 largely due to the sale of Alagasco. This decrease in income from continuing operations was primarily the result of:

• non-cash impairments on certain gas properties in the San Juan Basin (approximately $143.7 million after-tax);

• non-cash impairments on certain oil properties in the Permian Basin (approximately $70.9 million after-tax);

• unproved leasehold writedowns primarily on Permian Basin oil properties (approximately $39 million after-tax);

• lower realized oil and natural gas liquids commodity prices (approximately $72 million after-tax);

• higher depreciation, depletion and amortization (DD&A) expense (approximately $62 million after-tax);

• higher oil, natural gas liquids and natural gas production expense (approximately $11 million after-tax);

• higher exploration expense (approximately $9 million after-tax);

• increased general and administrative expense (approximately $5 million after-tax) and

• higher production and ad valorem taxes (approximately $5 million after-tax)

partially offset by:

• year-over-year after-tax $232.4 million gain on open derivatives (resulting from an after-tax $201.8 million non-cash gain on open derivatives for 2014 and an after-tax $30.6 million non-cash loss on open derivatives for 2013);

• higher oil, natural gas liquids and natural gas production volumes (approximately $104 million after-tax);

• higher realized natural gas commodity prices (approximately $25 million after-tax) and

• gain on closed derivatives (approximately $14 million after-tax).

Operating Income (Loss)

Operating loss in 2015 totaled $1,437.9 million. Operating income in 2014 and 2013 totaled $177.0 million and $252.1 million, respectively. Reduced operating income for 2015 is primarily due to significantly lower commodity prices, asset impairment charges, non-cash mark-to-market decrease in open derivatives, decreased natural gas and natural gas liquids production and higher DD&A expense partially offset by non-cash mark-to-market increase in closed derivatives, higher oil production, lower oil, natural gas liquids and natural gas production expense, decreased production and ad valorem taxes and a gain on the sale of certain natural gas San Juan Basin assets. In 2014, lower operating income was largely due to non-cash impairments on certain properties in the San Juan and Permian basins, leasehold writedowns in the Permian Basin, lower oil and natural gas liquids commodity prices and higher DD&A expense. Partially offsetting these decreases in operating income was the non-cash mark-to-market income in open and closed derivatives, higher production and increased natural gas commodity prices.

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Results of Operations

The following table summarizes information regarding our production and operating data from continuing operations.

Years ended December 31, (in thousands, except sales price and per unit data)	2015			2014		2013
Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
Oil	$	631,663		$	988,868	$	961,055
Natural gas liquids	48,856			110,918		91,407
Natural gas	82,742			244,408		203,855
Total	$	763,261		$	1,344,194	$	1,256,317
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	(242,227	)	$	271,200	$	(43,261	)
Natural gas liquids	—			287		(652		)
Natural gas	(39,525		)	43,958		(3,919		)
Total	$	(281,752	)	$	315,445	$	(47,832	)
Closed gains (losses) on derivative instruments
Oil	$	346,404		$	4,377	$	(52,694	)
Natural gas liquids	—			6,218		10,795
Natural gas	50,641			8,979		39,707
Total	$	397,045		$	19,574	$	(2,192	)
Total revenues	$	878,554		$	1,679,213	$	1,206,293
Production volumes
Oil (MBbl)	14,023			11,814		10,364
Natural gas liquids (MMgal)	170.7			172.3		135.8
Natural gas (MMcf)	35,604			58,602		58,104
Total production volumes (MBOE)	24,022			25,684		23,281
Average daily production volumes
Oil (MBbl)	38.4			32.4		28.4
Natural gas liquids (MMgal)	0.5			0.5		0.4
Natural gas (MMcf)	97.5			160.6		159.2
Total average daily production volumes (MBOE/d)	65.8			70.4		63.8
Permian Basin - Spraberry (Trend Area) Field production volumes (included in production volumes above)*
Oil (MBbl)	2,143			2,463		2,822
Natural gas liquids (MMgal)	30.9			44.5		38.5
Natural gas (MMcf)	4,313			5,729		4,836
Total production volumes (MBOE)	3,599			4,477		4,544
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)	$	69.75		$	84.07	$	87.65
Natural gas liquids (per gallon)	$	0.29		$	0.68	$	0.75
Natural gas (per Mcf)	$	3.75		$	4.32	$	4.19
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)	$	45.04		$	83.70	$	92.73
Natural gas liquids (per gallon)	$	0.29		$	0.64	$	0.67

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Natural gas (per Mcf)	$	2.32	$	4.17	$	3.51
Costs per BOE
Oil, natural gas liquids and natural gas production expenses	$	9.51	$	10.68	$	11.06
Production and ad valorem taxes	$	2.39	$	3.97	$	4.04
Depreciation, depletion and amortization	$	24.72	$	21.36	$	19.45
Exploration expense	$	0.62	$	1.09	$	0.60
General and administrative	$	6.21	$	4.75	$	4.89

*The Spraberry (Trend Area) Field in the Permian Basin contained 15 percent or more of Energen’s total proved reserves as of December 31, 2015.

Revenues: Our revenues fluctuate primarily as a result of realized commodity prices, production volumes, the value of our derivative contracts and any recognized gains or losses on the sales of assets. Our revenues are predominantly derived from the sale of oil, natural gas liquids and natural gas.

For the year ended December 31, 2015, commodity sales decreased $580.9 million or 43.2 percent from the same period of 2014. Particular factors impacting commodity sales for 2015 include the following:

• Oil volumes in 2015 increased 18.7 percent to 14,023 MBbl as new drilling in the horizontal Wolfcamp in the Midland and Delaware basins more than offset declines in the Wolfberry in the Midland Basin, 3rd Bone Spring in the Delaware Basin and the Central Basin Platform.

• Average realized oil prices fell 46.2 percent to $45.04 per barrel during 2015.

• Natural gas liquids production for 2015 declined 0.9 percent to 170.7 MMgal due to the sale of the majority of our natural gas assets in the San Juan Basin.

• Average realized natural gas liquids prices decreased 54.7 percent to an average price of $0.29 per gallon during 2015.

• Natural gas production decreased 39.2 percent to 35.6 Bcf in 2015 due to the sale of natural gas assets in the San Juan Basin, normal declines in the San Juan Basin and pipeline curtailments in the Permian Basin partially offset by accelerated completions and new well performance in the Permian Basin.

• Average realized natural gas prices decreased 44.4 percent to $2.32 per Mcf during 2015.

• Production from continuing operations fell 6.5 percent to 24 MMBOE during 2015.

For the year ended December 31, 2014, oil, natural gas liquids and natural gas sales increased $87.9 million or 7 percent from the same period of 2013. Particular factors impacting commodity sales for 2014 include the following:

• Oil volumes rose 14 percent to 11,814 MBbl during 2014 as new drilling in the horizontal Wolfcamp in the Midland and Delaware basins, along with continued Wolfberry and Bone Spring drilling, more than offset declines in the mature Central Basin Platform.

• Average realized oil prices in 2014 fell 9.7 percent to $83.70 per barrel and included the impact of wider oil basis differentials.

• Production of natural gas liquids increased 26.9 percent to 172.3 MMgal in 2014 largely due to higher natural gas volumes related to the current drilling program and higher natural gas liquids recovery.

• Average realized natural gas liquids prices fell 4.5 percent to an average price of $0.64 per gallon during 2014.

• Natural gas production increased 0.9 percent to 58.6 Bcf in 2014 as increased production in the Permian Basin was partially offset by declining San Juan Basin production.

• Average realized natural gas prices in 2014 rose 18.8 percent to $4.17 per Mcf.

• Production from continuing operations rose 10.3 percent to 25.7 MMBOE during 2014.

Realized prices exclude the effects of derivative instruments.

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Oil, natural gas liquids and natural gas production expense: The following table provides the components of our oil, natural gas liquids and natural gas production expenses:

Years ended December 31, (in thousands, except per unit data)	2015		2014		2013
Lease operating expenses	$	140,010	$	140,413	$	129,326
Workover and repair costs	68,428		91,629		84,102
Marketing and transportation	19,942		42,390		44,010
Total oil, natural gas liquids and natural gas production expense	$	228,380	$	274,432	$	257,438
Oil, natural gas liquids and natural gas production expense per BOE	$	9.51	$	10.68	$	11.06

Energen had oil, natural gas liquids and natural gas production expense of $228.4 million, $274.4 million and $257.4 million during the years ended December 31, 2015, 2014 and 2013, respectively. Lease operating expense may be positively or negatively impacted by property acquisitions and dispositions and also generally reflects year-over-year increases in the number of active wells resulting from Energen’s ongoing development and exploratory activities. Overall lease operating expense was positively impacted in the current year by the sale of the San Juan Basin.

• In 2015, lease operating expense decreased $0.4 million primarily due to lower other operations and maintenance expense (approximately $8 million) and decreased electrical costs (approximately $3.6 million) largely offset by additional equipment rental costs (approximately $4.5 million), higher labor costs (approximately $2 million), increased non-operated costs (approximately $1.9 million), increased gathering costs (approximately $1.2 million), higher environmental compliance costs (approximately $1.1 million) and higher water disposal costs (approximately $1.1 million).

• In 2014, lease operating expense increased $11.1 million primarily due to increased chemical and treatment costs (approximately $2.7 million), higher producing overhead costs (approximately $2.2 million), increased gathering costs (approximately $2.2 million), additional other operations and maintenance expense (approximately $1.9 million), increased labor costs (approximately $1.7 million), higher electrical costs (approximately $1.7 million) and increased non-operated costs (approximately $1.6 million) partially offset by decreased environmental compliance costs (approximately $2.9 million) and lower water disposal costs (approximately $1 million).

On a per unit basis, the average lease operating expense for 2015, 2014 and 2013 was $5.83 per BOE, $5.46 per BOE and $5.56 per BOE, respectively.

Workover and repair costs decreased approximately $23.2 million in 2015 and increased $7.5 million in 2014. Workover and repair costs in 2015 were lower primarily due to lower incidence of offset well stimulation interference and lower electrical costs. In 2014, these expenses were primarily related to workovers in the west Texas Permian Basin associated with pump and tubing replacements. Additional expenses were incurred associated with the protective preparation of producing wells for offset operations. Also, the increased number of producing wells resulting from our ongoing drilling program creates a higher level of base load workover and repair expense.

In the years ended December 31, 2015 and 2014, marketing and transportation costs decreased $22.4 million and $1.6 million, respectively. The decline in 2015 was largely due to lower natural gas volumes as a result of the sale of certain San Juan Basin natural gas assets.

Production and ad valorem taxes: Production and ad valorem taxes were $57.4 million ($2.39 per BOE), $102.1 million ($3.97 per BOE) and $94.1 million ($4.04 per BOE) during the years ended December 31, 2015, 2014 and 2013, respectively. In 2015, production-related taxes were $37.1 million lower as decreased commodity market prices and lower net production volumes contributed approximately $32.2 million and $4.9 million to the decrease in production taxes, respectively. In 2014, production-related taxes were $7.8 million higher as increased commodity production volumes contributed approximately $7 million to the increase in production taxes combined with increased natural gas commodity market prices, largely offset by lower gas and natural gas liquids commodity market prices, which contributed approximately $0.8 million to the increase. Commodity market prices exclude the effects of derivative instruments for purposes of determining production taxes. Decreased ad valorem taxes of $7.6 million in 2015 were largely driven by the factor adjusted price impact on our Texas oil and natural gas properties. Increased ad valorem taxes of $0.2 million in 2014 were primarily driven by the increase in the number of active wells.

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Depreciation, depletion and amortization: DD&A expense increased $45.2 million in 2015 and $95.7 million in 2014. The average DD&A rates were $24.72 per BOE in 2015, $21.36 per BOE in 2014 and $19.45 per BOE in 2013. The increase in the 2015 and 2014 per unit DD&A rates, which contributed approximately $79.3 million and $47.5 million, respectively, to the increase in DD&A expense, was primarily due to higher rates resulting from an increase in development costs and the impact of year end reserve revisions driven by lower commodity prices. Lower net production volumes reduced DD&A expense approximately $35.2 million in 2015. Increased production volumes contributed approximately $46.4 million to the increase in DD&A expense in 2014.

Asset impairment: Non-cash impairment writedowns are reflected in asset impairment on the consolidated income statements.

Permian Basin: For 2015, Energen recognized non-cash impairment writedowns on certain properties in the Permian Basin of $1,092.2 million to adjust the carrying amount of these properties to their fair value. We estimate future discounted cash flows in determining fair value using commodity assumptions, which are based on the commodity price curve for five years and then escalated at 3 percent through our assumed price cap. During the fourth quarter of 2015, Energen recognized non-cash impairment writedowns of $646.1 million due to commodity price declines and the related impact to our drilling plans. Our commodity price assumptions declined over the third quarter by approximately 12 percent for oil and 6 percent for natural gas in comparable periods. During the third quarter of 2015, Energen recognized non-cash impairment writedowns of $390.2 million due to commodity price declines. Our commodity price assumptions declined over the second quarter by approximately 19 percent for oil and 12 percent for natural gas in comparable periods. During the second quarter of 2015, Energen recognized non-cash impairment writedowns on certain properties in the Central Basin Platform of $51.5 million. Estimated future cash flows were revised due to the receipt of an unsolicited offer for these properties. During the first quarter of 2015, Energen recognized a non-cash impairment writedown of $4.3 million.

During the third and fourth quarters of 2014, Energen recognized non-cash impairment writedowns on certain Permian Basin properties in the Midland Basin of $25.8 million and in the Delaware Basin of $90.6 million, respectively, to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows.

Energen recognized unproved leasehold writedowns primarily on Permian Basin oil properties in the Delaware Basin of $29.2 million in 2015. During 2014, Energen recognized unproved leasehold writedowns of $64.4 million. These unproved leasehold writedowns include $55.1 million of leasehold expirations.

San Juan Basin: Energen recognized non-cash impairment writedowns on properties in the San Juan Basin of $133.1 million during the fourth quarter of 2015 to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. These remaining properties were designated as held for sale as of December 31, 2015. At December 31, 2015, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 16,930 MBOE.

During the third and fourth quarters of 2014, non-cash impairment writedowns of $142.2 million and $88.1 million, respectively, were recognized by Energen on certain natural gas properties in the San Juan Basin to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows in the third quarter and based on direct market data in the fourth quarter as these properties were designated as held for sale as of December 31, 2014. At December 31, 2014, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 69,038 MBOE.

During 2015 and 2014, Energen recognized unproved leasehold writedowns San Juan Basin properties of $37.9 million and $5.8 million, respectively.

Exploration: The following table provides details of our exploration expense:

Years ended December 31, (in thousands, except per unit data)	2015		2014		2013
Geological and geophysical	$	7,316	$	8,800	$	3,141
Dry hole costs	7,097		9,325		2,101
Delay rentals and other	465		9,965		8,794
Total exploration expense	$	14,878	$	28,090	$	14,036
Total exploration expense per BOE	$	0.62	$	1.09	$	0.60

Exploration expense decreased $13.2 million in 2015 primarily due to lower delay rentals and dry hole costs. Delay rentals are lower in the current year largely due to the sale of certain San Juan Basin properties. Exploration expense rose $14.1 million during 2014 primarily due to higher dry hole costs, increased seismic costs and additional delay rentals.

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General and administrative: The following table provides details of our general and administrative (G&A) expense:

Years ended December 31, (in thousands, except per unit data)	2015		2014		2013
General and administrative	$	30,578	$	25,519	$	25,310
Benefit and performance-based compensation costs	64,805		45,215		45,954
Labor costs	53,749		51,318		42,557
Total general and administrative expense	$	149,132	$	122,052	$	113,821
Total general and administrative expense per BOE	$	6.21	$	4.75	$	4.89

In 2015, total G&A expense rose $27.1 million primarily due to increased costs related to Energen’s benefit and performance-based compensation plans (approximately $19.6 million), increased legal expenses (approximately $5.4 million) and higher labor costs (approximately $2.4 million). Total G&A expense rose $8.2 million in 2014 largely due to increased labor costs (approximately $8.8 million), higher professional services (approximately $1.6 million) and increased recruiting expenses (approximately $1.5 million) partially offset by decreased costs from Energen’s benefit and performance-based compensation plans (approximately $0.7 million) and decreased legal expenses (approximately $1.7 million). Included in costs from the benefit and performance-based compensation plans were pension costs of $31.3 million (including settlement expense of $29.8 million), $18.9 million (including settlement expense of $4.1 million) and $11.8 million (including settlement expense of $0.2 million) for the years ended December 31, 2015, 2014 and 2013, respectively.

(Gain) loss on sale of assets and other, net: On March 31, 2015, Energen completed the sale of the majority of our 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 held for sale properties totaled 69,038 MBOE.

Interest expense: Interest expense rose $5.3 million during 2015 largely due to the classification of interest expense associated with debt required to be extinguished as discontinued operations in the prior year partially offset by the prior year write-off of debt issuance costs associated with the $600 million Senior Term Loans. Interest expense decreased $2 million during 2014 largely due to the December 2013 repayment of the Senior Term Loans of $300 million issued in November 2011 and the October 2013 repayment of $50 million of 5 percent Notes, partially offset by the write-off of debt issuance costs of $2.7 million associated with the $600 million Senior Term Loans issued in December 2013, interest expense incurred from our credit facility entered into on September 2, 2014 and $0.4 million associated with the October 2012 syndicated credit facilities. The interest expense associated with the $600 million Senior Term Loans and the October 2012 syndicated credit facilities are reflected in discontinued operations for 2014 and 2013. In conjunction with the sale of Alagasco, the $600 million Senior Term Loans and the syndicated credit facilities were repaid in September 2014. The average daily outstanding balance under credit facilities was $358.9 million in 2015. The average daily outstanding balance under credit facilities was $482.2 million in 2014 as compared to $772 million in 2013.

Income tax expense: Income tax expense decreased in 2015 and 2014 largely due to lower pre-tax income. In addition, Energen recognized a $1.2 million and an $8.4 million income tax benefit during the 4th quarter of 2015 and 2014, respectively, as a result of re-measuring its state deferred tax liabilities. This re-measurement reflected the state apportionment changes related to certain San Juan Basin properties designated as held for sale as of December 31, 2015 and 2014. On June 15, 2015, a Texas tax bill was signed into law which reduces the Texas Franchise Tax (Margin Tax) rate from 1 percent to 0.75 percent for taxpayers not engaged in retail or wholesale trade. The tax rate reduction is applicable for tax reports originally due on or after January 1, 2016.  Energen recognized a $3.1 million income tax benefit during the second quarter of 2015, the period the law was enacted, to reflect the impact of this change.

Discontinued operations, net of tax: 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. 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 the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. Energen’s results of operations and cash flows for the years ended December 31, 2014 and 2013 presented in our consolidated financial statements and these notes reflect Alagasco as discontinued operations.

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In March 2014, Energen completed the sale of its North Louisiana/East Texas primarily natural gas properties for $30.3 million. The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations. Energen recognized non-cash impairment writedowns on these properties in 2014 of $1.9 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. Energen also recognized non-cash impairment writedowns on these properties of $29.8 million in 2013. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net on the consolidated income statements. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million. Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 that was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held for sale and reflected in discontinued operations during the third quarter of 2013.

See Note 16, Discontinued Operations and Held for Sale Properties, in the Notes to Financial Statements for additional information regarding discontinued operations.

FINANCIAL POSITION AND LIQUIDITY

Cash Flow

The key drivers impacting our cash flow from operations are our oil, natural gas liquids and natural gas production volumes and realized commodity market prices, net of the effects of settlements on our derivative commodity instruments. We rely on our cash flows from operations supplemented by borrowings under our syndicated credit facility to fund our capital spending plans and working capital requirements. We also used the pre-tax proceeds from the sale of certain San Juan Basin properties.

Net cash provided by operating activities: Energen’s net cash from operating activities totaled $714.6 million, $705.5 million and $927.4 million in 2015, 2014 and 2013, respectively and included discontinued operations associated with cash flows from Alagasco of $91.5 million in 2014 and $109.3 million in 2013. Net income in 2015 was impacted by non-cash charges, including, asset impairment charges, deferred income taxes and the change in derivative fair value. During 2015, operating cash flows were impacted by significantly lower commodity prices. During 2014, operating cash flows decreased due to lower oil and natural gas liquids commodity prices partially offset by increased production and higher natural gas commodity prices. Net income in 2014 was also significantly impacted by non-cash charges, including higher DD&A, asset impairment charges and the change in derivative fair value. During 2013, operating cash flows increased due to an increase in oil and natural gas liquids production and higher natural gas and oil commodity prices. In 2013, net income was also impacted by non-cash charges, including higher DD&A and the change in derivative fair value. The Company’s working capital needs were also influenced by accrued taxes and the timing of payments and recoveries for all years.

Net cash used in investing activities: Energen made net investments of $847.3 million during 2015. Energen invested $87.4 million in property acquisitions including approximately $85.5 million of unproved leaseholds; $386.4 million for development costs (includes the reversal of approximately $17.2 million of accrued development cost) including approximately $139 million to drill 63 net development and service wells; and $753.1 million for exploration (includes the reversal of approximately $111.1 million of accrued exploration cost) including approximately $492 million to drill 100 net exploratory wells. Included in the proceeds from asset sales in 2015 are cash proceeds of $384 million from the sale of certain San Juan Basin assets and $8.6 million from the sale of Alagasco. During 2014, the Company made net investments of $38.9 million. Energen invested $70.7 million in property acquisitions including approximately $68.5 million of unproved leaseholds; $399.1 million for development costs (excludes the accrual of approximately $4.6 million of accrued development cost) including approximately $270 million to drill 102 net development and service wells; and $844.1 million for exploration (excludes the accrual of approximately $109.3 million of accrued exploration cost) including approximately $703 million to drill 110 net exploratory wells. Included in the proceeds from asset sales and the sale of Alagasco in 2014 are cash proceeds of $1,317.1 million from the sale of Alagasco and $30 million from the sale of North Louisiana/East Texas properties. During 2013, the Company made net investments of $1,053.6 million. Energen invested $31.3 million in property acquisitions including approximately $26.8 million of unproved leaseholds; $675.4 million for development costs (includes the reversal of approximately $23.9 million of accrued development cost) including approximately $457 million to drill 179 net development and service wells; and $423.7 million for exploration including approximately $295 million to drill 90 net exploratory wells. Energen had cash proceeds in 2013 of $161.0 million primarily from the sale of certain Black Warrior Basin properties.

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During 2015, Energen added 133 MMBOE of proved reserves from discoveries and other additions, primarily the result of exploratory and development drilling that increased the number of proved undeveloped locations in the Permian Basin. Energen added approximately 130 MMBOE and 37 MMBOE of proved reserves in 2014 and 2013, respectively.

Net cash provided by (used in) financing activities: The Company provided $132.1 million for net financing activities in 2015 primarily due to the issuance of 5,700,000 shares of common stock largely offset by the repayment of credit facility borrowings. The Company used $670.3 million for net financing activities in 2014 largely due to the repayment of $600 million Senior Term Loans, discontinued operations primarily related to the sale of Alagasco and the purchase and retirement of shares. In 2013, the Company provided $122.1 million from net financing activities primarily from the December 2013 issuance of $600 million of Senior Term Loans partially offset by the repayment of long-term debt of $350 million combined with a decrease in short-term borrowings. For each of the years, net cash provided by (used in) financing activities also reflected dividends paid to common shareholders and cash received from the issuance of common stock through the Company’s stock-based compensation plan.

Capital Expenditures

Capital spending at Energen is detailed below.

Years ended December 31, (in thousands)	2015		2014		2013
Property acquisitions	$	87,556	$	71,096	$	31,481
Development	370,331		406,597		654,222
Exploration	641,983		953,409		423,698
Other	14,938		20,849		11,352
Total	1,114,808		1,451,951		1,120,753
Less exploration expenditures charged to income	74,198		79,441		16,008
Net capital expenditures	$	1,040,610	$	1,372,510	$	1,104,745

FUTURE CAPITAL RESOURCES AND LIQUIDITY

Outlook

Realized commodity prices and production levels by commodity type are the two primary drivers of our liquidity. Recent price declines in the outlook for oil, natural gas liquids and natural gas indicate a significant risk for lower revenues and related operating cash flows. Historically, prices received for oil, natural gas liquids and natural gas production have been volatile because of supply and demand factors, general economic conditions and seasonal weather patterns. Crude oil prices also are affected by quality differentials, worldwide political developments and actions of the Organization of the Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply and demand factors, including seasonal variations and the availability and price of transportation to consuming areas.

We engage in derivative risk management activities in order to reduce the risk associated with commodity price fluctuations. Commodity hedges in place for 2016 will help mitigate some of the commodity price volatility and recent declines; however, we currently have significantly fewer hedges in place for 2016 and at lower price levels than in 2015 and may not be able to execute new hedges at acceptable volumes or price levels.Unless commodity prices increase during 2016, we expect that the net prices we will receive for our 2016 production will decline relative to 2015. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for a full detail of our hedged volumes.

Production from the liquids rich Permian Basin in 2016 is estimated to range from 19.5 MMBOE to 20.3 MMBOE, with a midpoint of 19.9 MMBOE, including approximately 17.6 MMBOE of estimated production from proved reserves owned at December 31, 2015. Production estimates do not include amounts related to held for sale properties or potential future acquisitions. In the event Energen is unable to fully invest in its capital investment opportunities, future operating revenues, production and proved reserves could be negatively affected.

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Production volumes by commodity are expected to be as follows:

Year ended December 31, (MMBOE)	2016
Oil	12.6
Natural gas liquids	3.5
Natural gas	3.8
Total (midpoint of range)	19.9

During 2016, Energen expects an annualized decline rate of approximately 18.2 percent for its proved developed producing properties owned at December 31, 2015, excluding production from held for sale properties. During the same period, total production from proved properties is expected to decrease approximately 12.8 percent and total production is expected to decrease approximately 1.5 percent. The above proved developed producing properties decline rate is not necessarily indicative of Energen’s expectations for its terminal decline rate on a long-term basis.

Various factors influence decline rates. For example, certain properties may have production curves that decline at faster rates in the early years of production and at slower rates in later years. Accordingly, the decline rate for a single year is influenced by numerous factors, including but not limited to, the mix of types of wells, the mix of newer versus older wells, and the effect of enhanced recovery activities, but it is not necessarily indicative of future decline rates. Energen expects a compound annual decline rate for proved producing properties owned at December 31, 2015, excluding production from held for sale properties, for the 5 year period 2015 to 2020, for the 10 year period 2015 to 2025 and for the 20 year period 2015 to 2035 of approximately 16.2 percent, 12.5 percent and 10 percent, respectively.

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 and natural gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

Energen plans to continue investing capital in oil and natural gas production operations. For 2016, we expect our oil and natural gas capital spending to total approximately $250 million, including $209 million for existing properties and $36 million for exploration. Included in this $209 million is approximately $58 million for the development of previously identified proved undeveloped reserves. Capital spending is required to offset declines in production and proved oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the results of our drilling program and our ability to add reserves economically during a challenging market for crude oil and natural gas.

Capital expenditures in the Permian Basin by area during 2016 are planned as follows:

Year ended December 31, (in thousands)	2016
Midland Basin	$	197
Delaware Basin	41
Other	3
Net Carry-in/Carry Out	5
Total	$	246

Energen anticipates having the following drilling rigs and net wells by area during 2016. The drilling rigs presented below are operated while the net wells include operated and non-operated wells.

	Drilling Rigs	Net Wells
Permian Basin	1-2	11

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Included in Energen’s capital plan is approximately $168 million for the completion of 46 net drilled but uncompleted wells in the Midland Basin.

Energen also may allocate additional capital for other oil and natural gas activities such as property acquisitions and additional development of existing properties. Energen may evaluate acquisition opportunities which arise in the marketplace. Energen’s ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions, except as discussed above, are not included in the aforementioned estimate of oil and natural gas investments and could result in capital expenditures different from those outlined above.

Liquidity

At December 31, 2015, we had $1.3 million of cash on hand and $1.2 billion of committed financing available under our credit facilities. To finance our operations, working capital and capital spending, we expect to use internally generated cash flow from operations supplemented by our existing $1.4 billion five-year syndicated credit facility. In addition, we have classified our remaining San Juan Basin properties as held for sale as of December 31, 2015 and, subsequent to year-end, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale.

Energen may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. Access to capital is an integral part of Energen’s business plan. As of December 31, 2015, the Company has $222.5 million outstanding under its revolving credit facilities and $554.0 million outstanding under long term note agreements. While we expect to have ongoing access to our credit facility and capital markets, continued access could be adversely affected by current and future economic and business conditions and possible credit rating downgrades. To the extent current market conditions continue for a prolonged period or worsen, we may be forced to reduce or delay capital and operational expenditures, divest assets, seek additional debt or equity financing, or refinance all or a portion of our debt.

Our debt facilities are subject to certain financial and non-financial covenants as discussed in Note 3, Long Term Debt, in the Notes to Financial Statements. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other noncash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0.As of December 31, 2015, we were in compliance with our covenants and expect to maintain compliance during 2016 assuming we are able to execute on our business plan which includes property divestitures and/or access to the capital markets and utilization of our credit facility. However, factors including those outside of our control may prevent us from maintaining compliance with the financial and non-financial covenants, including our total debt to EBITDAX covenant, at future measurement dates in 2016 and beyond. Such factors may include further commodity price declines, lack of liquidity in property and capital markets and our continuing ability to execute on our business plan. The borrowing base on our credit facility is scheduled to be redetermined in April and October of 2016. In the event that we are unable to remain in compliance with our financial and non-financial covenants, we would seek covenant relief at a scheduled redetermination date or at an interim date, as appropriate, during 2016. However, no assurances can be given with respect to such relief. If any such covenant violations are not waived by the lenders such violation would result in an event of default that could trigger acceleration of payment of the amounts outstanding under credit facilities and long term note agreements, which is an aggregate balance outstanding of $776.5 million at December 31, 2015. Additionally, the lenders could refuse to make additional loans under the credit facility, take possession of any collateral, and exercise other remedies or rights that may be available to them, all of which could have a material adverse effect on the business and financial condition of the Company.

On September 2, 2014, Energen entered into a five-year syndicated secured credit facility with domestic and foreign lenders. On October 20, 2015, the borrowing base and aggregate commitments were reduced to $1.4 billion in association with the semi-annual redetermination required under the agreement. Energen’s obligations under the $1.4 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. 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

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redeterminations. Given the lower price environment since our prior redetermination, we would expect a reduction in our borrowing basis at the next scheduled redetermination. Our next scheduled redetermination is April 1, 2016.

At December 31, 2015, Energen reported negative working capital of $41.2 million arising from current liabilities of $287.5 million exceeding current assets of $246.3 million. Working capital at Energen is influenced by the fair value of derivative financial instruments associated with future production. Energen has $57.0 million in current assets and $0.5 million in current liabilities associated with its derivative financial instruments at December 31, 2015. Energen relies upon cash flows from operations supplemented by our credit facility to fund working capital needs.

Workforce Reduction

On January 22, 2016, we reduced our workforce as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In connection with the reduction, we will incur a total charge of approximately $3.2 million in the first quarter of 2016 for one-time termination benefits.

Credit Ratings

On February 11, 2016, Moody’s Investors Service lowered Energen’s Corporate Family rating from Ba1 to B1 with a negative outlook. Moody’s Senior Unsecured Medium-Term Notes and Senior Unsecured Regular Bond ratings were lowered from Ba2 to B3 with a negative outlook. On February 9, 2016, Standard and Poor’s affirmed its Corporate credit rating for Energen at BB with a stable outlook.

Equity Offering and Shares Issued

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 initially used to repay borrowings under our credit facility and for general corporate purposes.

(in thousands)	December 31, 2015	December 31, 2014
Shares outstanding	78,795	72,973
Treasury stock*	2,976	2,903
Shares issued	81,771	75,876

*Excludes 50,800 shares and 78,254 shares held in the 1997 Deferred Compensation Plan at December 31, 2015 and 2014, respectively.

Dividends

In February 2016, we announced the discontinuance of dividend payments. Accordingly, we do not expect to pay cash dividends on Energen common stock in 2016. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

Employee Benefit Plans

In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015 and distributed benefits in December 2015.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 with the remainder to be paid in the first quarter of 2016. In connection with the termination of these plans, Energen has also classified approximately $3.3 million as of December 31, 2015 of its investment in a Rabbi Trust from other long term assets to prepayments and other assets in the accompanying balance sheets to reflect its intent to utilize these assets to partially fund the estimated payments in the first quarter of 2016.

In October 2014, Energen’s Board of Directors amended and restated the Employee Savings Plan to make certain benefit design changes effective January 1, 2015. The benefit design changes include an increase in the percentage of Company match and other contributions. In February 2016, Energen announced additional changes to benefits under the Employee Savings Plan, effective March 21, 2016, which reduces the percentage of Company match.

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Stock Repurchase Authorization

From time to time, the Company may repurchase shares of its common stock through open market or negotiated purchases. Such repurchases would be pursuant to a 3,600,000 share repurchase authorization approved by the Board of Directors on October 22, 2014. For the year ended December 31, 2014, Energen repurchased and retired 226,839 shares for $14.9 million pursuant to our repurchase authorization. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2015 and 2013. As of December 31, 2015, a total of 3,373,161 shares remain authorized for future repurchase. The timing and amounts of any repurchases are subject to changes in market conditions and other business considerations. Energen also from time to time acquires shares in connection with participant elections under Energen’s stock compensation plans. For the years ended December 31, 2015, 2014 and 2013, Energen acquired 73,126 shares, 32,768 shares and 14,766 shares, respectively, in connection with its stock compensation plans.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes Energen’s significant contractual cash obligations, other than hedging contracts, as of December 31, 2015:

			Payments Due Before December 31,
(in thousands)	Total		2016		2017-2018		2019-2020		2021 and Thereafter
Long-term debt (1)	$	776,500	$	—	$	19,000	$	222,500	$	535,000
Interest payments on debt	229,457		33,261		64,538		58,848		72,810
Operating leases	10,079		2,537		5,111		2,431		—
Asset retirement obligations (2)	718,952		5,480		4,919		5,235		703,318
Nonqualified supplemental retirement plans	15,729		14,606		231		217		675
Total contractual cash obligations	$	1,750,717	$	55,884	$	93,799	$	289,231	$	1,311,803

(1) Long-term debt obligations include approximately $0.4 million of unamortized debt discounts as of December 31, 2015.

(2) Represents the estimated future asset retirement obligation on an undiscounted basis.

Energen operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a working interest basis as defined in the joint operating contractual agreement.

Under various agreements for third-party gathering, treatment, transportation or other services, Energen is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 5.8 MMBOE through October 2020.

The contractual obligations reported above exclude Energen’s liability of $11.2 million related to Energen’s provision for uncertain tax positions. Energen cannot make a reasonably reliable estimate of the amount and period of related future payments for such liability.

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 Orderin 2011 and in July 2012, on a motion from ONRR, the Orderwas remanded. In August 2014, ONRR issued its Revised Order that is now under appeal. In the Revised Order, ONRR has ordered that Energen pay additional royalties on production from certain federal leases in the amount of $129,700. Energen estimates that application of

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the Revised Order to all of the Company’s federal leases would result in ONRR claims up to approximately $24 million, plus interest and penalties from 2004 forward. ONRR began implementing its unbundling initiative in 2010, but seeks to implement its revisions retroactively, despite the fact that they conflict with previous audits, allowances and industry practice. Energen continues to vigorously contest the Revised Order and the findings. Management is unable, at this time, to determine a range of reasonably possible losses, and no amount has been accrued as of December 31, 2015.

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 and basis swaps typically executed with investment and commercial banks and energy-trading firms.

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. Additionally, Energen is at risk of economic loss based upon the creditworthiness of our counterparties. We were in a net gain position with eleven of our active counterparties and in a net loss position with the remaining one at December 31, 2015. Energen has policies in place to limit hedging to not more than 80 percent of our estimated annual production; however, Energen’s credit facility contains a covenant which operates to limit hedging at a lower threshold in certain circumstances.

Energen has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of crude oil, natural gas liquids and natural gas may have on the fair value of its derivative instruments. This analysis measured the impact on the commodity derivative instruments and, thereby, did not consider the underlying exposure related to the commodity. At December 31, 2015, Energen was in a net gain position of $56.5 million for derivative contracts and estimates that a 10 percent increase or decrease in the commodities prices would have resulted in an approximate $4.3 million change in the fair value of open derivative contracts; however, gains and losses on derivative contracts are expected to be similarly offset by sales at the spot market price. The hypothetical change in fair value was calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes and did not include the impact of related taxes on actual cash prices.

All derivatives are recognized at fair value under the fair value hierarchy as discussed in Note 2, Summary of Significant Accounting Policies, in the Notes to Financial Statements. Level 3 assets as of December 31, 2015 represent an immaterial amount of both total assets and liabilities. Changes in fair value primarily result from price changes in the underlying commodity. Energen has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its Level 3 instruments. We estimate that a 10 percent increase or decrease in commodity prices would result in an approximate $0.1 million change in the fair value of open Level 3 derivative contracts and to the results of operations.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets. The Commodities Futures Trading Commission (CFTC) and the SEC have adopted, or are in the process of adopting, rules and regulations covering, among other derivative transactions, transactions linked to crude oil and natural gas prices.  We believe Energen’s derivative transactions qualify for the end-user exception which exempts them from certain Dodd-Frank Act swap clearing and exchange-trading requirements pursuant to final regulations adopted by the CFTC and SEC. However, the Dodd-Frank Act also authorized the CFTC to set position limits for certain futures and options contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC’s initial regulations on position limits were vacated by the U.S. District Court for the District of Columbia in 2012, and the CFTC subsequently proposed new position limits in November 2013. The CFTC has supplemented the new position limit rule proposal as recently as September 2015, and the final rules have not yet been adopted. The full impact of the Dodd-Frank Act and related regulatory requirements on Energen will not be known until the regulations have been fully implemented and the derivative markets have adjusted to such regulations. Energen could experience increased costs and reduced liquidity in the markets as a result of these rules and regulations governing derivatives, which could reduce hedging opportunities and negatively affect our revenues and cash flows.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Energen’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Management has identified the following critical accounting policies in the application of existing accounting standards or in the implementation of new standards that involve significant judgments and estimates by Energen. The application of these accounting policies necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events that could have a material impact on the financial statements.

Accounting for Oil and Natural Gas Producing Activities and Related Proved Reserves: Energen utilizes the successful efforts method of accounting for its oil and natural gas producing activities. Acquisition and development costs of proved properties are

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capitalized and amortized on a units-of-production basis over the remaining life of total proved and proved developed reserves. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The technologies associated with these proved reserve estimates are analysis of well production data, geophysical data, wireline and core data. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas proved reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and natural gas proved reserves have been determined by Company engineers. Independent oil and natural gas reservoir engineers have audited the estimates of proved reserves of crude oil, natural gas liquids and natural gas attributed to Energen’s net interests in oil and natural gas properties as of December 31, 2015. The independent reservoir engineers have issued reports covering approximately 99 percent of the Company’s ending proved reserves and in their judgment these estimates were reasonable in the aggregate. Energen’s production of proved undeveloped reserves requires the drilling of development wells and the installation or completion of related infrastructure facilities.

Changes in oil and natural gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated proved reserves held by Energen. If proved reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if proved reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the property’s book value if an impairment is warranted.

The table below reflects an estimated increase in 2016 depreciation, depletion and amortization expense associated with an assumed downward revision in the reported oil and natural gas reserve amounts at December 31, 2015:

	Percentage Change in Proved Oil & Natural Gas Reserves From Reported Reserves
	as of December 31, 2015
(dollars in thousands)	-5%		-10%
Estimated increase in DD&A expense for the year ended December 31, 2016, net of tax	$	14,416	$	30,322

Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred.

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. 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. We monitor the business environment and our oil and natural gas properties for events that could result in a potential impairment. Further, we make assumptions about future expectations in our evaluation of potential impairment. Such assumptions include, but are not necessarily limited to, commodity prices and related basis differentials, transportation costs, inflation assumptions, well and reservoir performance, severance and ad valorem taxes, other operating and future development costs, and general business plans. 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.

Our commodity price assumption is a significant and volatile uncertainty in our estimate, and we are unable to reliably forecast future commodity prices. Our assumption is therefore based on the commodity price curve for the next five years and then escalated at 3 percent through our assumed price caps. Our other assumptions generally have less volatility than the price assumption with variances tending to be field specific and more localized in effect. However, these assumptions can also be impacted by a higher or lower inflationary environment, limitations on takeaway capacity, well and reservoir performance over time, changes to governmental taxation, or changes to cost assumptions, operational and development plans, or the general economic or business environment.

If a material event occurs, we make 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.

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We may also 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.

Certain impairments were recognized during 2015 as discussed under Asset Impairment in our Results of Operations. A further decline in our price assumptions by 10 percent (assuming all other assumptions are held constant) would result in approximately $240 million of impairment expense on properties, primarily in the Central Basin Platform, not impaired at December 31, 2015. No additional expense would be recognized on properties previously impaired. Other assumptions such as operating costs, transportation costs, well and reservoir performance, severance and ad valorem taxes, operating and development plans may also change given an assumed 10 percent commodity price decline. However, we are unable to estimate their correlation to the price change and these other assumptions may worsen or partially mitigate some of the estimated impairment.

Derivatives: Energen periodically enters into derivative commodity instruments to manage its exposure to oil, natural gas liquids and natural gas price volatility. We enter into derivative transactions that are accounted for as mark-to-market transactions with gains and losses reported in current period gain (loss) on derivative instruments, net. Energen does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Company’s financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred.

Asset Retirement Obligation: Energen records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, Energen will settle the obligation for its recorded amount and recognize the resulting gain or loss. Energen has an obligation to remove tangible equipment and restore land at the end of oil and natural gas production operations. The estimate of future restoration and removal costs includes numerous assumptions and uncertainties, including but not limited to, inflation factors, discount rates, timing of settlement, and changes in contractual, regulatory, political, environmental, safety and public relations considerations.

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD

See Note 19, Recently Issued Accounting Standards, in the Notes to Financial Statements for information regarding recently issued accounting standards.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained herein should be read in conjunction with the related disclosures as set forth in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Outlook” and in Note 7, Derivative Commodity Instruments, and in Note 8, Fair Value Measurements, in the Notes to Financial Statements.

We are exposed to various market risks including commodity price risk, counterparty credit risk and interest rate risk. We seek to manage these risks through our risk management program which often includes the use of derivative instruments. We do not enter into derivative or other financial instruments for speculative or trading purposes.

Commodity price risk: Energen’s major market risk exposure is in the pricing applicable to its oil and natural gas production. Historically, prices received for oil, natural gas liquids and natural gas production have been volatile due to seasonal weather patterns, world and national supply-and-demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, by worldwide political developments and by actions of the Organization of the Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply-and-demand factors, including seasonal factors and the availability and price of transportation to consuming areas. As impacted by such commodity price volatility during  2015, our average realized oil prices fell 46.2 percent to $45.04 per barrel, average realized natural gas liquids prices decreased 54.7 percent to an average price of $0.29 per gallon and average realized natural gas prices decreased 44.4 percent to $2.32 per Mcf.

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 swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms.

As of December 31, 2015, Energen entered into the following transactions for 2016 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description	Fair Value (in thousands)
Oil
2016	1,086	MBbl	$63.80 Bbl	NYMEX Swaps	$	24,126
Oil Basis Differential
2016	7,524	MBbl	$(1.92) Bbl	WTI/WTI Basis Swaps	(13,180		)
2016	2,117	MBbl	$(1.63) Bbl	WTS/WTI Basis Swaps	(2,878		)
December 2015 contracts (closed but not cash settled)					48,436
Total					$	56,504
WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

Realized prices are anticipated to be lower than New York Mercantile Exchange prices primarily due to basis differences and other factors.

Additionally, we have entered into certain sales volume and supply target arrangements with certain customers. A failure to meet sales volume targets at Energen due to miscalculations, weather events, natural disasters, accidents, mechanical failures, criminal acts or otherwise could leave us exposed to our counterparties in commodity hedging contracts and result in material adverse financial losses.

Counterparty credit risk: Our principal exposure to credit risk is through the sale of our oil, natural gas liquids and natural gas production, which we market 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 our overall exposure to credit risk. We consider the credit quality of our purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

We are also at risk for economic loss based upon the credit worthiness of our derivative instrument counterparties. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by Energen. All hedge transactions are subject to Energen’s risk management policy, approved by the Board of Directors, which does not permit

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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.

Interest rate risk: Our interest rate exposure as of December 31, 2015 primarily relates to our syndicated credit facility with variable interest rates. The weighted average interest rate for amounts outstanding at December 31, 2015 was 1.64 percent. A 1 percent increase or decrease in the weighted average interest rate would have resulted in an approximate $2.2 million change in interest expense on our outstanding credit facility balance of $222.5 million at December 31, 2015. All long-term debt obligations, other than our credit facility, were at fixed rates at December 31, 2015. At December 31, 2015, we had interest rate swap agreements with a notional value of $66.7 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 1.0425 percent. The fair value of our interest rate swaps was a $0.2 million liability at December 31, 2015.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ENERGEN CORPORATION

INDEX TO FINANCIAL STATEMENTS

		Page
1.	Financial Statements
	Report of Independent Registered Public Accounting Firm	48
	Consolidated Balance Sheets as of December 31, 2015 and 2014	49
	Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013	51
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2015, 2014 and 2013	52
	Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2015, 2014 and 2013	53
	Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	54
	Notes to Financial Statements	55

Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energen Corporation:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Energen Corporation and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reportingappearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 16, 2016

48

ENERGEN CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands)	December 31, 2015		December 31, 2014
ASSETS
Current Assets
Cash and cash equivalents	$	1,272	$	1,852
Accounts receivable, net	63,097		157,678
Inventories	11,255		14,251
Assets held for sale	93,739		395,797
Derivative instruments	56,963		322,337
Prepayments and other	20,014		27,445
Total current assets	246,340		919,360
Property, Plant and Equipment
Oil and natural gas properties, successful efforts method
Proved properties	7,611,118		6,903,514
Unproved properties	145,724		142,340
Less accumulated depreciation, depletion and amortization	3,454,510		1,893,106
Oil and natural gas properties, net	4,302,332		5,152,748
Other property and equipment, net	48,358		46,389
Total property, plant and equipment, net	4,350,690		5,199,137
Other postretirement assets	3,881		—
Other assets	12,782		19,761
TOTAL ASSETS	$	4,613,693	$	6,138,258

The accompanying Notes to Financial Statements are an integral part of these statements.

49

ENERGEN CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)	December 31, 2015			December 31, 2014
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	64,742		$	101,453
Accrued taxes	5,801			5,530
Accrued wages and benefits	28,563			21,553
Accrued capital costs	79,206			207,461
Revenue and royalty payable	60,493			72,047
Liabilities related to assets held for sale	12,789			24,230
Pension liabilities	15,685			24,609
Deferred income taxes	—			79,164
Derivative instruments	459			988
Other	19,783			23,288
Total current liabilities	287,521			560,323
Long-term debt	776,087			1,038,563
Asset retirement obligations	89,990			94,060
Pension and other postretirement liabilities	—			15,935
Deferred income taxes	552,369			1,000,486
Other	11,866			14,287
Total liabilities	1,717,833			2,723,654
Commitments and Contingencies
Shareholders’ Equity Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized	—			—
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized; 81,770,161 shares issued at December 31, 2015 and 75,875,711 shares issued at December 31, 2014	818			759
Premium on capital stock	979,030			564,438
Retained earnings	2,046,016			2,997,821
Accumulated other comprehensive income (loss), net of tax
Pension and postretirement plans	263			(22,870		)
Deferred compensation plan	1,965			2,862
Treasury stock, at cost; 3,026,350 shares and 2,980,598 shares at December 31, 2015 and 2014, respectively	(132,232		)	(128,406		)
Total shareholders’ equity	2,895,860			3,414,604
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	4,613,693		$	6,138,258

The accompanying Notes to Financial Statements are an integral part of these statements.

50

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

Years ended December 31, (in thousands, except share data)	2015			2014			2013
Revenues
Oil, natural gas liquids and natural gas sales	$	763,261		$	1,344,194		$	1,256,317
Gain (loss) on derivative instruments, net	115,293			335,019			(50,024		)
Total revenues	878,554			1,679,213			1,206,293
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production	228,380			274,432			257,438
Production and ad valorem taxes	57,380			102,063			94,103
Depreciation, depletion and amortization	593,789			548,564			452,876
Asset impairment	1,292,308			416,801			13,906
Exploration	14,878			28,090			14,036
General and administrative	149,132			122,052			113,821
Accretion of discount on asset retirement obligations	7,108			7,608			6,995
(Gain) loss on sale of assets and other, net	(26,570		)	2,642			981
Total operating costs and expenses	2,316,405			1,502,252			954,156
Operating Income (Loss)	(1,437,851		)	176,961			252,137
Other Income (Expense)
Interest expense	(43,108		)	(37,771		)	(39,736		)
Other income	223			1,181			3,803
Total other expense	(42,885		)	(36,590		)	(35,933		)
Income (Loss) From Continuing Operations Before Income Taxes	(1,480,736		)	140,371			216,204
Income tax expense (benefit)	(535,005		)	40,728			74,323
Income (Loss) From Continuing Operations	(945,731		)	99,643			141,881
Discontinued Operations, net of tax
Income from discontinued operations	—			29,292			59,079
Gain on disposal of discontinued operations, net	—			439,097			3,594
Income From Discontinued Operations	—			468,389			62,673
Net Income (Loss)	$	(945,731	)	$	568,032		$	204,554
Diluted Earnings Per Average Common Share
Continuing operations	$	(12.43	)	$	1.36		$	1.96
Discontinued operations	—			6.39			0.86
Net Income (Loss)	$	(12.43	)	$	7.75		$	2.82
Basic Earnings Per Average Common Share
Continuing operations	$	(12.43	)	$	1.37		$	1.96
Discontinued operations	—			6.42			0.87
Net Income (Loss)	$	(12.43	)	$	7.79		$	2.83
Diluted Average Common Shares Outstanding	76,078,371			73,274,631			72,470,622
Basic Average Common Shares Outstanding	76,078,371			72,896,579			72,317,865

The accompanying Notes to Financial Statements are an integral part of these statements.

51

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Years ended December 31, (in thousands)	2015			2014			2013
Net Income (Loss)	$	(945,731	)	$	568,032		$	204,554
Other comprehensive income (loss):
Cash flow hedges:
Current period change in fair value of derivative commodity instruments, net of tax of $0, $23 and ($6,660), respectively	—			37			(10,866		)
Reclassification adjustment for derivative commodity instruments, net of tax of $0, ($8,212) and ($13,560), respectively	—			(13,399		)	(22,124		)
Current period change in fair value of interest rate swap, net of tax of $0, ($160) and ($80), respectively	—			(298		)	(148		)
Reclassification adjustment for interest rate swap, net of tax of $0, $798 and $603, respectively	—			1,482			1,120
Total cash flow hedges	—			(12,178		)	(32,018		)
Pension and postretirement plans:
Amortization of net benefit obligation at transition, net of tax of $0, $8 and $112, respectively	—			14			207
Amortization of prior service cost, net of tax of $0, $87 and $90, respectively	—			161			167
Amortization of net loss, net of tax of $10,676, $7,676 and $4,472, respectively	19,828			14,256			8,306
Current period change in fair value of pension and postretirement plans, net of tax of $1,779, ($2,722), and $6,237, respectively	3,305			(5,056		)	11,582
Total pension and postretirement plans	23,133			9,375			20,262
Comprehensive Income (Loss)	$	(922,598	)	$	565,229		$	192,798

The accompanying Notes to Financial Statements are an integral part of these statements.

52

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

	Common Stock					Premium on Capital Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Deferred Compensation Plan			Treasury Stock			Total Shareholders’ Equity
(in thousands, except share data)	Number of Shares		Par Value
BALANCE DECEMBER 31, 2012	75,067,760		$	751		$	494,910		$	2,314,055		$	(8,311	)	$	2,774		$	(127,489	)	$	2,676,690
Net income									204,554												204,554
Other comprehensive loss												(11,756		)							(11,756		)
Purchase of treasury shares, net (14,766 shares)																		(1,038		)	(1,038		)
Shares issued for employee benefit plans	506,396		5			18,790															18,795
Deferred compensation obligation															485			(485		)	—
Stock-based compensation						6,869												2,756			9,625
Tax benefit from employee stock plans						3,142															3,142
Cash dividends - $0.58 per share									(41,993		)										(41,993		)
BALANCE DECEMBER 31, 2013	75,574,156		756			523,711			2,476,616			(20,067		)	3,259			(126,256		)	2,858,019
Net income									568,032												568,032
Other comprehensive loss												(2,803		)							(2,803		)
Purchase of treasury shares, net (32,768 shares)																		(2,547		)	(2,547		)
Purchase and retirement of treasury shares	(226,839	)	(2		)	(2,388		)	(12,523		)										(14,913		)
Shares issued for employee benefit plans	528,394		5			25,496															25,501
Deferred compensation obligation															(397		)	397			—
Stock-based compensation						11,713															11,713
Tax benefit from employee stock plans						5,906															5,906
Cash dividends - $0.47 per share									(34,304		)										(34,304		)
BALANCE DECEMBER 31, 2014	75,875,711		759			564,438			2,997,821			(22,870		)	2,862			(128,406		)	3,414,604
Net loss									(945,731		)										(945,731		)
Other comprehensive income												23,133									23,133
Purchase of treasury shares, net (73,206 shares)																		(4,723		)	(4,723		)
Shares issued for:
Stock offering	5,700,000		57			398,563															398,620
Employee benefit plans	194,450		2			6,737															6,739
Deferred compensation obligation															(897		)	897			—
Stock-based compensation						8,228															8,228
Tax benefit from employee stock plans						1,064															1,064
Cash dividends - $0.08 per share									(6,074		)										(6,074		)
BALANCE DECEMBER 31, 2015	81,770,161		$	818		$	979,030		$	2,046,016		$	263		$	1,965		$	(132,232	)	$	2,895,860

The accompanying Notes to Financial Statements are an integral part of these statements.

53

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31, (in thousands)	2015			2014			2013
Operating Activities
Net income (loss)	$	(945,731	)	$	568,032		$	204,554
Income from discontinued operations	—			(468,389		)	(62,673		)
Adjustments to reconcile net income to net cash provided    by operating activities:
Depreciation, depletion and amortization	593,789			548,564			452,876
Asset impairment	1,292,308			416,801			13,906
Accretion of discount on asset retirement obligations	7,108			7,608			6,995
Deferred income taxes	(539,735		)	302,890			118,600
Change in derivative fair value	233,315			(346,646		)	48,029
(Gain) loss on sale of assets	(28,077		)	55			(89		)
Stock-based compensation expense	8,028			11,332			13,621
Exploration, including dry holes	7,097			9,325			2,102
Discontinued operations	—			91,510			109,318
Other, net	35,641			4,166			12,284
Net change in:
Accounts receivable	117,486			4,812			23,785
Inventories	(655		)	(3,121		)	10,817
Accounts payable	(46,283		)	18,695			(52,946		)
Accrued taxes/income tax receivable	(4,791		)	(488,980		)	4,092
Pension and other postretirement benefit contributions	(24,848		)	(12,483		)	(5,677		)
Other current assets and liabilities	9,940			41,312			27,783
Net cash provided by operating activities	714,592			705,483			927,377
Investing Activities
Additions to oil and natural gas properties	(1,154,373		)	(1,264,059		)	(1,109,365		)
Acquisitions, net of cash acquired	(87,410		)	(70,730		)	(31,331		)
Proceeds from asset sales and sale of Alabama Gas Corporation	394,521			1,347,725			160,986
Purchase of short-term investments	(919,000		)	(473,000		)	(310,000		)
Sale of short-term investments	919,000			473,000			310,000
Discontinued operations	—			(51,850		)	(73,341		)
Other, net	—			—			(559		)
Net cash used in investing activities	(847,262		)	(38,914		)	(1,053,610		)
Financing Activities
Payment of dividends on common stock	(6,074		)	(34,304		)	(41,993		)
Issuance of common stock, net	399,600			23,053			17,780
Purchase and retirement of shares	—			(14,913		)	—
Issuance of long-term debt	—			—			600,000
Reduction of long-term debt	—			(600,000		)	(350,000		)
Payment of debt issuance costs	—			(10,901		)	(2,740		)
Net change in credit facility	(262,500		)	(4,000		)	(77,000		)
Tax benefit on stock compensation	1,064			5,906			3,142
Discontinued operations	—			(35,113		)	(27,105		)
Net cash provided by (used in) financing activities	132,090			(670,272		)	122,084
Net change in cash and cash equivalents	(580		)	(3,703		)	(4,149		)
Cash and cash equivalents at beginning of period	1,852			5,555			9,704
Cash and cash equivalents at end of period	1,272			1,852			5,555
Less cash and cash equivalents of discontinued operations at end of period	—			—			(3,032		)
Cash and cash equivalents of continuing operations at end of period	$	1,272		$	1,852		$	2,523

The accompanying Notes to Financial Statements are an integral part of these statements.

54

ENERGEN CORPORATION

NOTES TO FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

Energen Corporation (Energen or the Company) is an oil and natural gas exploration and production company engaged in the exploration, development and production of oil, natural gas liquids-rich properties and natural gas primarily in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Headquartered in Birmingham, Alabama, our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources).

Energen may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held for sale are reported at the lower of the carrying amount or estimated fair value. Certain of these held for sale properties also qualify as discontinued operations. The results of operations of these properties are reclassified and reported as discontinued operations for prior periods.

Prior to September 2, 2014, Energen owned Alabama Gas Corporation (Alagasco), which was engaged in the purchase, distribution and sale of natural gas principally in central and north Alabama. On September 2, 2014, Energen completed the transaction to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion resulting in a pre-tax gain of $726.5 million. This sale had an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness. During 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. See Note 16, Discontinued Operations and Held for Sale Properties, for further information regarding the sale of Alagasco.

Liquidity

At December 31, 2015, we had $1.3 million of cash on hand and $1.2 billion of committed financing available under our credit facilities. To finance our operations, working capital and capital spending, we expect to use internally generated cash flow from operations supplemented by our existing $1.4 billionfive-year syndicated credit facility. In addition, we have classified our remaining San Juan Basin properties as held for sale as at December 31, 2015 and, subsequent to year-end, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale.

Energen may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. Access to capital is an integral part of Energen’s business plan. As of December 31, 2015, the Company has $222.5 million outstanding under its revolving credit facilities and $554.0 million outstanding under long term note agreements. While we expect to have ongoing access to our credit facility and capital markets, continued access could be adversely affected by current and future economic and business conditions and possible credit rating downgrades. To the extent current market conditions continue for a prolonged period or worsen, we may be forced to reduce or delay capital and operational expenditures, divest assets, seek additional debt or equity financing, or refinance all or a portion of our debt.

Our debt facilities are subject to certain financial and non-financial covenants as discussed in Note 3, Long Term Debt. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other noncash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0.As of December 31, 2015, we were in compliance with our covenants and expect to maintain compliance during 2016 assuming we are able to execute on our business plan which includes property divestitures and/or access to the capital markets and utilization of our credit facility. However, factors including those outside of our control may prevent us from maintaining compliance with the financial and non-financial covenants, including our total debt to EBITDAX covenant, at future measurement dates in 2016 and beyond. Such factors may include further commodity price declines, lack of liquidity in property and capital markets and our continuing ability to execute on our business plan. The borrowing base on our credit facility is scheduled to be redetermined in April and October of 2016. In the event that we are unable to remain in compliance with our financial and non-financial covenants, we would seek covenant relief at a scheduled redetermination date or at an interim date, as appropriate, during 2016. However, no assurances can be given with respect to such relief. If any such covenant violations are not waived by the lenders such violation would result in an event of default that could trigger acceleration of payment of the amounts outstanding under credit facilities and long term note agreements, which is an aggregate balance outstanding of $776.5 million at December 31, 2015. Additionally, the lenders could refuse to make additional loans under the credit facility, take possession of any collateral, and exercise other remedies or rights that may be available to them, all of which could have a material adverse effect on the business and financial condition of the Company.

55

Workforce Reduction

On January 22, 2016, we reduced our workforce as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In connection with the reduction, we will incur a total charge of approximately $3.2 million in the first quarter of 2016 for one-time termination benefits.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. Principles of Consolidation

The accompanying consolidated financial statements include Energen and its subsidiaries, principally Energen Resources, after elimination of all significant intercompany transactions in consolidation. In the opinion of management, our consolidated financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods and as of the dates shown. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior periods’ financial statements to the current-year presentation.

B. Oil and Natural Gas Operations

Property and Related Depletion: Energen follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, natural gas liquids and natural gas reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. Energen capitalizes exploratory drilling costs until a determination is made that the well or project has either found proved reserves or is impaired. After an exploratory well has been drilled and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas quantities can be classified as proved. In those circumstances, we continue to capitalize the drilling costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Capitalized exploratory drilling costs are presented in proved properties in the balance sheets. If the exploratory well is determined to be a dry well, the costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves.

Operating Revenues: Energen utilizes the sales method of accounting to recognize oil, natural gas liquids and natural gas production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining proved reserves for such property. Energen had no significant production imbalances at December 31, 2015 and 2014.

Derivative Commodity Instruments: We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen. All derivative transactions are included in operating activities on the consolidated statements of cash flows.

The majority of our counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Energen formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the nature of the risk being hedged. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes.

Effective June 30, 2013, Energen discontinued the use of cash flow hedge accounting and dedesignated all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting,

56

any gains or losses from inception of the hedge to June 30, 2013 were frozen in accumulated other comprehensive income until the forecasted transactions actually occurred. Any subsequent gains or losses are accounted for as mark-to-market and recognized immediately through gain (loss) on derivative instruments, net. As a result of Energen’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 are accounted for as mark-to-market transactions with gains or losses recognized in the period of change in gain (loss) on derivative instruments, net.

Asset Impairments: Oil and natural gas proved properties periodically are assessed for possible impairment on a field-by-field basis using the estimated undiscounted future cash flows. Energen monitors its oil and natural gas properties as well as the market and business environments in which it operates and makes assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected production performance. If a material event occurs, we make an estimate of undiscounted future cash flows to determine whether the asset is impaired. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. If the asset is impaired, Energen will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows.

Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These variables can, and often do, differ from the estimates and can have a positive or negative impact on our need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact Energen’s original and ongoing assessments of potential impairment.

Energen also may recognize impairments of capitalized costs for unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by exploration activities, changes in economic factors and potential shifts in business strategy employed by management. We consider a combination of geologic and economic factors to evaluate the need for impairment of these costs.

Long-Lived Assets and Discontinued Operations: Energen may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held for sale are reported at the lower of the carrying amount or estimated fair value. Certain of these held for sale properties also qualify as discontinued operations and the results of operations of these properties are reclassified and reported as discontinued operations for prior periods.

Acquisitions: Energen recognizes all acquisitions at fair value. Energen estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen obtained control of the properties for all acquisitions that qualify as business combinations. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. Energen uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy. Acquisition related costs are expensed as incurred in general and administrative expense on the consolidated income statements.

C. Inventory

Inventories consist primarily of tubular goods and other oilfield equipment used in our operations and are stated at the lower of cost or market value, on a weighted average cost basis.

D. Fair Value Measurements

The carrying values of cash and cash equivalents, accounts payable, accounts receivable (net of allowance), derivative commodity instruments, pension and postretirement plan assets and liabilities and other current assets and liabilities approximate fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). In determining fair value, we use various valuation approaches and classify all assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own assumptions about the assumptions other market participants would use in pricing the asset or liability based on the best information available in the circumstances. Assessing the significance of a particular input may require judgment considering factors specific to the

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asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The hierarchy is broken down into three levels based on the observability of inputs as follows:

Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;

Level 2 - Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;

Level 3 - Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumptions that market participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

The fair value of Energen’s derivative commodity instruments is determined using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. Our OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which we are able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX oil and natural gas prices. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. We consider the frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While Energen does not have access to the specific assumptions used in its counterparties’ valuation models, we maintain communications with our counterparties and discuss pricing practices. Further, we corroborate the fair value of our transactions by comparison of market-based price sources.

Energen utilizes a discounted cash flow model in valuing its interest rate derivatives, which are comprised of interest rate swap agreements. The fair value attributable to Energen's interest rate derivative contracts is based on (i) the contracted notional amounts, (ii) active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

Pension and postretirement plan assets include cash and mutual funds. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and Level 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds.

E. Income Taxes

Energen uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. Energen and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.

F. Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in the existing accounts receivable. Energen determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered. Energen had allowance for doubtful accounts of $0.7 million at both December 31, 2015 and 2014, respectively.

G. Cash and Cash Equivalents

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value.

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H. Short-term Investments

All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments. As of December 31, 2015 and 2014, Energen had no short-term investments.

I. Earnings Per Share (EPS)

Energen’s basic earnings per share amounts have been computed based on the weighted average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities.

J. Stock-Based Compensation

Energen recognizes all share-based compensation awards in general and administrative expense on the consolidated income statement over the requisite vesting period. Equity awards are measured at fair value as of the date of grant. Awards that are settled in cash are classified as liabilities and re-measured at fair value at the end of each reporting period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. We recognize all stock-based compensation expense in the period of grant, subject to certain vesting requirements, for retirement eligible employees. Energen utilizes the long-form method of calculating the available pool of windfall tax benefit. For the years ended December 31, 2015, 2014 and 2013, we recognized an excess tax benefit of $1.1 million, $5.9 million and $3.1 million, respectively, related to our stock-based compensation.

K. Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, physical quantities of proved oil and gas reserves, periodic assessments of oil and gas properties for impairment, Energen’s obligations under its employee pension and compensation plans, the valuation of derivative financial instruments, the allowance for doubtful accounts, tax contingency reserves, legal contingency reserves, asset retirement obligations and self insurance reserves. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.

L. Employee Benefit Plans

Plan Termination: In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015 and distributed benefits in December 2015.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 with the remainder to be paid in the first quarter of 2016.

Plan Separation: Effective April 30, 2014, Energen separated its defined benefit non-contributory pension plan and its postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan reflecting the separation of assets and obligations in accordance with ERISA provisions. Energen remeasured the plans using current assumptions.

Postretirement Benefit Plans: Energen provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. These postretirement healthcare and life insurance benefits are available upon reaching normal retirement age while working for Energen. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.

For other postretirement plans, certain financial assumptions are used in determining Energen’s projected benefit obligation. These assumptions are examined periodically by Energen, and any required changes are reflected in the subsequent determination of projected benefit obligations.

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Energen calculates periodic expense for the other postretirement benefit plans on an actuarial basis and the net funded status is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. The benefit obligation is the accumulated postretirement benefit obligation. Energen measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.

For our other postretirement plan, we selected a yield curve comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments.

The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. Energen considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets.

M. Environmental Costs

Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated.

3. LONG-TERM DEBT

Long-term debt consisted of the following:

(in thousands)	December 31, 2015		December 31, 2014
Credit facility	$	222,500	$	485,000
7.40% Medium-term Notes, Series A, due July 24, 2017	2,000		2,000
7.36% Medium-term Notes, Series A, due July 24, 2017	15,000		15,000
7.23% Medium-term Notes, Series A, due July 28, 2017	2,000		2,000
7.32% Medium-term Notes, Series A, due July 28, 2022	20,000		20,000
7.60% Medium-term Notes, Series A, due July 26, 2027	5,000		5,000
7.35% Medium-term Notes, Series A, due July 28, 2027	10,000		10,000
7.125% Medium-term Notes, Series B, due February 15, 2028	100,000		100,000
4.625% Notes, due September 1, 2021	400,000		400,000
Total	776,500		1,039,000
Less unamortized debt discount	413		437
Total	$	776,087	$	1,038,563

The aggregate maturities of Energen’s long-term debt as of December 31, 2015 are as follows:

Years ending December 31, (in thousands)
2016	2017	2018	2019	2020	Thereafter
$—	$19,000	$—	$222,500	$—	$535,000

The debt agreements of Energen contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. Although none of the agreements have events of default based on credit ratings, the interest rates applicable to the syndicated credit facility discussed below may adjust based on credit rating changes during certain periods.

Under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee, a cross default provision provides that any debt default of more than $10 million by Energen or Energen Resources will constitute an event of default by Energen. The Indenture does not include a restriction on the payment of dividends.

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Credit Facilities: On September 2, 2014, Energen entered into a five-year syndicated secured credit facility with domestic and foreign lenders. On October 20, 2015, the borrowing base and aggregate commitments were reduced to $1.4 billion in association with the semi-annual redetermination required under the agreement. Energen’s obligations under the $1.4 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. Subject to release of collateral in certain periods upon the achievement of certain investment grade ratings from designated ratings agencies, the credit facility is collateralized by certain assets of Energen, including a pledge of equity interests in subsidiaries of Energen other than Energen Resources, and by mortgages on substantially all of Energen Resources’ oil and natural gas properties. The current credit facility qualifies for classification as long-term debt on the consolidated balance sheets. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other non-cash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0; to maintain a ratio of consolidated current assets (adjusted to include amounts available for borrowings and exclude non-cash derivative instruments) to consolidated current liabilities (adjusted to exclude maturities under the credit facility and non-cash derivative instruments) greater than or equal to 1.0 to 1.0; and, during certain periods, to maintain a ratio of the net present value of proved reserves of our oil and natural gas properties to consolidated total debt greater than or equal to 1.50 to 1.0. We are also bound by covenants which limit our ability to incur additional indebtedness, make certain distributions or alter our corporate structure. Energen may not pay dividends during an event of default, if the payment would result in an event of default or if availability is less than 10 percent of the loan limit under the credit facility. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes. In addition, the terms of our credit facility limit the amount we can borrow to a borrowing base amount which is determined by our lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria including commodity price outlook. The borrowing base amount is subject to redetermination semi-annually and for event-driven unscheduled redeterminations. Our next scheduled redetermination is April 1, 2016. See Note 1, Organization and Basis of Presentation, for discussion of financial covenants under liquidity.

Under Energen’s credit facility, a cross default provision provides that any debt default of more than $75 million by Energen or Energen Resources will constitute an event of default by Energen.

Upon an uncured event of default under the credit facility, all amounts owing under the credit facility, if any, depending on the nature of the event of default will automatically, or may upon notice by the administrative agent or the requisite lenders thereunder, become immediately due and payable and the lenders may terminate their commitments under the defaulted facility. Energen was in compliance with the terms of its credit facility as of December 31, 2015.

The following is a summary of information relating to Energen’s credit facility:

(in thousands)	December 31, 2015			December 31, 2014
Credit facility outstanding	$	222,500		$	485,000
Available for borrowings	1,177,500			1,515,000
Total borrowing commitments	$	1,400,000		$	2,000,000
Maximum amount outstanding at any month-end	$	685,000		$	750,000
Average daily amount outstanding	$	358,929		$	482,166
Weighted average interest rates based on:
Average daily amount outstanding	1.60		%	1.46		%
Amount outstanding at year-end	1.64		%	1.67		%

Energen’s total interest expense was $43.1 million, $37.8 million and $39.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. Energen’s total interest expense for the years ended December 31, 2015, 2014 and 2013 included amortization of debt issuance costs of $3.3 million, $5.7 million and $2.0 million, respectively. Capitalized interest expense for the year ended December 31, 2015 was not significant. Capitalized interest expense was $0.2 million for both the years ended December 31, 2014 and 2013. At December 31, 2015, Energen paid commitment fees on the unused portion of available credit facilities at a current annual rate of 30 basis points per annum.

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4. INCOME TAXES

The components of Energen’s income taxes consisted of the following:

Years ended December 31, (in thousands)	2015			2014			2013
Taxes estimated to be payable currently:
Federal	$	3,972		$	161,576		$	23,342
State	758			72,379			2,516
Total current	4,730			233,955			25,858
Taxes deferred:
Federal	(513,187		)	144,645			85,950
State	(26,548		)	(34,447		)	(2,300		)
Total deferred	(539,735		)	110,198			83,650
Total income tax expense (benefit)	$	(535,005	)	$	344,153		$	109,508

The components of Energen’s income taxes consisted of the following:

Years ended December 31, (in thousands)	2015			2014		2013
Income tax expense (benefit) from continuing operations	$	(535,005	)	$	40,728	$	74,323
Income tax expense from discontinued operations	—			17,928		33,174
Income tax expense from gain on disposal of discontinued operations	—			285,497		2,011
Total income tax expense (benefit)	$	(535,005	)	$	344,153	$	109,508

Energen elected early adoption of Accounting Standards Update (ASU) No. 2015-17, Balance Sheet Classification of Deferred Taxes, prospectively as of December 31, 2015. This update requires that deferred tax liabilities and assets be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of each jurisdiction of an entity be offset and presented as a single amount is not affected by the amendments in this update. We reclassified $14.5 million from a current deferred income tax asset to a noncurrent deferred income tax liability at December 31, 2015.

Temporary differences and carryforwards which gave rise to Energen’s deferred tax assets and liabilities were as follows:

(in thousands)	December 31, 2015					December 31, 2014
	Current		Noncurrent			Current			Noncurrent
Deferred tax assets:
Minimum tax credit	$	—	$	44,862		$	—		$	46,338
Allowance for doubtful accounts	—		253			244			—
Insurance and other accruals	—		2,807			2,537			—
Compensation accruals	—		11,650			11,355			—
Pension and other costs	—		8,693			—			7,009
Other comprehensive income	—		—			10,732			1,581
State net operating losses and other carryforwards	—		12,577			—			15,392
Other	—		962			665			—
Total deferred tax assets	—		81,804			25,533			70,320
Valuation allowance	—		(4,235		)	(1,122		)	(2,467		)
Total deferred tax assets	—		77,569			24,411			67,853

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Deferred tax liabilities:
Depreciation and basis differences	—		620,629			—			1,057,430
Derivative instruments	—		2,838			102,691			—
Other comprehensive income	—		141			—			—
Other	—		6,330			884			10,909
Total deferred tax liabilities	—		629,938			103,575			1,068,339
Net deferred tax liabilities	$	—	$	(552,369	)	$	(79,164	)	$	(1,000,486	)

Energen files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2015, the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $44.9 million. Energen has a noncurrent deferred tax asset of $8.4 million relating to Energen Resources’ $191.3 million state net operating loss carryforward which will expire beginning in 2027. Energen Resources anticipates generating adequate future taxable income from the reversals of its existing taxable temporary differences to fully realize this benefit. Energen has a full valuation allowance recorded against a noncurrent deferred tax asset of $4.2 million arising from certain state net operating loss and charitable contribution carryforwards. Energen intends to fully reserve this asset until it is determined that it is more likely than not that the asset can be realized through future taxable income in the respective state taxing jurisdictions. No other valuation allowance with respect to deferred taxes is deemed necessary as Energen anticipates generating adequate future taxable income from the reversals of its existing taxable temporary differences to realize the benefits of all remaining deferred tax assets on the consolidated balance sheets.

Total income tax expense from continuing operations differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:

Years ended December 31, (in thousands)	2015			2014			2013
Income tax expense (benefit) at statutory federal income tax rate	$	(518,258	)	$	49,130		$	75,671
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	(14,112		)	93			1,461
Impact of state law changes	(3,075		)	(121		)	(1,966		)
Impact of state deferred tax revaluation on San Juan properties	(1,241		)	(8,382		)	—
401(k) stock dividend deduction	—			(232		)	(449		)
Other, net	1,681			240			(394		)
Total income tax expense (benefit)	$	(535,005	)	$	40,728		$	74,323
Effective income tax rate (%)	36.13			29.01			34.38

In addition to other changes in state apportionment reflected in the state income taxes, net of federal income tax benefit above,Energen recognized a $1.2 million and an $8.4 million income tax benefit during the 4th quarter of 2015 and 2014, respectively, as a result of re-measuring its state deferred tax liabilities. This re-measurement reflected the state apportionment changes related to certain San Juan Basin properties designated as held for sale as of December 31, 2015, and 2014. 

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A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows:

(in thousands)
Balance as of December 31, 2012	$	12,555
Additions based on tax positions related to the current year	4,546
Additions for tax positions of prior years	366
Reductions for tax positions of prior years	(46		)
Lapse of statute of limitations	(1,435		)
Balance as of December 31, 2013	15,986
Additions based on tax positions related to the current year	3,873
Additions for tax positions of prior years	19
Reductions for tax positions of prior years	(954		)
Lapse of statute of limitations	(1,394		)
Balance as of December 31, 2014	17,530
Additions based on tax positions related to the current year	2,378
Reductions based on tax positions related to the current year	(6,589		)
Reductions for tax positions of prior years	(345		)
Lapse of statute of limitations	(1,785		)
Balance as of December 31, 2015	$	11,189

The amount of unrecognized tax benefits at December 31, 2015 that would favorably impact Energen’s effective tax rate, if recognized, is $3 million. Energen recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2015, 2014, and 2013, Energen recognized approximately $2,000 of income, $27,000 of expense and $15,000 of expense for interest (net of tax benefit) and penalties, respectively. Energen had approximately $0.2 million and $0.2 million for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2015 and 2014, respectively.

Energen’s tax returns for years 2012-2014 remain open and subject to examination by the IRS and major state taxing jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations is highly uncertain, Energen does not expect that the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

5. EMPLOYEE BENEFIT PLANS

Plan Terminations: In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015 and distributed benefits in December 2015.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 and with the remainder to be paid in the first quarter of 2016. In connection with the termination of these plans, Energen has also classified approximately $3.3 million as of December 31, 2015 of its investment in a Rabbi Trust from other long term assets to prepayments and other assets in the accompanying balance sheets to reflect its intent to utilize these assets to partially fund the estimated payments in the first quarter of 2016.

Effective April 30, 2014, Energen separated its defined benefit non-contributory pension plan and its postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan reflecting the separation of assets and obligations in accordance with ERISA provisions. Energen remeasured the plans using current assumptions.

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Benefit Obligations: The following table sets forth the combined funded status of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in Energen’s consolidated financial statements.

As of December 31, (in thousands)	2015			2014			2015			2014
	Pension						Postretirement Benefits
Accumulated benefit obligation	$	15,729		$	107,669
Benefit obligation:
Balance at beginning of period	$	107,669		$	266,294		$	11,127		$	33,224
Service cost	—			8,329			392			262
Interest cost	816			5,325			466			716
Actuarial (gain) loss	(683		)	9,078			(1,185		)	6,385
Plan amendments	—			—			(4,071		)	—
Curtailment gain	—			(8,496		)	—			—
Transfer in connection with the sale of Alagasco	—			(124,783		)	—			(28,648		)
Termination benefit charge	—			2,477			—			—
Retiree drug subsidy program	—			—			—			48
Benefits paid	(92,073		)	(50,555		)	(241		)	(860		)
Balance at end of period	$	15,729		$	107,669		$	6,488		$	11,127
Plan assets:
Fair value of plan assets at beginning of period	$	67,542		$	193,457		$	10,693		$	55,459
Actual return (loss) on plan assets	(289		)	5,359			(83		)	(331		)
Employer contributions	24,847			19,164			—			21
Transfer in connection with the sale of Alagasco	—			(99,883		)	—			(43,596		)
Benefits paid	(92,073		)	(50,555		)	(241		)	(860		)
Fair value of plan assets at end of period	$	27		$	67,542		$	10,369		$	10,693
Funded status of plans	$	(15,702	)	$	(40,127	)	$	3,881		$	(434	)

Noncurrent assets	$	—		$	—		$	3,881		$	—
Current liabilities	(15,702		)	(24,626		)	—			—
Noncurrent liabilities	—			(15,501		)	—			(434		)
Net asset (liability) recognized	$	(15,702	)	$	(40,127	)	$	3,881		$	(434	)
Amounts recognized to accumulated other comprehensive income:
Prior service credit, net of taxes	$	—		$	—		$	(2,646	)	$	—
Net actuarial loss, net of taxes	2,179			22,246			205			624
Total accumulated other comprehensive income (loss)	$	2,179		$	22,246		$	(2,441	)	$	624

Other investment assets designated for payment of the nonqualified supplemental retirement plans were as follows:

	December 31, 2015
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	$	3,308	$	—	$	3,308
Total	$	3,308	$	—	$	3,308

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	December 31, 2014
(in thousands)	Level 1		Level 2		Total
Fixed income	$	—	$	4,255	$	4,255
Cash and cash equivalents	9,929		—		9,929
Total	$	9,929	$	4,255	$	14,184

While intended for payment of the nonqualified supplemental retirement plan benefits, these assets remain subject to the claims of Energen’s creditors and are not recognized in the funded status of the plan. These assets are recorded at fair value and included in prepayments and other and other assets in the consolidated balance sheets.

The components of net periodic benefit cost from continuing operations were as follows:

Years ended December 31, (in thousands)	2015			2014			2013
Pension Plans
Components of net periodic benefit cost:
Service cost	$	—		$	6,808		$	5,196
Interest cost	816			4,498			4,496
Expected long-term return on assets	—			(4,386		)	(5,225		)
Prior service cost amortization	—			202			246
Actuarial loss amortization	737			4,995			6,919
Termination benefit charge	—			2,477			—
Settlement charge	29,767			4,082			161
Curtailment expense (gain)	—			254			(4		)
Net periodic expense	$	31,320		$	18,930		$	11,789
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	392		$	253		$	386
Interest cost	466			661			645
Expected long-term return on assets	(457		)	(1,122		)	(787		)
Actuarial gain amortization	—			(653		)	(28		)
Transition obligation amortization	—			44			229
Net periodic (income) expense	$	401		$	(817	)	$	445

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Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows:

Years ended December 31, (in thousands)	2015			2014			2013
Pension Plans
Net actuarial (gain) loss experienced during the year	$	(394	)	$	10,495		$	(14,138	)
Net actuarial loss recognized as expense	(30,478		)	(25,433		)	(8,934		)
Prior service cost recognized as expense	—			(246		)	(311		)
Curtailment loss	—			(8,749		)	—
Total recognized in other comprehensive income (loss)	(30,872		)	(23,933		)	(23,383		)
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	(645	)	$	7,649		$	(8,057	)
Prior service credit during the year	(4,071		)	—			—
Net actuarial gain recognized as expense	—			1,908			550
Transition obligation recognized as expense	—			(48		)	(283		)
Total recognized in other comprehensive income (loss)	$	(4,716	)	$	9,509		$	(7,790	)

In the year ended December 31, 2015, Energen incurred settlement charges of $27.3 million for the payment of lump sums from the qualified defined benefit pension plans. Also in the first quarter of 2015, Energen incurred a settlement charge of $2.5 million for the payment of lump sums from the non-qualified supplemental retirement plans.

During the year ended December 31, 2014, Energen incurred settlement charges of $7.6 million for the payment of lump sums from the qualified defined benefit pension plans of which $3.7 million is included in discontinued operations. Also during 2014, Energen incurred settlement charges of $0.4 million for the payment of lump sums from the non-qualified supplemental retirement plans. In the fourth quarter of 2014, Energen incurred a settlement charge of $1.8 million for the payment of lump sums from the non-qualified supplemental retirement plans which is included in discontinued operations. In the fourth quarter of 2014, Energen recognized a termination benefit charge of $2.5 million to provide for early retirement of certain non-highly compensated employees. In conjunction with the sale of Alagasco, Energen recognized a curtailment loss of $0.3 million in the fourth quarter of 2014.

For the year ended December 31, 2013, Energen incurred settlement charges of $0.6 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.2 million was expensed and $0.4 million was recognized as a regulatory asset at Alagasco. In conjunction with the sale of its Black Warrior Basin coalbed methane properties in Alabama, Energen recognized a curtailment gain of $1.2 million in the fourth quarter of 2013.

Estimated amounts to be amortized, including settlement charges, from accumulated other comprehensive income into pension cost during 2016 are included in the table below.

(in thousands)
Amortization of net actuarial loss	$	3,352

Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2016 are included in the table below.

(in thousands)
Amortization of prior service credit	$	(515	)

Energen has a long-term disability plan covering most employees. Energen had expense of $0.2 million for each of the years ended December 31, 2015, 2014 and 2013.

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Assumptions: The weighted average rate assumptions to determine net periodic benefit costs were as follows:

Years ended December 31,	2015		2014		2013
Pension Plans
Discount rate	0.96	%	3.66	%	3.63	%
Expected long-term return on plan assets	—	%	7.00	%	7.00	%
Rate of compensation increase for pay-related plans	—	%	3.63	%	3.71	%
Postretirement Benefit Plans
Discount rate	4.25	%	4.88	%	4.36	%
Expected long-term return on plan assets	6.20	%	7.00	%	7.00	%
Rate of compensation increase	—	%	3.60	%	3.70	%

The pension benefit obligation as of December 31, 2014 represents the present value of the estimated cost of settling the benefit obligation of the plan. For our defined benefit pension plan, we discounted the estimated termination liability using the one year spot rate of 0.70 percent. For the year ended December 31, 2015, the discount rate shown above represents the weighted average for the nonqualified supplemental retirement plan. The discount rate shown below represents the weighted average for both the defined qualified and nonqualified supplemental retirement plans for the year ended December 31, 2014. For the year ended December 31, 2015, the expected long-term return on plan assets no longer applies for our defined benefit pension plan as the assets of the nonqualified supplemental retirement plan are not considered qualifying assets. As the plans were frozen as of December 31, 2014, the rate of compensation increase no longer applies for any of the plans. The weighted average assumptions used to determine the benefit obligations at the measurement date were as follows:

Years ended December 31,	2015		2014
Pension Plans
Discount rate	3.90	%	0.96	%
Postretirement Benefit Plans
Discount rate	4.70	%	4.25	%

The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows:

As of December 31,	2015		2014
Health care cost trend rate assumed for next year	7.75	%	7.25	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2026		2021

Health care costs trend rates will not have a material impact to the accumulated postretirement benefit obligation due to the separation of assets and obligations of the postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan. Employees remaining at Energen will receive a fixed postretirement benefit.

Investment Strategy: For our postretirement benefit plan assets, we continue to employ a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.

Energen seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, commodity or class of investment fund.

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The Company’s weighted average plan asset allocations by asset category were as follows:

	Pension						Postretirement Benefits
As of December 31,	Target		2015		2014		Target		2015		2014
Asset category:
Equity securities	—	%	—	%	—	%	56	%	56	%	60	%
Debt securities	—	%	—	%	—	%	44	%	44	%	40	%
Cash and cash equivalents	100	%	100	%	100	%	—	%	—	%	—	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

Equity securities for postretirement benefits do not include the Company’s common stock.

Plan assets included in the funded status of the pension plans were as follows:

	December 31, 2015
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	27		$	—	$	27
Total	$	27	$	—	$	27

	December 31, 2014
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	$	67,542	$	—	$	67,542
Total	$	67,542	$	—	$	67,542

Plan assets included in the funded status of the postretirement benefit plans were as follows:

	December 31, 2015
(in thousands)	Level 1		Level 2		Total
United States equities	$	4,185	$	—	$	4,185
Global equities	1,650		—		1,650
Fixed income	—		4,534		4,534
Total	$	5,835	$	4,534	$	10,369

	December 31, 2014
(in thousands)	Level 1		Level 2		Total
United States equities	$	4,715	$	—	$	4,715
Global equities	1,711		—		1,711
Fixed income	—		4,267		4,267
Total	$	6,426	$	4,267	$	10,693

Energen had no Level 3 postretirement benefit plan assets. United States equities consists of mutual funds with varying strategies. These funds invest largely in medium to large capitalized companies with exposure blending growth, market-oriented and value styles. Additional fund investments include small capitalization companies, and certain of these funds utilize tax-sensitive management approaches. Global equities are mutual funds that invest in non-United States securities broadly diversified across most developed markets with exposure blending growth, market-oriented and value styles. Fixed income securities are high-quality short-duration securities including investment-grade market sectors with tactical investments in non-investment grade sectors.

Cash Flows: The Company expects to make benefit payments, which will be partially funded by the Rabbi Trust, of approximately $14.6 million during 2016 with respect to the termination of the nonqualified supplemental retirement plans.

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Due to restructuring of our plans, Energen no longer qualifies for benefits related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows:

(in thousands)	Pension Benefits	Postretirement Benefits
2016	$14,606	$198
2017	$117	$213
2018	$114	$245
2019	$110	$258
2020	$107	$289
2021-2025	$472	$1,769

6. COMMON STOCK PLANS

Energen Employee Savings Plan (ESP): In October 2014, Energen’s Board of Directors amended and restated the ESP to make certain benefit design changes effective January 1, 2015. The benefit design changes include an increase in the percentage of Energen match and other contributions. A majority of our employees are eligible to participate in the ESP by electing to contribute a portion of their compensation to the ESP. Energen may match a percentage of the contributions and make these contributions in Energen common stock or in funds for the purchase of Energen common stock. Employees may diversify 100 percent of their ESP Energen stock account into other ESP investment options. The ESP also contains employer supplemental contributions. Effective January 1, 2015, the Company match will no longer be contributed in Energen common stock. Expense associated with Energen contributions to the ESP was $5.7 million, $3.7 million and $3.7 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Stock Incentive Plan: The Stock Incentive Plan provided for the grant of performance share awards and restricted stock units and restricted stock. The Stock Incentive Plan also provided for the grant of non-qualified stock options and incentive stock options to officers and key employees. Energen has typically funded performance share obligations, restricted stock obligations and options through original issue shares and restricted stock through treasury shares. Under the Stock Incentive Plan, established in 1997, 8,600,000 shares of Energen common stock were reserved for issuance, adjusted for stock splits, with 2,294,740 remaining for issuance as of December 31, 2015.

Performance Share Awards: The Stock Incentive Plan provided for the grant of performance share awards to eligible employees based on predetermined Energen performance criteria at the end of an award period. The Stock Incentive Plan provided that payment of earned performance share awards be made in the form of Energen common stock.

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A summary of performance share award activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 is presented below:

	Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2012	—		$	—
Granted (two-year vesting period)	86,221		61.14
Granted (three-year vesting period)	82,606		62.96
Forfeited	(8,008	)	60.03
Nonvested at December 31, 2013	160,819		62.13
Granted (two-year vesting period)	937		131.56
Granted (three-year vesting period)	65,309		93.49
Vested and paid	(14,097	)	70.06
Nonvested at December 31, 2014	212,968		71.53
Granted (three-year vesting period)	120,372		83.94
Vested and paid	(77,257	)	61.36
Nonvested at December 31, 2015	256,083		$	80.43

Energen recorded expense of $6.7 million, $6.2 million and $3.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, for performance share awards with a related deferred income tax benefit of $2.4 million, $2.3 million and $1.4 million. As of December 31, 2015, there was $8.9 million of total unrecognized compensation cost related to performance share awards. These awards have a remaining weighted average requisite service period of 1.66 years.

Restricted Stock: In addition, the Stock Incentive Plan provided for the grant of restricted stock and restricted stock units (restricted stock awards) which have been valued based on the quoted market price of Energen’s common stock at the date of grant. Restricted stock awards vest within three years from grant date. A summary of restricted stock award activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 is presented below:

	Stock Incentive Plan
	Awards		Weighted Average Price
Nonvested at December 31, 2012	11,115		$	45.24
Restricted stock granted	52,650		52.34
Forfeited	(1,247	)	48.36
Nonvested at December 31, 2013	62,518		51.16
Restricted stock units granted	48,904		71.91
Vested	(11,848	)	65.94
Nonvested at December 31, 2014	99,574		59.60
Restricted stock units granted	99,814		65.15
Vested	(14,446	)	53.20
Nonvested at December 31, 2015	184,942		$	63.09

Energen recorded expense of $6.0 million, $3.2 million and $1.9 million for the years ended December 31, 2015, 2014 and 2013, respectively, related to restricted stock awards, with a related deferred income tax benefit of $2.1 million, $1.2 million and $0.7 million, respectively. As of December 31, 2015, there was $1.9 million of total unrecognized compensation cost related to nonvested restricted stock awards recorded in premium on capital stock. These awards have a remaining requisite service period of 1.75 years.

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Stock Options: The Stock Incentive Plan provided for the grant of non-qualified stock options, incentive stock options, or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provided for the purchase of Energen common stock at not less than the fair market value on the date the option was granted. The sale or transfer of the shares is limited during certain periods. All outstanding options are incentive or non-qualified, vest within three years from date of grant and expire 10 years from the grant date.

A summary of stock option activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 are presented below:

	Stock Incentive Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2012	1,648,475		$	47.58
Granted	137,762		49.22
Exercised	(590,119	)	40.92
Forfeited	(5,074	)	51.85
Outstanding at December 31, 2013	1,191,044		51.06
Granted	110,307		72.55
Exercised	(544,280	)	50.09
Outstanding at December 31, 2014	757,071		54.88
Exercised	(23,680	)	41.42
Outstanding at December 31, 2015	733,391		$	55.32
Exercisable at December 31, 2013	713,445		$	49.80
Exercisable at December 31, 2014	454,938		$	51.88
Exercisable at December 31, 2015	622,156		$	53.80

Energen uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values:

Grant date	4/15/2014	1/22/2014	10/15/2013	1/24/2013
Awards granted	2,439	107,868	3,686	134,076
Fair market value of stock option at grant	$32.22	$27.57	$30.53	$16.66
Expected life of award	5.8 years	5.8 years	5.8 years	5.8 years
Risk-free interest rate	1.93%	2.06%	1.79%	1.01	%
Annualized volatility rate	40.7%	40.7%	40.6%	40.3	%
Dividend yield	0.2%	0.8%	0.7%	1.2	%

Energen recorded stock option expense of $0.4 million, $2.9 million and $3.4 million during the years ended December 31, 2015, 2014 and 2013, respectively, with a related deferred tax benefit of $0.1 million, $1.1 million and $1.3 million, respectively.

The total intrinsic value of stock options exercised during the year ended December 31, 2015, was $0.7 million. During the year ended December 31, 2015, Energen received cash of $1.0 million from the exercise of stock options. Total intrinsic value for outstanding options as of December 31, 2015, was $0.3 million and $0.3 million for exercisable options. The fair value of options vested for the year ended December 31, 2015 was $3.7 million. As of December 31, 2015, there was $0.1 million of unrecognized compensation cost related to outstanding nonvested stock options.

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The following table summarizes options outstanding as of December 31, 2015:

Stock Incentive Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
$46.45	19,990	1.00 year
$60.56	48,560	2.00 years
$29.79	24,291	3.00 years
$46.69	26,481	4.00 years
$54.99	104,841	5.00 years
$54.11	271,164	6.00 years
$48.36	124,071	7.00 years
$80.48	3,686	7.79 years
$72.39	107,868	8.00 years
$79.63	2,439	8.00 years
$29.79-$80.48	733,391	5.76 years

The weighted average remaining contractual life of currently exercisable stock options is 5.43 years as of December 31, 2015.

Stock Appreciation Rights Plan: The Energen Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Energen common stock. Officers of Energen are not eligible to participate in this Plan. These awards are liability awards which settle in cash and are remeasured each reporting period until settlement. These awards have a three year requisite service period.

A summary of stock appreciation rights activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 are presented below:

	Stock Appreciation Rights Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2012	653,030		$	44.14
Granted	88,000		48.36
Exercised/forfeited	(363,653	)	39.66
Outstanding at December 31, 2013	377,377		49.48
Granted	62,749		72.39
Exercised/forfeited	(164,976	)	52.37
Outstanding at December 31, 2014	275,150		52.96
Exercised/forfeited	(10,283	)	55.18
Outstanding at December 31, 2015	264,867		$	52.88

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Energen issued the following awards with stock appreciation rights. Energen uses the Black-Scholes pricing model to calculate the fair values of the rights awarded. On December 19, 2013, we modified certain stock appreciation rights subsequent to the original grant date. For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2015:

Grant date	1/22/2014	1/22/2014	1/24/2013	1/24/2013	1/24/2013	1/26/2011
		(modified)		(modified)	(modified)
Awards granted	62,227	522	83,654	768	3,578	182,199
Fair market value of award	$5.11	$1.67	$8.30	$5.64	$4.24	$4.80
Expected life of award	4.56 years	2.13 years	3.57 years	2.13 years	1.50 years	2.53 years
Risk-free interest rate	1.67%	1.11%	1.43%	1.11%	0.80%	1.23%
Annualized volatility rate	33.4%	33.4%	33.4%	33.4%	33.4%	33.4%
Dividend yield	0.20%	0.20%	0.20%	0.20%	0.20%	0.20%

Grant date	1/26/2011	1/27/2010	1/28/2009	2/4/2008	2/1/2007
	(modified)
Awards granted	7,785	171,749	305,257	67,093	85,906
Fair market value of award	$2.74	$5.95	$13.18	$0.81	$2.16
Expected life of award	1.50 years	2.04 years	1.54 years	1.05 years	0.54 years
Risk-free interest rate	0.80%	1.08%	0.82%	0.65%	0.54%
Annualized volatility rate	33.4%	33.4%	33.4%	33.4%	33.4%
Dividend yield	0.20%	0.20%	0.20%	0.20%	0.20%

Income associated with stock appreciation rights of $3.2 million and $0.4 million was recorded for the years ended December 31, 2015 and 2014. Expense associated with stock appreciation rights of $9.9 million was recorded for the year ended 2013. During the year ended December 31, 2015, the total intrinsic value of stock appreciation rights exercised was $0.1 million. During the year ended December 31, 2015, Energen paid $0.1 million in settlement of stock appreciation rights.

Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provided for the grant of stock equivalent units which may include market conditions. Officers of Energen are not eligible to participate in this Plan. These awards are liability awards which are remeasured each reporting period and settle in cash at completion of the vesting period. Stock equivalent units with service conditions were valued based on Energen’s stock price at the end of the period adjusted to remove the present value of future dividends.

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A summary of Petrotech unit activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 are presented below:

	Petrotech Incentive Plan
	Shares
Outstanding at December 31, 2012	141,243
Granted (three-year vesting period)	92,418
Granted (17 month vesting period)	2,952
Paid	(36,792	)
Forfeited	(26,529	)
Outstanding at December 31, 2013	173,292
Granted	76,084
Paid	(4,431	)
Forfeited	(31,075	)
Outstanding at December 31, 2014	213,870
Granted (three-year vesting period)	128,519
Granted (two-year vesting period)	297
Granted (16 month vesting period)	1,648
Paid	(78,430	)
Forfeited	(22,158	)
Outstanding at December 31, 2015	243,746

Energen recognized expense of $3.0 million, $4.5 million and $6.2 million during 2015, 2014 and 2013, respectively, related to these units.

1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allowed officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of Energen’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. Energen has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust’s assets remain subject to the claims of our creditors. Amounts earned under the 1997 Deferred Compensation Plan and invested in Energen common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the consolidated statements of shareholders’ equity. As of December 31, 2015 there were 576,850 shares reserved for issuance from the 1997 Deferred Compensation Plan.

1992 Energen Corporation Directors Stock Plan: In 1992 Energen adopted the Energen Corporation Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Energen common stock. Under the Plan, 11,550 shares, 10,360 shares and 13,500 shares were awarded during the years ended December 31, 2015, 2014 and 2013, respectively, leaving 116,374 shares reserved for issuance as of December 31, 2015.

Stock Repurchase Authorization: By resolution adopted October 22, 2014, the Board of Directors authorized Energen to repurchase up to 3,600,000 shares of Energen common stock. The resolution does not have an expiration date and does not limit Energen’s authorization to acquire shares in connection with tax withholdings and payment of exercise price on stock compensation plans. For the year ended December 31, 2014, Energen repurchased and retired 226,839 shares for $14.9 million pursuant to our repurchase authorization. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2015 and 2013. As of December 31, 2015, a total of 3,373,161 shares remain authorized for future repurchase. Energen also from time to time acquires shares in connection with participant elections under Energen’s stock compensation plans. For the years ended December 31, 2015, 2014 and 2013, Energen acquired 73,126 shares, 32,768 shares and 14,766 shares, respectively, in connection with its stock compensation plans.

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7. DERIVATIVE COMMODITY INSTRUMENTS

The following table details gain (loss) on derivative instruments, net, as follows:

Years ended December 31, (in thousands)	2015			2014		2013
Open non-cash mark-to-market gains (losses) on derivative instruments	$	(281,752	)	$	315,445	$	(47,832	)
Closed gains (losses) on derivative instruments	397,045			19,574		(2,192		)
Gain (loss) on derivative instruments, net	$	115,293		$	335,019	$	(50,024	)

The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets:

(in thousands)	December 31, 2015
								Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	72,563	$	(15,600	)	$	56,963	$	—	$	—	$	56,963
Liabilities
Derivative instruments	16,059		(15,600		)	459		—		—		459
Total derivatives	$	56,504	$	—		$	56,504	$	—	$	—	$	56,504

(in thousands)	December 31, 2014
								Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	339,977	$	(17,640	)	$	322,337	$	—	$	—	$	322,337
Liabilities
Derivative instruments	18,628		(17,640		)	988		—		—		988
Total derivatives	$	321,349	$	—		$	321,349	$	—	$	—	$	321,349

*All derivative instruments were current at December 31, 2015 and 2014.

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. Additionally, Energen is at risk of economic loss based upon the creditworthiness of our counterparties. We were in a net gain position with eleven of our active counterparties and in a net loss position with the remaining one at December 31, 2015. The largest counterparty net gain positions at December 31, 2015, Morgan Stanley Capital Group Inc. and BP Corporation North America Inc., constituted approximately $18.1 million, and $10.7 million, respectively, of Energen’s total net gain on fair value of derivatives.

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The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:

Years ended December 31, (in thousands)	Location on Statements of Income	2014		2013
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $23 and ($6,660)	—	$	37	$	(10,866	)
Gain reclassified from accumulated other comprehensive income into income (effective portion)	Gain (loss) on derivative instruments, net	$	21,612	$	34,293
Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Gain (loss) on derivative instruments, net	$	—	$	835

The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:

Years ended December 31, (in thousands)	Location on Statements of Income	2015		2014		2013
Gain (loss) recognized in income on derivatives	Gain (loss) on derivative instruments, net	$	115,293	$	313,408	$	(73,980	)

As of December 31, 2015, Energen entered into the following transactions for 2016 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Oil
2016	1,086	MBbl	$63.80 Bbl	NYMEX Swaps
Oil Basis Differential
2016	7,524	MBbl	$(1.92) Bbl	WTI/WTI Basis Swaps
2016	2,117	MBbl	$(1.63) Bbl	WTS/WTI Basis Swaps
WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

As of December 31, 2015, the maximum term over which Energen has hedged exposures to the variability of cash flows is through December 31, 2016.

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8. FAIR VALUE MEASUREMENTS

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Energen classifies the fair value of multiple derivative instruments executed under master netting arrangements as net derivative assets and liabilities. The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis:

	December 31, 2015
(in thousands)	Level 2		Level 3			Total
Assets
Derivative instruments	$	69,864	$	(12,901	)	$	56,963
Liabilities
Derivative instruments	2,699		(3,158		)	(459		)
Net derivative asset (liability)	$	72,563	$	(16,059	)	$	56,504

	December 31, 2014
(in thousands)	Level 2		Level 3			Total
Assets
Derivative instruments	$	294,865	$	27,472		$	322,337
Liabilities
Derivative instruments	2,048		(3,036		)	(988		)
Net derivative asset	$	296,913	$	24,436		$	321,349

At December 31, 2015, Energen had interest rate swap agreements with a notional value of $66.7 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 1.0425 percent. The fair value of our interest rate swap was a $0.2 million and a $0.8 million liability at December 31, 2015 and 2014, respectively, and are classified as Level 2 fair value liabilities. The fair value of our interest rate swaps are recognized on a gross basis in accounts payable on the consolidated balance sheet.

Energen prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its Level 3 instruments. We estimate that a 10 percent increase or decrease in commodity prices would result in an approximate $0.1 million change in the fair value of open Level 3 derivative contracts and to the results of operations.

The table below sets forth a summary of changes in the fair value of Energen’s Level 3 derivative commodity instruments as follows:

Years ended December 31, (in thousands)	2015			2014			2013
Balance at beginning of period	$	24,436		$	18,289		$	89,019
Realized gains	13,145			22,208			55,210
Unrealized gains (losses) relating to instruments held at the reporting date*	(40,495		)	2,981			(71,367		)
Settlements during period	(13,145		)	(19,042		)	(54,573		)
Balance at end of period	$	(16,059	)	$	24,436		$	18,289

*Includes $16.1 million in mark-to-market losses, $20.2 million in mark-to-market gains and $7.6 million in mark-to-market losses for the years ended December 31, 2015, 2014 and 2013, respectively.

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The tables below set forth quantitative information about Energen’s Level 3 fair value measurements of derivative commodity instruments as follows:

(in thousands, except price data)	Fair Value as of December 31, 2015			Valuation Technique*	Unobservable Input*	Range
Oil Basis - WTI/WTI
2016	$	(13,181	)	Discounted Cash Flow	Forward Basis	($0.07 - $0.28) Bbl
Oil Basis - WTS/WTI
2016	$	(2,878	)	Discounted Cash Flow	Forward Basis	($0.19 - $0.31) Bbl

*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in Energen’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values.

Asset retirement obligations:Energen’s asset retirement obligations (ARO) primarily relate to the future plugging, abandonment and reclamation of wells and facilities. We recognize a liability for the fair value of the ARO in the periods incurred. See Note 13, Asset Retirement Obligations, for further discussion related to these ARO’s. These assumptions are classified as Level 3 fair value.

Asset Impairments: We monitor our oil and natural gas properties as well as the market and business environments in which we operate and make assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected field production performance. If a material event occurs, Energen makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, we will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows. Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future.

These assumptions are classified as Level 3 fair value. See Note 14, Asset Impairment, for impairments recognized by Energen during the years ended December 31, 2015, 2014 and 2013.

Financial Instruments Not Carried at Fair Value

The stated value of cash and cash equivalents, short-term investments, accounts receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. Short-term investments purchased and sold during 2015 of $919 million are not considered readily convertible into cash and accordingly are not classified in cash and cash equivalents. In addition, the Company also invested in certain short-term investments that qualify and were classified as cash and cash equivalents. The fair value of Energen’s long-term debt, including the current portion and notes payable to banks, approximates $690.1 million and $993.7 million and has a carrying value of $776.5 million and $1,039.0 million at December 31, 2015 and 2014, respectively. The fair values are based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

Concentration of Credit Risk

Revenues and related accounts receivable from oil and natural gas operations primarily are generated from the sale of produced oil and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect Energen’s overall exposure to credit risk, either positively or negatively, in that our oil and natural gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen considers the credit quality of its purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The two largest purchasers of Energen’s oiland natural gas, Plains Marketing, LP (Plains) and Shell Trading (US) Company, accounted for approximately 47 percent and 21 percent, respectively, of Energen’s accounts receivable for commodity sales as of December 31, 2015. Energen’s other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2015. During the year ended December 31, 2015, Plains accounted for approximately 33 percent of total revenues, excluding the impact of non-cash mark-to-market open derivatives. All other oil and natural gas purchasers each accounted for less than 10 percent of total revenues for the year ended December 31, 2015.

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9. EXPLORATORY COSTS

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:

Years ended December 31, (in thousands)	2015			2014			2013
Capitalized exploratory well costs at beginning of period	$	119,439		$	57,600		$	79,791
Additions pending determination of proved reserves	634,908			946,751			421,599
Reclassifications due to determination of proved reserves	(650,759		)	(882,254		)	(442,909		)
Exploratory well costs charged to expense	—			(2,658		)	(881		)
Capitalized exploratory well costs at end of period	$	103,588		$	119,439		$	57,600

The following table sets forth capitalized exploratory wells costs:

(in thousands)	December 31, 2015		December 31, 2014
Exploratory wells in progress (drilling rig not released)	$	1,760	$	18,781
Capitalized exploratory well costs for a period of one year or less	101,828		100,658
Total capitalized exploratory well costs	$	103,588	$	119,439

No wells were capitalized for a period greater than one year as of December 31, 2015 and 2014. At December 31, 2015, Energen had 40 gross exploratory wells either drilling or waiting on results from completion and testing. These wells are located in the Permian Basin.

10. RECONCILIATION OF EARNINGS PER SHARE

Years ended December 31,
(in thousands, except per share amounts)				2015						2014					2013
	Net Loss			Shares	Per Share Amount			Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	(945,731	)	76,078	$	(12.43	)	$	568,032	72,897	$	7.79	$	204,554	72,318	$	2.83
Effect of dilutive securities
Stock options				—						216					112
Non-vested restricted stock				—						58					20
Performance share awards				—						104					21
Diluted EPS	$	(945,731	)	76,078	$	(12.43	)	$	568,032	73,275	$	7.75	$	204,554	72,471	$	2.82

In periods of loss, shares that otherwise would have been included in diluted average commons shares outstanding are excluded. Energen had 355,915 of excluded shares for the year ended December 31, 2015.

Energen had the following shares that were excluded from the computation of diluted EPS, as inclusion would be anti-dilutive.

Years ended December 31, (in thousands)	2015	2014	2013
Stock options	114	114	134
Non-vested restricted stock	—	3	7
Performance share awards	—	2	4

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11. EQUITY OFFERING

During the second quarter of 2015, Energen issued 5,700,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $398.6 million, after deducting offering expenses. Net proceeds from this offering were used to repay borrowings under our credit facility and for general corporate purposes.

12. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Under various agreements for third-party gathering, treatment, transportation or other services, Energen is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 5.8 MMBOE through October 2020.

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen and Energen Resources. Historically, the cost of environmental compliance has not materially affected our financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency regarding the Reef Environmental Site in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party under The Comprehensive Environmental Response, Compensation, and Liability Act for the cleanup of the Site. In 2008, Energen hired a third party to transport approximately 3,000 gallons of non-hazardous wastewater to Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Due to its one time use of Reef Environmental for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings and we have accrued a provision for our estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. We recognize a liability for contingencies, including an estimate of legal costs to be incurred, when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results.

On November 4, 2015, Energen Resources filed a suit against Endeavor Energy Resources. L.P. in the District Court of Howard County, Texas, to remove a cloud on the title to approximately 10,000 acres leased by Energen Resources in that county. Energen Resources believes the cloud on title arises from a prior, unreleased but partially terminated oil and gas lease covering the leased lands. The defendant in the action filed a counterclaim alleging Energen Resources tortiously interfered with a prospective contract. The counterclaim seeks $300 million in damages. Energen Resources believes the counterclaim is without merit, and no amount has been accrued as of December 31, 2015. Energen Resources intends to pursue a favorable ruling in the quiet title action and vigorously defend against the counterclaim.

We recently became aware that Energen Resources may be one of multiple defendants in a Petition for Damages to the Cameron Parish Coastal Zone filed by the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron, State of Louisiana alleging violation of Louisiana’s coastal zone management laws. We are in the very preliminary stages of evaluating our exposure, and no amount has been accrued as of December 31, 2015

New Mexico Audits: In 2011, Energen Resources received an Order to Perform Restructured Accounting and Pay Additional Royalties (the Order), following an audit performed by the Taxation and Revenue Department (the Department) of the State of New Mexico on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The Order addressed ONRR’s efforts to change accounting and reporting practices, and to unbundle fees charged by third parties that gather, compress and transport natural gas production. ONRR now maintains that all or some of such fees are not deductible.

Energen Resources appealed the Orderin 2011 and in July 2012, on a motion from ONRR, the Orderwas remanded. In August 2014, ONRR issued its Revised Order that is now under appeal. In the Revised Order, ONRR has ordered that Energen pay additional royalties on production from certain federal leases in the amount of $129,700. Energen estimates that application of

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the Revised Order to all of the Company’s federal leases would result in ONRR claims up to approximately $24 million, plus interest and penalties from 2004 forward. ONRR began implementing its unbundling initiative in 2010, but seeks to implement its revisions retroactively, despite the fact that they conflict with previous audits, allowances and industry practice. Energen continues to vigorously contest the Revised Order and the findings. Management is unable, at this time, to determine a range of reasonably possible losses, and no amount has been accrued as of December 31, 2015.

Lease Obligations: Energen’s total lease payments included as operating lease expense were $23.7 million, $24.1 million and $25.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. Minimum future rental payments required after 2015 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2016	2017	2018	2019	2020	2021 and thereafter
$2,537	$2,574	$2,537	$2,431	$—	$—

13. ASSET RETIREMENT OBLIGATIONS

Energen’s asset retirement obligations primarily relate to the future plugging, abandonment and reclamation of wells and facilities. We recognize a liability for the fair value of the ARO in the periods incurred. The ARO fair value liability is determined by calculating the present value of the estimated future cash outflows we expect to incur to plug, abandon and reclaim our producing properties at the end of their productive lives, and is recognized on a discounted basis incorporating an estimate of performance risk specific to Energen. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful lives of the related assets. Upon settlement of the liability, Energen may recognize a gain or loss for differences between estimated and actual settlement costs.

The following table reflects the components of the change in Energen’s ARO balance:

(in thousands)
Balance as of December 31, 2012	$	118,023
Liabilities incurred	2,772
Liabilities settled	(5,525		)
Accretion expense (including discontinued operations of $1,197)	8,192
Reclassification associated with held for sale properties*	(14,929		)
Balance as of December 31, 2013	108,533
Liabilities incurred	2,266
Liabilities settled	(1,543		)
Accretion expense (including discontinued operations of $251)	7,859
Revision in estimated cash flows	692
Reclassification associated with held for sale properties**	(23,747		)
Balance as of December 31, 2014	$	94,060
Liabilities incurred	981
Liabilities settled	(686		)
Accretion expense	7,108
Reclassification associated with held for sale properties***	(11,473		)
Balance as of December 31, 2015	$	89,990

*Asset retirement obligation associated with North Louisiana/East Texas properties.

**Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2014.

***Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2015.

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14. ASSET IMPAIRMENT

Impairments recognized by Energen during the years ended December 31, 2015, 2014 and 2013 are presented below:

Years ended December 31, (in thousands)	2015		2014		2013
Continuing operations
Permian Basin properties
Central Basin Platform	$	484,848	$	—	$	—
Delaware Basin	607,303		90,594		—
Midland Basin	—		25,776		—
San Juan Basin properties	133,055		230,315		—
Permian Basin unproved leasehold properties	29,168		64,361		13,906
San Juan Basin unproved leasehold properties	37,934		5,755		—
Total asset impairments from continuing operations	1,292,308		416,801		13,906
Discontinued operations
North Louisiana/East Texas oil and natural gas properties	—		1,936		29,794
Total asset impairments from discontinued operations	—		1,936		29,794
Total asset impairments	$	1,292,308	$	418,737	$	43,700

Non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement.

Permian Basin: For 2015, Energen recognized non-cash impairment writedowns on certain properties in the Permian Basin of $1,092.2 million to adjust the carrying amount of these properties to their fair value. We estimate future discounted cash flows in determining fair value using commodity assumptions, which are based on the commodity price curve for five years and then escalated at 3 percent through our assumed price cap. During the fourth quarter of 2015, Energen recognized non-cash impairment writedowns of $646.1 million due to commodity price declines and the related impact to our drilling plans. Our commodity price assumptions declined over the third quarter by approximately 12 percent for oil and 6 percent for natural gas in comparable periods. During the third quarter of 2015, Energen recognized non-cash impairment writedowns of $390.2 million due to commodity price declines. Our commodity price assumptions declined over the second quarter by approximately 19 percent for oil and 12 percent for natural gas in comparable periods. During the second quarter of 2015, Energen recognized non-cash impairment writedowns on certain properties in the Central Basin Platform of $51.5 million. Estimated future cash flows were revised due to the receipt of an unsolicited offer for these properties. During the first quarter of 2015, Energen recognized a non-cash impairment writedown of $4.3 million.

During the third and fourth quarters of 2014, Energen recognized non-cash impairment writedowns on certain Permian Basin properties in the Midland Basin of $25.8 million and in the Delaware Basin of $90.6 million, respectively, to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows.

Energen recognized unproved leasehold writedowns primarily on Permian Basin oil properties in the Delaware Basin of $29.2 million in 2015. During 2014, Energen recognized unproved leasehold writedowns of $64.4 million. These unproved leasehold writedowns include $55.1 million of leasehold expirations.

San Juan Basin: Energen recognized non-cash impairment writedowns on properties in the San Juan Basin of $133.1 million during the fourth quarter of 2015 to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. These remaining properties were designated as held for sale as of December 31, 2015. At December 31, 2015, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 16,930 MBOE.

During the third and fourth quarters of 2014, non-cash impairment writedowns of $142.2 million and $88.1 million, respectively, were recognized by Energen on certain natural gas properties in the San Juan Basin to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows in the third quarter and based on direct market data in the fourth quarter as these properties were designated as held for sale as of December 31, 2014. At December 31, 2014, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 69,038 MBOE.

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During 2015 and 2014, Energen recognized unproved leasehold writedowns on San Juan Basin properties of $37.9 million and $5.8 million, respectively.

North Louisiana/East Texas: In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million. The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations. Energen recognized non-cash impairment writedowns on these properties in 2014 of $1.9 million to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2014. Energen also recognized non-cash impairment writedowns on these properties of $29.8 million in 2013. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2013. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment writedowns are classified as Level 3 fair value. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

Black Warrior Basin: In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million. Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

15. ACQUISITION AND DISPOSITION OF PROPERTIES

Subsequent to December 31, 2015, Energen classified certain non-core assets in the eastern Delaware Basin as held for sale. Proved reserves associated with these Delaware Basin properties totaled 25,200 MBOE at December 31, 2015.

At December 31, 2015, our remaining San Juan Basin properties were classified as held for sale. Proved reserves associated with these San Juan Basin properties totaled 16,930 MBOE at December 31, 2015.

On March 31, 2015, Energen completed the sale of the majority of its natural gas assets in the San Juan Basin in New Mexico and Colorado (effective as of January 1, 2015) for an aggregate purchase price of $395 million. The sales proceeds were reduced by purchase price adjustments of approximately $11 million related to the operations of the San Juan Basin properties subsequent to December 31, 2014 and one-time adjustments related primarily to liabilities assumed by the buyer, which resulted in pre-tax proceeds to Energen of approximately $384 million before consideration of transaction costs of approximately $2.8 million. Energen recognized a pre-tax gain of $27.0 million on the sale. Energen used proceeds from the sale to reduce long-term indebtedness. At December 31, 2014, proved reserves associated with these San Juan Basin properties totaled 69,038 MBOE.

Energen completed an estimated total of $85.7 million in various purchases of unproved leasehold largely in the Permian Basin during 2015. During 2014, Energen completed a total of approximately $68.5 million in various purchases of unproved leasehold properties, including the October 2014, purchase of approximately 15,000 net acres of unproved leasehold in the Mancos formation oil play in the San Juan Basin for $22.8 million. During 2013, Energen also completed a total of approximately $26.8 million in various purchases of unproved leasehold properties.

16. DISCONTINUED OPERATIONS AND HELD FOR SALE PROPERTIES

As discussed in Note 15, Acquisition and Disposition of Properties, subsequent to December 31, 2015, Energen classified certain non-core assets in the eastern Delaware Basin as held for sale. Proved reserves associated with these Delaware Basin properties totaled 25,200 MBOE at December 31, 2015.

At December 31, 2015, our remaining San Juan Basin properties were classified as held for sale. Proved reserves associated with these San Juan Basin properties totaled 16,930 MBOE at December 31, 2015.

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The following table details San Juan Basin held for sale properties by major classes of assets and liabilities. Property sales in the San Juan Basin do not qualify for discontinued operations:

(in thousands)	December 31, 2015			December 31, 2014
Inventories	$	3,651		$	—
Oil and natural gas properties	305,386			1,166,124
Less accumulated depreciation, depletion and amortization	(219,059		)	(770,327		)
Other property and equipment, net	3,761			—
Total assets held for sale	93,739			395,797
Other long-term liabilities	(12,789		)	(24,230		)
Total liabilities held for sale	(12,789		)	(24,230		)
Total net assets held for sale	$	80,950		$	371,567

On September 2, 2014, Energen completed the transaction to sell Alagasco to Laclede for $1.6 billion, less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion resulting in a pre-tax gain of $726.5 million. This sale has an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. Energen’s results of operations and cash flows for the years ended December 31, 2014 and 2013 presented in our consolidated financial statements and these notes reflect Alagasco as discontinued operations.

We classified as discontinued operations interest on debt required to be extinguished, certain depreciation costs that ended at close of transaction, the related income tax impact of these items and the earnings of Alagasco. In addition, we reclassified from discontinued operations certain general and administrative expenses, other income and the related tax impact from these items. The table below provides a detail of these items included in income (loss) from discontinued operations as follows:

Years ended December 31, (in thousands)	2014			2013
Alagasco net income	$	40,646		$	57,399
Depreciation, depletion and amortization	(408		)	(598		)
General and administrative	3,337			5,894
Interest expense	(17,306		)	(13,815		)
Other income	(347		)	(1,342		)
Income tax expense	5,567			3,728
Alagasco income from discontinued operations	31,489			51,266
Energen income (loss) from discontinued operations	(2,197		)	7,813
Income from discontinued operations	$	29,292		$	59,079

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Years ended December 31, (in thousands, except per share data)	2014		2013
Natural gas distribution revenues	$	397,648	$	533,338
Oil and natural gas revenues	5,199		60,191
Total revenues	$	402,847	$	593,529
Pretax income from discontinued operations	$	47,220	$	92,253
Income tax expense	17,928		33,174
Income From Discontinued Operations	$	29,292	$	59,079
Gain on disposal of discontinued operations, net	$	724,594	$	5,605
Income tax expense	285,497		2,011
Gain on Disposal of Discontinued Operations, net	$	439,097	$	3,594
Total Income From Discontinued Operations	$	468,389	$	62,673
Diluted Earnings Per Average Common Share
Income from discontinued operations	$	0.40	$	0.81
Gain on disposal of discontinued operations, net	5.99		0.05
Total Income From Discontinued Operations	$	6.39	$	0.86
Basic Earnings Per Average Common Share
Income from discontinued operations	$	0.40	$	0.82
Gain on disposal of discontinued operations, net	6.02		0.05
Total Income From Discontinued Operations	$	6.42	$	0.87

In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million. The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations. Energen recognized non-cash impairment writedowns on these properties in 2014 of $1.9 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2014. Energen also recognized non-cash impairment writedowns on these properties of $29.8 million in 2013. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2013. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million. Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 that was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

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17. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental information concerning Energen’s cash flow activities from continuing operations was as follows:

Years ended December 31, (in thousands)	2015		2014		2013
Interest paid, net of amount capitalized	$	40,747	$	32,172	$	38,255
Income taxes paid	$	8,114	$	219,505	$	22,781
Noncash investing activities:
Accrued development, exploration costs and other capital	$	79,206	$	207,461	$	93,623
Capitalized asset retirement obligations costs	$	981	$	2,958	$	2,772
Receivable from sale of Alabama Gas Corporation	$	—	$	8,247	$	—
Noncash financing activities:
Issuance of common stock for employee benefit plans	$	5,758	$	2,448	$	1,015
Treasury stock acquired in connection with tax withholdings	$	4,722	$	2,547	$	977

18. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects:

(in thousands)	Pension and Postretirement Plans
Balance as of December 31, 2014	$	(22,870	)
Other comprehensive income before reclassifications	3,305
Amounts reclassified from accumulated other comprehensive income	19,828
Change in accumulated other comprehensive income (loss)	23,133
Balance as of December 31, 2015	$	263

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The following table provides details of the reclassifications out of accumulated other comprehensive income (loss):

Years ended December 31, (in thousands)	2015			2014			2013
				Amounts Reclassified						Line Item Where Presented
Gains (losses) on cash flow hedges:
Commodity contracts	$	—		$	21,611		$	35,684		Gain (loss) on derivative instruments, net
Interest rate swap	—			(2,280		)	(1,723		)	Interest expense
Total cash flow hedges	—			19,331			33,961
Income tax expense	—			(7,414		)	(12,957		)
Net of tax	—			11,917			21,004
Pension and postretirement plans:
Transition obligation	—			(22		)	(319		)	General and administrative
Prior service cost	—			(248		)	(257		)	General and administrative
Actuarial losses	(30,504		)	(21,932		)	(12,357		)	General and administrative
Actuarial losses on settlement charges*	—			—			(421		)	Assets held for sale
Total pension and postretirement plans	(30,504		)	(22,202		)	(13,354		)
Income tax benefit	10,676			7,771			4,674
Net of tax	(19,828		)	(14,431		)	(8,680		)
Total reclassifications for the period	$	(19,828	)	$	(2,514	)	$	12,324

*During the year ended December 31, 2013, Energen incurred settlement charges of $0.6 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.2 million was recognized in actuarial losses above and $0.4 million was recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

19. RECENTLY ISSUED ACCOUNTING STANDARDS

In November 2015, the Financial Accounting Standards Board (FASB) issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. Prior year comparable periods have not been updated retrospectively, as we elected to adopt the standard prospectively. This update requires that deferred tax liabilities and assets be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of each jurisdiction of an entity be offset and presented as a single amount is not affected by the amendments in this update. The amendment is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Energen elected early adoption of this ASU prospectively as of December 31, 2015. We reclassified $14.5 million from a current deferred income tax asset to a noncurrent deferred income tax liability at December 31, 2015.

In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendment is effective for fiscal years beginning on or after December 15, 2015, and interim periods within those fiscal years. Energen does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This update clarifies the guidance regarding line-of-credit arrangements with regards to the recently issued ASU 2015-03. ASU 2015-15 allows entities to defer and present debt issue costs as an asset and subsequently amortize the deferred debt issue costs ratably over the term of the line-of-credit arrangement.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This update codifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. The amendments in this ASU will not impact the Company's financial position or results of operations. The new guidance will require a formal assessment of going concern by management based on criteria prescribed in the new guidance. The Company is reviewing its policies and processes to ensure compliance with this new guidance.

88

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. This update is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. Companies may apply this update retrospectively or using a modified retrospective approach to adjust retained earnings. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers, which deferred the effective date of ASU No. 2014-09 to annual periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are currently evaluating the impact of this guidance on our financial statements.

In April 2014, the FASB issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held for sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment was effective for annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The adoption of this ASU did not have a material impact on the consolidated financial statements of Energen.

20. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

The following data summarizes quarterly operating results:

	Year ended December 31, 2015
(in thousands, except per share amounts)	First			Second			Third			Fourth
Revenues	$	221,858		$	168,326		$	295,571		$	192,799
Operating loss	$	(12,409	)	$	(161,678	)	$	(348,214	)	$	(915,550	)
Loss from continuing operations	$	(15,420	)	$	(111,601	)	$	(227,904	)	$	(590,806	)
Net loss	$	(15,420	)	$	(111,601	)	$	(227,904	)	$	(590,806	)
Diluted earnings per average common share
Continuing operations	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)
Net loss	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)
Basic earnings per average common share
Continuing operations	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)
Net loss	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)

89

	Year ended December 31, 2014
(in thousands, except per share amounts)	First			Second			Third		Fourth
Revenues as originally reported	$	561,178		$	270,097		$	497,761	$	611,435
Discontinued operations*	(263,900		)	—			—		—
Reclassification of loss on sale of assets and other	153			909			747		833
Adjusted revenues	$	297,431		$	271,006		$	498,508	$	612,268
Operating income as originally reported	$	104,599		$	3,107		$	48,171	$	94,223
Discontinued operations*	(73,139		)	—			—		—
Adjusted operating income	$	31,460		$	3,107		$	48,171	$	94,223
Income (loss) from continuing operations	$	15,647		$	(3,154	)	$	20,631	$	66,519
Net income (loss)	$	53,316		$	(7,953	)	$	457,251	$	65,418
Diluted earnings per average common share
Continuing operations	$	0.21		$	(0.04	)	$	0.28	$	0.91
Net income (loss)	$	0.73		$	(0.11	)	$	6.22	$	0.89
Basic earnings per average common share
Continuing operations	$	0.22		$	(0.04	)	$	0.28	$	0.91
Net income (loss)	$	0.73		$	(0.11	)	$	6.26	$	0.90

*As discussed in Note 16, Discontinued Operations and Held for Sale Properties, during the third quarter of 2014, Energen completed the transaction to sell Alagasco to Laclede. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations.

21. OIL AND NATURAL GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:

(in thousands)	December 31, 2015		December 31, 2014
Proved	$	7,911,554	$	8,069,638
Unproved	150,674		142,340
Total capitalized costs	8,062,228		8,211,978
Accumulated depreciation, depletion and amortization	3,673,569		2,663,434
Capitalized costs, net	$	4,388,659	$	5,548,544

Costs Incurred: The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year:

Years ended December 31, (in thousands)	2015		2014		2013
Property acquisition:
Proved	$	1,866	$	2,582	$	4,661
Unproved	85,690		68,514		26,820
Exploration	649,764		972,164		435,636
Development	372,177		408,949		655,353
Total costs incurred	$	1,109,497	$	1,452,209	$	1,122,470

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Results of Operations From Producing Activities: The following table sets forth results of Energen’s oil, natural gas liquids and natural gas operations from producing activities:

Years ended December 31, (in thousands)	2015			2014		2013
Gross revenues*	$	878,554		$	1,679,213	$	1,206,293
Production (lifting costs)	285,760			376,495		351,541
Exploration expense	14,877			28,090		14,036
Depreciation, depletion and amortization including asset impairments	1,880,190			960,539		463,606
Accretion expense	7,108			7,608		6,995
Income tax expense (benefit)	(469,362		)	99,469		128,773
Results of operations from producing activities	$	(840,019	)	$	207,012	$	241,342

* The years ended December 31, 2015, 2014 and 2013 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $281.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million and a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, respectively.

Oil and Natural Gas Operations: The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that proved categories of reserves be disclosed. Proved reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2015, 2014 and 2013. Changes to prices and costs could have a significant effect on the disclosed amount of proved reserves and their associated values. In addition, the estimation of proved reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of proved reserves disclosed. The proved reserves are located onshore in the United States of America.

Estimates of physical quantities of oil and natural gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. (Ryder Scott) and Hickman McClaine and Associates, Inc. (Hickman McClaine), independent oil and natural gas reservoir engineers, have audited the estimates of proved reserves of oil, natural gas liquids and natural gas that Energen has attributed to its net interests in oil and natural gas properties as of December 31, 2015. Ryder Scott audited the proved reserve estimates for coalbed methane in the San Juan Basin and substantially all of the Permian Basin proved reserves. Hickman McClaine audited the conventional proved reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 99 percent of Energen’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

Year ended December 31, 2015	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	181,227		73,463		707,926		372.7
Revisions of previous estimates	(39,537	)	(11,979	)	(44,176	)	(58.9	)
Purchases	2		1		2		—
Extensions and discoveries	83,319		25,530		143,022		132.6
Production	(14,023	)	(4,065	)	(35,604	)	(24.0	)
Sales	(297	)	(11,237	)	(337,266	)	(67.7	)
Proved reserves at end of period	210,691		71,713		433,904		354.7
Proved developed reserves at end of period	108,319		36,374		236,112		184.0
Proved undeveloped reserves at end of period	102,372		35,339		197,792		170.7

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Year ended December 31, 2014	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	164,870		63,011		719,725		347.8
Revisions of previous estimates	(48,548	)	(15,165	)	(71,806	)	(75.7	)
Purchases	88		26		116		0.1
Extensions and discoveries	76,722		29,695		141,209		130
Production	(11,818	)	(4,104	)	(59,562	)	(25.8	)
Sales	(87	)	—		(21,756	)	(3.7	)
Proved reserves at end of period	181,227		73,463		707,926		372.7
Proved developed reserves at end of period	118,697		47,621		589,074		264.5
Proved undeveloped reserves at end of period	62,530		25,842		118,852		108.2

Year ended December 31, 2013	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	155,348		56,155		809,128		346.4
Revisions of previous estimates	(680	)	2,211		18,465		4.6
Purchases	142		56		282		0.2
Extensions and discoveries	20,517		7,823		50,568		36.8
Production	(10,378	)	(3,233	)	(70,506	)	(25.4	)
Sales	(79	)	(1	)	(88,212	)	(14.8	)
Proved reserves at end of period	164,870		63,011		719,725		347.8
Proved developed reserves at end of period	113,795		42,087		623,305		259.8
Proved undeveloped reserves at end of period	51,075		20,924		96,420		88.0

2015 Activities: Energen had net downward reserve revisions during 2015 which totaled 58.9 MMBOE including negative revisions of approximately 38.0 MMBOE related to changes in year-end pricing and negative revisions of approximately 8.2 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period. Other negative revisions were 5.5 MMBOE due to increased declines in certain Wolfberry wells and 5.0 MMBOE of Wolfcamp reserves due to interference caused by our wellbore placement geometry.

During 2015, Energen had extensions and discoveries of 132.6 MMBOE, primarily in the Permian Basin, of which 78 percent were proved undeveloped reserves and 22 percent were proved developed reserves. Extension drilling resulted in 3.1 MMBOE of discoveries with exploratory drilling providing 129.5 MMBOE of discoveries.

During 2015, Energen had sales of 67.7 MMBOE primarily due to the sale of certain natural gas assets in the San Juan Basin.

2014 Activities: Energen had net downward reserve revisions during 2014 which totaled 75.7 MMBOE including downward revisions of approximately 53.4 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period and upward revisions of approximately 3.9 MMBOE related to changes in year-end pricing. The San Juan Basin had upward reserve revisions of 1.6 MMBOE including 4.4 MMBOE related to changes in year-end pricing and downward revisions of approximately 1.5 MMBOE due to higher operating costs. Net downward reserve revisions of 77.3 MMBOE in the Permian Basin were due to reclassifying 53.4 MMBOE as unproved because of changes in our development plans, downward revisions of approximately 13.3 MMBOE due to decreased well performance in certain Wolfberry wells, downward revisions of approximately 5.4 due to higher operating costs and approximately 0.5 MMBOE related to changes in the year-end pricing.

Energen purchased 0.1 MMBOE of reserves during 2014 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2014, Energen had extensions and discoveries of 130.0 MMBOE of which 70 percent were proved undeveloped reserves and 30 percent were proved developed reserves. Extension drilling resulted in 89.6 MMBOE of discoveries with exploratory drilling providing 40.4 MMBOE of discoveries. The San Juan Basin added 1.1 MMBOE of reserves through the drilling or

92

identification of 16 well locations and 10 pay adds. The Permian Basin added 128.6 MMBOE of reserves primarily through the drilling or identification of 361 well locations.

During 2014, Energen had sales of 3.7 MMBOE primarily due to the sale of the North Louisiana/East Texas primarily natural gas properties.

2013 Activities: Energen had upward reserve revisions during 2013 which totaled 4.6 MMBOE including approximately 7 MMBOE related to changes in year-end pricing and downward revisions of approximately 5.3 MMBOE of proved undeveloped reserves of which 4.6 MMBOE are expected to be drilled beyond five years with the remainder no longer expected to be drilled. The San Juan Basin upward reserve revisions of 2.2 MMBOE including 5.9 MMBOE related to changes in year-end pricing and downward revisions of approximately 4.6 MMBOE of proved undeveloped reserves that are expected to be drilled beyond five years. Net upward reserve revisions of 1.2 MMBOE in the Permian Basin were due to improved well performance in certain Wolfberry wells and approximately 0.4 MMBOE related to changes in the year-end pricing and downward revisions of approximately 0.7 MMBOE of proved undeveloped reserves that are no longer expected to be drilled.

Energen purchased 0.2 MMBOE of reserves during 2013 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2013, Energen had extensions and discoveries of 36.8 MMBOE of which 45 percent were proved undeveloped reserves and 55 percent were proved developed reserves. Extension drilling resulted in 21.6 MMBOE of discoveries with exploratory drilling providing 15.2 MMBOE of discoveries. The San Juan Basin added 2.3 MMBOE of reserves through 30 pay adds. The Permian Basin added 34.4 MMBOE of reserves primarily through the drilling or identification of 262 well locations.

During 2013, Energen had sales of 14.8 MMBOE primarily due to the sale of the Black Warrior Basin coalbed methane properties.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of Energen’s crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. Open mark-to-market derivatives applicable to future periods are excluded from the calculation of standardized measure of future net cash flows.

Years ended December 31, (in thousands)	2015		2014		2013
Future gross revenues	$	11,714,729	$	20,971,672	$	19,509,305
Future production costs	4,353,974		7,532,273		6,136,709
Future development costs	1,961,661		1,784,738		1,896,602
Future income tax expense	1,065,887		3,440,582		3,209,697
Future net cash flows	4,333,207		8,214,079		8,266,297
Discount at 10% per annum	2,299,859		3,994,423		4,248,456
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	2,033,348	$	4,219,656	$	4,017,841

93

The following are the principal sources of changes in the standardized measure of discounted future net cash flows:

Years ended December 31, (in thousands)	2015			2014			2013
Balance at beginning of year	$	4,219,656		$	4,017,841		$	3,699,319
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(2,861,591		)	(1,147,028		)	566,838
Net changes due to revisions in quantity estimates	(404,708		)	(1,285,394		)	(81,762		)
Development costs incurred, previously estimated	350,560			337,198			299,432
Accretion of discount	421,966			401,784			369,932
Changes in timing and other*	(903,975		)	987,652			(179,502		)
Total revisions	(3,397,748		)	(705,788		)	974,938
New field discoveries and extensions, net of future production and development costs	776,315			2,321,028			376,326
Sales of oil and gas produced, net of production costs	(514,380		)	(1,054,553		)	(1,014,593		)
Purchases	8			4,241			4,690
Sales	(372,039		)	(21,092		)	(24,876		)
Net change in income taxes	1,321,536			(342,021		)	2,037
Net change in standardized measure of discounted future net cash flows	(2,186,308		)	201,815			318,522
Balance at end of year	$	2,033,348		$	4,219,656		$	4,017,841

*Amount represents changes in production timing and other. In 2015, the production timing is significantly affected by changes related to the delay of the drilling program. For 2014, the production timing is significantly affected by changes related to the acceleration of the horizontal drilling program and the delay of the vertical drilling program. 

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

a. Disclosure Controls and Procedures

Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

b. Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Energen Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those written policies and procedures that:

i pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Energen Corporation;

ii provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Energen Corporation are being made only in accordance with authorization of management and directors of Energen Corporation; and

iii provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2015. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Energen Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.

Based on this assessment, management determined that, as of December 31, 2015, Energen Corporation maintained effective internal control over financial reporting. The effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

c. Changes in Internal Control Over Financial Reporting

Our chief executive officer and chief financial officer have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10 is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held May 3, 2016. The definitive proxy statement will be filed on or about March 21, 2016.

ITEM 11.    EXECUTIVE COMPENSATION

The information regarding executive compensation is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held May 3, 2016.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

a. Security Ownership of Certain Beneficial Owners

The information regarding the security ownership of the beneficial owners of more than five percent of Energen’s common stock is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held May 3, 2016.

b. Security Ownership of Management

The information regarding the security ownership of management is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held May 3, 2016.

c. Securities Authorized for Issuance Under Equity Compensation Plans

The following table summarizes information concerning securities authorized for issuance under equity compensation plans as of December 31, 2015:

Plan Category	Number of Securities to be Issued for Outstanding Options, Performance Share Awards and Restricted Stock Units	Weighted Average Exercise Price		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders*	1,387,066	$	65.77	2,987,964
Equity compensation plans not approved by security holders	—	—		—
Total	1,387,066	$	65.77	2,987,964

*These plans include 2,294,740 shares associated with Energen’s Stock Incentive Plan, 116,374 shares associated with the 1992 Energen Corporation Directors Stock Plan and 576,850 shares associated with the 1997 Deferred Compensation Plan.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information regarding certain relationships and related transactions, and director independence is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held May 3, 2016.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information regarding Principal Accountant Fees and Services is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held May 3, 2016.

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a. Documents Filed as Part of This Report

(1) Financial Statements

The consolidated financial statements of Energen are included in Item 8 of this Form 10-K.

(2)Financial Statement Schedules

No financial statement schedules are required to be files as part of this Form 10-K or they are inapplicable.

(3)Exhibits

The exhibits listed on the accompanying Index to Exhibits are filed as part of this Form 10-K.

97

Energen Corporation

INDEX TO EXHIBITS

Item 14(a)(3)

Exhibit
Number	Description
*3(a)	Restated Certificate of Incorporation of Energen Corporation (composite, as amended April 29, 2005) which was filed as Exhibit 3(a) to Energen’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005
*3(b)	Articles of Amendment to Restated Certificate of Incorporation of Energen, designating Series 1998 Junior Participating Preferred Stock (July 27, 1998) which was filed as Exhibit 4(b) to Energen’s Post Effective Amendment No. 1 to Registration Statement on Form S-3 (Registration No. 333-00395)
*3(c)	Bylaws of Energen Corporation (as amended through July 23, 2008) which was filed as Exhibit 99.1 to Energen’s Current Report on Form 8-K, dated July 25, 2008
*4(a)	Form of Indenture between Energen Corporation and The Bank of New York, as Trustee, which was dated as of September 1, 1996 (the “Energen 1996 Indenture”), and which was filed as Exhibit 4(i) to the Registrant’s Registration Statement on Form S-3 (Registration No. 333-11239)
*4(a)(i)	Officers’ Certificate, dated September 13, 1996, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Series A Notes which was filed as Exhibit 4(d)(i) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001
*4(a)(ii)	Officers’ Certificate, dated July 8, 1997, pursuant to Section 301 of the Energen 1996 Indenture amending the terms of the Series A Notes which was filed as Exhibit 4(d)(ii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001
*4(a)(iii)	Amended and Restated Officers’ Certificate, dated February 27, 1998, setting forth the terms of the Series B Notes which was filed as Exhibit 4(d)(iii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001
*4(a)(iv)	Officers’ Certificate, dated August 5, 2011, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 4.65 percent Senior Notes due September 1, 2021, which was filed as Exhibit 4.1 to Energen’s Current Report on Form 8-K, dated August 5, 2011
*10(a)	Credit Agreement dated September 2, 2014, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed September 2, 2014
*10(b)	First Amendment to the Credit Agreement dated as of October 20, 2014, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Energen Resources Corporation, as Guarantor, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed October 20, 2014
*10(b)(i)	Second Amendment to the Credit Agreement dated as of April 16, 2015, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Energen Resources Corporation, as Guarantor, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed April 20, 2015
*10(b)(ii)	Third Amendment to the Credit Agreement dated as of October 20, 2015, by and among Energen Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Energen Resources Corporation, as Guarantor, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed October 23, 2015
*10(c)	Commitment Increase Letter dated November 17, 2014, by and among Energen Corporations, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the institutions named therein as lenders, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed October 17, 2014

98

*10(d)	Form of Severance Compensation Agreement between Energen Corporation and its executive officers which was filed as Exhibit 10.3 to Energen’s Current Report on Form 8-K filed December 13, 2012
*10(e)	Energen Corporation Stock Incentive Plan (as amended effective January 1, 2015)
*10(f)	Form of Stock Option Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(r) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012
*10(g)	Form of Restricted Stock Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(s) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012
*10(h)	Form of Restricted Stock Unit Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10.2 to Energen’s Current Report on Form 8-K filed December 12, 2013
*10(i)	Form of Performance Share Award under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(t) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012
*10(j)	Energen Corporation 1997 Deferred Compensation Plan (as amended and restated) effective October 22, 2014
*10(k)	Energen Corporation Directors Stock Plan (as amended April 28, 2010) which was filed as an attachment to Energen’s definitive Proxy Statement on Schedule 14A , filed March 19, 2010
*10(l)	Energen Corporation Annual Incentive Compensation Plan, as amended effective January 1, 2015
21	Subsidiaries of Energen Corporation
23(a)	Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP)
23(b)	Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott Company, L.P.)
23(c)	Consent of Independent Oil and Gas Reservoir Engineers (Hickman McClaine and Associates, Inc.)
24	Power of Attorney
31(a)	Energen Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a)
31(b)	Energen Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)
32	Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
99(a)	Reserve Audit – Ryder Scott & Company, L.P.
99(b)	Reserve Audit – Hickman McClaine and Associates, Inc.
101	The financial statements and notes thereto from Energen Corporation’s Annual Report on Form 10-K for the year ended December 31, 2015 are formatted in XBRL
*Incorporated by reference

99

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ENERGEN CORPORATION

(Registrant)

February 16, 2016	By	/s/ J.T. McManus, II
	J.T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation;

100

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

February 16, 2016	By	/s/ J.T. McManus, II
	J.T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation
February 16, 2016	By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation
February 16, 2016	By	/s/ Russell E. Lynch, Jr.
	Russell E. Lynch, Jr. Vice President and Controller of Energen Corporation
February 16, 2016	*
	Kenneth W. Dewey Director
February 16, 2016	*
	M. James Gorrie Director
February 16, 2016	*
	Jay Grinney Director
February 16, 2016	*
	William G. Hargett Director
February 16, 2016	*
	Frances Powell Hawes Director
February 16, 2016	*
	Alan A. Kleier Director
	*By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Attorney-in-Fact

101

EX-21

Exhibit 21

SUBSIDIARIES OF ENERGEN CORPORATION

Energen Resources Corporation*

* Incorporated in the State of Alabama

EX-23.A

Exhibit 23(a)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (File No. 333-203914) and Registration Statements on Forms S-8 (File No. 33-48505, File No. 333-59804, File No. 333-26111, File No. 333-45107, File No. 333-84170 and File No. 333-178794) of Energen Corporation of our report dated February 16, 2016 relating to the consolidated financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 16, 2016

EX-23.B

Exhibit 23(b)

CONSENT

We hereby consent to the reference to our firm name and our audit of the estimates of proved reserves of oil, natural gas liquids and natural gas that Energen Corporation attributed to its net interests in oil and natural gas properties located in the U.S. as of December 31, 2015 which appears in this Form 10-K and the inclusion of our report dated January 29, 2016, which appears as an Exhibit to this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (File No. 333-203914) and Registration Statements on Forms S-8 (File No. 33-48505, File No. 333-59804, File No. 333-26111, File No. 333-45107, File No. 333-84170 and File No. 333-178794) of Energen Corporation to the reference to our firm name and our audit of the estimates of proved reserves of oil, natural gas liquids and natural gas that Energen Corporation attributed to its net interests in oil and natural gas properties located in the U.S. as of December 31, 2015 which appears in this Form 10-K and our report dated January 29, 2016, which appears as an Exhibit to this Form 10-K.

/s/ Ryder Scott Company, L.P.

Houston, Texas

February 16, 2016

EX-23.C

Exhibit 23(c)

CONSENT

We hereby consent to the reference to our firm name and our audit of the estimates of proved reserves of oil, natural gas liquids, and natural gas that Energen Corporation attributed to its net interests in oil and natural gas properties located in the U.S. as of December 31, 2015 which appears in this Form 10-K and the inclusion of our report dated January 29, 2016, which appears as an Exhibit to this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (File No. 333-203914) and Registration Statements on Forms S-8 (File No. 33-48505, File No. 333-59804, File No. 333-26111, File No. 333-45107, File No. 333-84170 and File No. 333-178794) of Energen Corporation to the reference to our firm name and our audit of the estimates of proved reserves of oil, natural gas liquids and natural gas that Energen Corporation attributed to its net interests in oil and natural gas properties located in the U.S. as of December 31, 2015 which appears in this Form 10-K and our report dated January 29, 2016, which appears as an Exhibit to this Form 10-K.

/s/ Hickman McClaine & Associates, Inc.

Midland, Texas

February 16, 2016

EX-24

Exhibit 24

POWER OF ATTORNEY

ENERGEN CORPORATION

Each of the undersigned directors of Energen Corporation, an Alabama corporation, hereby nominates, constitutes and appoints James T. McManus, II, and Charles W. Porter, Jr., and each of them, the true and lawful attorneys of the undersigned to sign the name of the undersigned as director to the Annual Reports on Form 10-K for the year ended December 31, 2015, of each of said corporations, in such form as they or any one of them may approve, and to file the same with all exhibits thereto and other documents in connection therewith with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, and to any and all amendments to said reports.

The undersigned hereby grants to said attorneys full power and authority to do and perform each and every act and thing requisite and necessary to be done so that such Annual Reports shall comply with the Securities Exchange Act of 1934, as amended, and the applicable rules and regulations adopted pursuant thereto, and further grants full power of substitution, resubstitution and revocation, all as fully as the undersigned could do if personally present, hereby ratifying all that said attorneys or their substitutes may lawfully do by virtue hereof.

IN WITNESS WHEREOF, the undersigned directors of Energen Corporation have executed this Power of Attorney as of the 9^th day of February, 2016.    

/s/ Kenneth W. Dewey        

Kenneth W. Dewey

/s/ T. Michael Goodrich        

T. Michael Goodrich

/s/ M. James Gorrie        

M. James Gorrie

/s/ Jay Grinney            

Jay Grinney

/s/ William G. Hargett        

William G. Hargett

/s/ Frances Powell Hawes    

Frances Powell Hawes

/s/ Alan A. Kleier     

Alan A. Kleier

/s/ Stephen A. Snider        

Stephen A. Snider

/s/ Gary C. Youngblood        

Gary C. Youngblood

EX-31.A

Exhibit 31(a)

CERTIFICATION

I, James T. McManus, II, certify that:

1. I have reviewed this report on Form 10-K of Energen Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 16, 2016	By	/s/ J. T. McManus, II
		J. T. McManus, II Chairman and Chief Executive Officer of Energen Corporation

EX-31.B

Exhibit 31(b)

CERTIFICATION

I, Charles W. Porter, Jr., certify that:

1. I have reviewed this report on Form 10-K of Energen Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 16, 2016	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Energen Corporation (the “Registrant”) on Form 10-K for the period ended December 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of February 16, 2016

By	/s/ J. T. McManus, II
	J. T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation
By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Energen Corporation and will be retained by Energen Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.A

Exhibit 99(a)

ENERGEN RESOURCES CORPORATION

Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2015

\s\ Joseph E. Blankenship

Joseph E. Blankenship, P.E.

TBPE License No. 62093

Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849

1100 LOUISIANA STREET SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

January 29, 2016

Energen Resources Corporation

605 Richard Arrington, Jr. Boulevard North

Birmingham, AL 35203-2707

Attention: Mr. Henry E. Cash, Manager - Acquisitions & Engineering

Gentlemen:

At the request of Energen Resources Corporation (Energen), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2015 prepared by Energen’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on January 27, 2016 and presented herein, was prepared for public disclosure by Energen in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Energen’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by Energen and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2015. The properties reviewed by Ryder Scott incorporate 4078 reserve determinations and are located in the state of Texas.

The properties reviewed by Ryder Scott account for a portion of Energen’s total net proved reserves as of December 31, 2015. Based on the estimates of total net proved reserves prepared by Energen, the reserves audit conducted by Ryder Scott addresses the percentages shown below.

Percent of Energen’s Total Net Proved Reserves

Audited by Ryder Scott

Reserve Class and Category	Percent of Liquid Hydrocarbons	Percent of Gas	Percent of Oil Equivalent
Total Proved	97	87	95
Proved Developed	94	76	90
Proved Undeveloped	99	99	99

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

Based on our review, including the data, technical processes and interpretations presented by Energen, it is our opinion that the overall procedures and methodologies utilized by Energen in preparing

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

their estimates of the proved reserves as of December 31, 2015 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Energen are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The estimated reserves presented in this report are related to hydrocarbon prices. Energen has informed us that in the preparation of their reserve and income projections, as of December 31, 2015, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Energen attributable to Energen's interest in properties that we reviewed and for those that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold and Royalty Interests of

Energen Resources Corporation

As of December 31, 2015

	Proved
	Developed			Total
	Producing	Non-Producing	Undeveloped	Proved
Net Reserves - Audited by Ryder Scott
Oil/Condensate - MBBL	105,772	0	101,470	207,242
Plant Products - MBBL	30,417	0	35,091	65,508
Gas - MMCF	180,313	0	196,263	376,576
Total Equivalent Oil - MBOE	166,242	0	169,271	335,513
Net Reserves - Not Audited by Ryder Scott
Oil/Condensate - MBBL	2,506	41	902	3,449
Plant Products - MBBL	5,957	0	248	6,205
Gas - MMCF	55,715	84	1,529	57,328
Total Equivalent Oil - MBOE	17,748	55	1,406	19,209
Net Reserves - Total Corporation
Oil/Condensate - MBBL	108,278	41	102,372	210,691
Plant Products - MBBL	36,374	0	35,339	71,713
Gas - MMCF	236,028	84	197,792	433,904
Total Equivalent Oil - MBOE	183,990	55	170,677	354,722

Liquid hydrocarbons are expressed in thousand standard 42 gallon barrels (MBBL). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves referred to herein consist of the shut-in and behind pipe categories.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Energen’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward”. The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered,could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves, prepared by Energen, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 95 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through October 2015, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Energen or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 5 percent of the proved producing reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

Approximately 100 percent of the proved undeveloped reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Energen for our review or which we have obtained from public data sources that were available through October 2015. The data utilized from the analogues in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.

Energen’s reserves included in this audit were in conventional and unconventional formations in the Permian Basin. Many of Energen’s properties in the Permian Basin are producing under secondary and enhanced recovery techniques. Some of Energen’s reserves will be produced through horizontal wellbores. Examples would include many of their wells in the Wolfcamp Formation.

To estimate economically recoverable proved oil and gas reserves many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Energen relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Energen for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on December 31, 2015 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Energen for the geographic area reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used by Energen to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering fees, transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used by Energen were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Energen.

The table below summarizes Energen’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Energen’s “average realized prices.” The average realized prices shown in the table below were determined from Energen’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Energen’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$50.28/Bbl	$46.30/Bbl
	NGLs	WTI Cushing	$50.28/Bbl	$14.99/Bbl
	Gas	Henry Hub	$2.59/MMBTU	$2.08/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Energen’s individual property evaluations.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Operating costs furnished by Energen are based on the operating expense reports of Energen and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished by Energen were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Energen. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Energen are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Energen were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Energen. The estimated net cost of abandonment after salvage was included by Energen for properties where abandonment costs net of salvage were significant. Energen’s estimates of the net abandonment costs were accepted without independent verification.

The proved undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Energen’s plans to develop these reserves as of December 31, 2015. The implementation of Energen’s development plans as presented to us is subject to the approval process adopted by Energen’s management. As the result of our inquiries during the course of our review, Energen has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Energen’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Energen. Additionally, Energen has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2015, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. All of Energen’s proved undeveloped reserves are scheduled to be developed within five years from the initial disclosure in an SEC filing.

Current costs used by Energen were held constant throughout the life of the properties.

Energen’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend had been established, future production rates were held constant, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend had been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Energen to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Energen. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Energen’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Energen’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a review of the properties in which Energen owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Energen for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Energen are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Energen has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Energen’s forecast of future proved production, we have relied upon data furnished by Energen with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Energen. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by Energen to be appropriate and sufficient for the purpose of our review of Energen’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Energen and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Energen, it is our opinion that the overall procedures and methodologies utilized by Energen in preparing their estimates of the proved reserves as of December 31, 2015 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Energen are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

We were in reasonable agreement with Energen's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Energen's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Energen when its reserve estimates were prepared.However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Energen.

Other Properties

Other properties, as used herein, are those properties of Energen which we did not review. The proved net reserves attributable to the other properties account for 3 percent of the total proved net liquid hydrocarbon reserves and 13 percent of the total proved net gas reserves or 5 percent of the total proved net reserves on an equivalent barrel, BOE, basis based on estimates prepared by Energen as of December 31, 2015.

The same technical personnel of Energen were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Energen. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Energen.

Energen Resources Corporation is a wholly owned subsidiary of Energen Corporation. Energen Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Energen Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Energen Resources Corporation of the references to our name as well as to the references to our third party report for Energen Corporation, which appears in the December 31, 2015 annual report on Form 10-K of Energen Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Energen Corporation.

We have provided Energen with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Energen and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Joseph E. Blankenship

Joseph E. Blankenship, P.E.

TBPE License No. 62093

Advising Senior Vice President

[SEAL]

JEB (FWZ)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Joseph E. Blankenship was the primary technical person responsible for overseeing the estimation and evaluation process with respect to the preparation of this report.

Mr. Blankenship, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1982, is an Advising Senior Vice President and also serves as Chief Technical Advisor for Unconventional Reserves Evaluation. Mr. Blankenship is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Blankenship served in a number of engineering positions with Exxon Company USA. More information regarding Mr. Blankenship’s geographic and job specific experience can be seen on Ryder Scott Company’s website www.ryderscott.com/Company/Employees.

Mr. Blankenship earned a Bachelor of Science degree in Mechanical Engineering from the University of Alabama in 1977. He is a member of the Honorary Engineering Society Pi Tau Sigma and is a licensed Professional Engineer in the State of Texas. He attended Exxon schools on Reservoir Engineering, Well Log Analysis, Economic Evaluation, Oil and Gas Facility Design, and Offshore Platform Design. He is a member of the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE). He has served as Chairman of the SPE Newsletter Committee and has been invited by the SPEE to lecture on Coal Seam Evaluation.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Blankenship fulfills.

Mr. Blankenship’s continuing education in 2015 included classes on Reservoir Engineering Aspects of Unconventional Reservoirs, SPEE Monograph 4 Decline Curve Analysis Techniques, Petroleum Reservoir Geologic Mapping, Cash Flow Analysis Reporting Software, Seismic Data Evaluation Criteria, Excel Programing Techniques, Cash Flow Analysis Reporting Quality Control, and SEC Comment Letters Review. Mr. Blankenship also served as instructor in two courses on Unconventional and Conventional Reserves Evaluation.

In 2014, Mr. Blankenship attended classes on Aries Economic Evaluation Software, Nodal Analysis, Petrovisual Data Visualization Software, Petroleum Production Pricing, SEC vs. SPE PRMS Reserves Definitions, Probabilistic Evaluation Methods, Evaluation Quality Control and Quality Assurance, Reservoir Solutions Software, and Spotfire Business Intelligence Analytics Software. Mr. Blankenship also served as instructor in two courses on Unconventional and Conventional Reserves Evaluation.

In 2013, Mr. Blankenship attended classes on Booking of Enhanced Oil Recovery (EOR) Reserves, Formation Fracturing Statistics, SEC Reserves Disclosures, Analysis of Shale Reserves, and Reserves Reconciliation. Mr. Blankenship also served as instructor in two courses on Unconventional Resource Evaluation.

Based on his educational background, professional training and more than 38 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Blankenship has satisfied all of the professional qualifications for both Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.

Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EX-99.B

Exhibit 99(b)

January 29, 2016

Energen Resources Corp.

605 Richard Arrington Jr Boulevard North

Birmingham, AL 35203-2707

Attention: Mr. Henry E. Cash

Gentlemen:

Re:Reserve Audit

San Juan Basin, New Mexico

In accordance with your request, Hickman McClaine & Associates, Inc. (HM&A) has performed an audit of the Proved oil and gas reserves estimated by Energen Resources Corp. (ERC) for properties located in the San Juan Basin of New Mexico (herein referred to as “Subject Area”) in accordance with guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our audit was completed January 25, 2016.

	ERC Net “Subject Area” Audited Reserves
	Oil MBBL	Gas MMCF			NGL MBL	Liquid Eq MBOE
Effective Date	- - - - - - - - - - - - December 31, 2015- - - - - - - - - - - -
Proved Developed Producing	1,927		49,059	5,421			15,524
Proved Developed Non-Producing	0		0	—			0
Undeveloped	902		1,529	248			1,406
TOTAL PROVED	2,829		50,588	5,669			16,930

A reserve audit is the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or reserves information prepared by others and the rendering of an opinion about the methodologies, data and thoroughness of the process that was used, the reserve classification that was assigned and the reserve quantities that were estimated. This letter presents the results of our third party reserve audit based on the guidelines set forth under Section 229.1202(a)(7) and (8) of the SEC regulations. The estimated reserves shown in the following table represent ERC’s estimated net Proved reserves attributable to the leasehold interests in certain properties owned by ERC as of December 31, 2015.

The total proved reserves for the “Subject Areas” audited by HM&A represent approximately 4.8% of ERC’s total proved reserves expressed in MBOE. The liquid reserves include crude oil, condensate and natural gas liquids expressed in standard 42 gallon barrels. Gas volumes are

expressed in millions of standard cubic feet (MMCF) at contract temperature and pressure bases. Gas reserves are converted to oil equivalent using a factor of 6 mcf per barrel.

Proved oil and gas reserves are those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. Reserve estimations are based on industry-accepted principles of engineering and evaluation that are predicated on established scientific concepts. However, the application of such principles involves extensive judgment and assumptions and is subject to changes in performance data, existing technical knowledge, economic conditions and/or regulatory provisions. Consequently, reserve estimates are inherently uncertain and will normally require some revisions in the future, particularly on new wells with little production history and for reserve categories other than Proved Developed Producing. ERC’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

Since reserves have to be economically recoverable, it is necessary to determine the producing rate below which producing operations are no longer profitable (economic limit). Determining the economic limit requires the application of oil and gas prices and operating cost data. The SEC regulations require the use of a constant price that is the unweighted arithmetic average of the first-day-of-the-month price for the twelve months prior to the reporting date, except where the price is based on a contractual arrangement. The product prices which were actually used by ERC to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering fees, and transportation fees referred to herein as “differentials.” The differentials used by ERC were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by ERC.

The table below summarizes ERC’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as ERC’s “average realized prices.” The average realized prices shown in the table below were determined from ERC’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and ERC’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
San Juan Basin
	Oil/Condensate	WTI Cushing	$50.28/Bbl	$69.75/Bbl
	NGLs	Mt. Belvieu	$0.4114/Gal	$0.29/Gal
	Gas	Henry Hub	$2.587/MMBTU	$3.75/MCF

The lease./well operating costs used by ERC were the monthly averages for the most recent twelve month available prior to the reporting date. The operating costs included only expenses directly applicable to the lease/well plus general and administrative costs that were appropriate to allocate back to the lease/well. We spot checked operating costs to satisfy ourselves that they were reasonable. In the economic calculations operating costs were held constant unless some scheduled change in operations dictated a change.

Because of the inherent uncertainties in determining reserve quantities, the reserves presented in this report are estimates only and should not be construed as exact quantities. The actual volumes of oil and gas recovered could be more or less than the estimated reserves. The reserves reviewed in this audit are to be produced under primary recovery from formations within the Subject Area. Our audit covered 100% of ERC’s net Proved oil, NGL and gas reserves in the San Juan Basin.

We have accepted without independent verification the accuracy and completeness of the historical production and other data furnished by ERC with respect to ownership interest, oil and gas prices, historical costs of operation and development, and any agreements relating to current and future operations of the properties and sales of production. If, however, in the course of our audit something came to our attention which called into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto.

HM&A has used all methods and procedures necessary to prepare this report including a detailed review of major properties constituting approximately 80% of the total Proved Developed Producing reserves estimated by ERC in the Subject Area as of December 31, 2015. A review of the Proved Undeveloped reserves was also conducted. All of the files and records for the leases/wells in the Subject Area were available for our use. Performance and available plant accounting data were initially available through August 2015 at the start of our audit. Specific leases/wells performance data were updated as our review progressed.

In general the reserves we reviewed were estimated by decline curve analysis whereby historical performance data (producing rates and pressures) are extrapolated when such data were deemed to be definitive. When performance data was not definitive or little or no performance history was available, reserve estimate were based on analogous well performance and occasionally by volumetric methods. Nonproducing reserve estimates were based on analogy and volumetrics.

We are qualified to perform engineering evaluations and audits, but do not claim any expertise in accounting or legal matters. As is customary in the profession, no field inspection was made of the properties nor have we verified that all operations are in compliance with state and/or federal conservation, pricing and environmental regulations that may apply. No consideration was given to potential environmental liabilities that may exist. It is our understanding that ERC’s estimates of reserves do not include adjustments for settlement of any potential gas volume and value imbalances which may have resulted from over- or under-production to ERC’s interest. We have not attempted to identify any interest revisions that might exist.

HM&A is satisfied that the assumptions, methods, data and procedures utilized by ERC in the preparation of the reserve estimates are appropriate and that ERC’s reserve classifications conform to the SEC reserve definitions contained in 210.4-10(a).

In the aggregate the overall proved reserves estimated by ERC in the Subject Area are reasonable and within the audit tolerance of 10 percent as set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers (SPE audit guidelines). Therefore it is our opinion that reserves set forth in this report fairly reflect the estimated net Proven reserves owned by the ERC in the Subject Area.

HM&A (Successor to T. Scott Hickman & Associates, Inc.) has been providing reserve estimation and evaluation services to industry and investment community for over 40 years. All of the Company’s engineers are qualified by education, training and experience as Reserves Estimators and Reserves Auditors under the SPE audit guidelines. Each Engineer has at least 25 years of experience as a reserve evaluator. They are all registered engineers and complete a minimum of 15 hours of continuing education annually.

We are independent petroleum engineers with respect to ERC as provided in the SPE audit guidelines. We do not own an interest in any of the audited properties and are not employed on a contingency basis.

ERC is a wholly owned subsidiary of Energen Corporation. Energen Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Energen Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Energen Corporation, which appears in the December 31, 2015 annual report on Form 10-K of Energen Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Energen Corporation.

Yours very truly,

T. SCOTT HICKMAN & ASSOCIATES, INC.

/s/ J. Louis Moseley

J. Louis Moseley, P.E

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Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 05, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Entity Registrant Name	ENERGEN CORP
Entity Central Index Key	0000277595
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		78,791,451
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 5,283,012,351

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 1,272	$ 1,852
Accounts receivable, net	63,097	157,678
Inventories	11,255	14,251
Assets held for sale	93,739	395,797
Derivative instruments	56,963	322,337
Prepayments and other	20,014	27,445
Total current assets	246,340	919,360
Oil and natural gas properties, successful efforts method
Proved properties	7,611,118	6,903,514
Unproved properties	145,724	142,340
Less accumulated depreciation, depletion and amortization	3,454,510	1,893,106
Oil and natural gas properties, net	4,302,332	5,152,748
Other property and equipment, net	48,358	46,389
Total property, plant and equipment, net	4,350,690	5,199,137
Other postretirement assets	3,881	0
Other assets	12,782	19,761
TOTAL ASSETS	4,613,693	6,138,258
Current Liabilities
Accounts payable	64,742	101,453
Accrued taxes	5,801	5,530
Accrued wages and benefits	28,563	21,553
Accrued capital costs	79,206	207,461
Revenue and royalty payable	60,493	72,047
Liabilities related to assets held for sale	12,789	24,230
Pension liabilities	15,685	24,609
Deferred income taxes	0	79,164
Derivative instruments	459	988
Other	19,783	23,288
Total current liabilities	287,521	560,323
Long-term debt	776,087	1,038,563
Asset retirement obligations	89,990	94,060
Pension and other postretirement liabilities	0	15,935
Deferred income taxes	552,369	1,000,486
Other	11,866	14,287
Total liabilities	$ 1,717,833	$ 2,723,654
Commitments and Contingencies
Shareholders' Equity
Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized	$ 0	$ 0
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized; 81,770,161 shares issued at December 31, 2015 and 75,875,711 shares issued at December 31, 2014	818	759
Premium on capital stock	979,030	564,438
Retained earnings	2,046,016	2,997,821
Accumulated other comprehensive income (loss), net of tax
Pension and postretirement plans	263	(22,870)
Deferred compensation plan	1,965	2,862
Treasury stock, at cost; 3,026,350 shares and 2,980,598 shares at December 31, 2015 and 2014, respectively	(132,232)	(128,406)
Total shareholders’ equity	2,895,860	3,414,604
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$ 4,613,693	$ 6,138,258

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CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	81,770,161	75,875,711
Treasury stock, shares	3,026,350	2,980,598

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CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Oil, natural gas liquids and natural gas sales	$ 763,261	$ 1,344,194	$ 1,256,317
Gain (loss) on derivative instruments, net	115,293	335,019	(50,024)
Total revenues	878,554	1,679,213	1,206,293
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production	228,380	274,432	257,438
Production and ad valorem taxes	57,380	102,063	94,103
Depreciation, depletion and amortization	593,789	548,564	452,876
Asset impairment	1,292,308	416,801	13,906
Exploration	14,878	28,090	14,036
General and administrative	149,132	122,052	113,821
Accretion of discount on asset retirement obligations	7,108	7,608	6,995
(Gain) loss on sale of assets and other, net	(26,570)	2,642	981
Total operating costs and expenses	2,316,405	1,502,252	954,156
Operating Income (Loss)	(1,437,851)	176,961	252,137
Other Income (Expense)
Interest expense	(43,108)	(37,771)	(39,736)
Other income	223	1,181	3,803
Total other expense	(42,885)	(36,590)	(35,933)
Income (Loss) From Continuing Operations Before Income Taxes	(1,480,736)	140,371	216,204
Income tax expense (benefit)	(535,005)	40,728	74,323
Income (Loss) From Continuing Operations	(945,731)	99,643	141,881
Discontinued Operations, net of tax
Income from discontinued operations	0	29,292	59,079
Gain on disposal of discontinued operations, net	0	439,097	3,594
Income From Discontinued Operations	0	468,389	62,673
Net Income (Loss)	$ (945,731)	$ 568,032	$ 204,554
Diluted Earnings Per Average Common Share
Continuing operations (in dollars per share)	$ (12.43)	$ 1.36	$ 1.96
Discontinued operations (in dollars per share)	0.00	6.39	0.86
Net Income (Loss) (in dollars per share)	(12.43)	7.75	2.82
Basic Earnings Per Average Common Share
Continuing operations (in dollars per share)	(12.43)	1.37	1.96
Discontinued operations (in dollars per share)	0.00	6.42	0.87
Net Income (Loss) (in dollars per share)	$ (12.43)	$ 7.79	$ 2.83
Diluted Average Common Shares Outstanding (in shares)	76,078,371	73,274,631	72,470,622
Basic Average Common Shares Outstanding (in shares)	76,078,371	72,896,579	72,317,865

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net Income (Loss)	$ (945,731)	$ 568,032	$ 204,554
Cash flow hedges:
Total cash flow hedges	0	(12,178)	(32,018)
Pension and postretirement plans:
Amortization of net benefit obligation at transition, net of tax of $0, $8 and $112, respectively	0	14	207
Amortization of prior service cost, net of tax of $0, $87 and $90, respectively	0	161	167
Amortization of net loss, net of tax of $10,676, $7,676 and $4,472, respectively	19,828	14,256	8,306
Current period change in fair value of pension and postretirement plans, net of tax of $1,779, ($2,722), and $6,237, respectively	3,305	(5,056)	11,582
Total pension and postretirement plans	23,133	9,375	20,262
Comprehensive Income (Loss)	(922,598)	565,229	192,798
Commodity contracts
Cash flow hedges:
Current period change in fair value value of derivative instruments, net of tax	0	37	(10,866)
Reclassification adjustment for derivative instruments, net of tax	0	(13,399)	(22,124)
Interest rate swap
Cash flow hedges:
Current period change in fair value value of derivative instruments, net of tax	0	(298)	(148)
Reclassification adjustment for derivative instruments, net of tax	$ 0	$ 1,482	$ 1,120

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current period change in fair value of interest rate swap, tax		$ 23	$ (6,660)
Amortization of net obligation at transition, tax	$ 0	8	112
Amortization of prior service cost, tax	0	87	90
Amortization of net loss, tax	10,676	7,676	4,472
Current period change in fair value of pension and postretirement plans, tax	1,779	(2,722)	6,237
Commodity contracts
Current period change in fair value of interest rate swap, tax	0	23	(6,660)
Reclassification adjustment for derivative instruments, tax	0	(8,212)	(13,560)
Interest rate swap
Current period change in fair value of interest rate swap, tax	0	(160)	(80)
Reclassification adjustment for derivative instruments, tax	$ 0	$ 798	$ 603

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Premium on Capital Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Deferred Compensation Plan	Treasury Stock
Beginning balance, shares at Dec. 31, 2012		75,067,760
Beginning balance, value at Dec. 31, 2012	$ 2,676,690	$ 751	$ 494,910	$ 2,314,055	$ (8,311)	$ 2,774	$ (127,489)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	204,554			204,554
Other comprehensive income (loss)	(11,756)				(11,756)
Purchase of treasury shares, net (73,206 shares in 2015, 32,768 shares in 2014, 14,766 shares in 2013)	(1,038)						(1,038)
Purchase and retirement of shares, shares		0
Shares issued for employee benefit plans, shares		506,396
Shares issued for employee benefit plans	18,795	$ 5	18,790
Deferred compensation obligation	0					485	(485)
Stock-based compensation	9,625		6,869				2,756
Tax benefit from employee stock plans	3,142		3,142
Cash dividends, per share - ($0.08 in 2015, $0.47 in 2014, $0.58 in 2013)	(41,993)			(41,993)
Ending balance, shares at Dec. 31, 2013		75,574,156
Ending balance, value at Dec. 31, 2013	2,858,019	$ 756	523,711	2,476,616	(20,067)	3,259	(126,256)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	568,032			568,032
Other comprehensive income (loss)	(2,803)				(2,803)
Purchase of treasury shares, net (73,206 shares in 2015, 32,768 shares in 2014, 14,766 shares in 2013)	(2,547)						(2,547)
Purchase and retirement of shares, shares		(226,839)
Purchase and retirement of shares, value	(14,913)	$ (2)	(2,388)	(12,523)
Shares issued for employee benefit plans, shares		528,394
Shares issued for employee benefit plans	25,501	$ 5	25,496
Deferred compensation obligation	0					(397)	397
Stock-based compensation	11,713		11,713
Tax benefit from employee stock plans	5,906		5,906
Cash dividends, per share - ($0.08 in 2015, $0.47 in 2014, $0.58 in 2013)	$ (34,304)			(34,304)
Ending balance, shares at Dec. 31, 2014	75,875,711	75,875,711
Ending balance, value at Dec. 31, 2014	$ 3,414,604	$ 759	564,438	2,997,821	(22,870)	2,862	(128,406)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(945,731)			(945,731)
Other comprehensive income (loss)	23,133				23,133
Purchase of treasury shares, net (73,206 shares in 2015, 32,768 shares in 2014, 14,766 shares in 2013)	(4,723)						(4,723)
Shares issued for stock offering, shares		5,700,000
Shares issued for stock offering	398,620	$ 57	398,563
Purchase and retirement of shares, shares		0
Shares issued for employee benefit plans, shares		194,450
Shares issued for employee benefit plans	6,739	$ 2	6,737
Deferred compensation obligation	0					(897)	897
Stock-based compensation	8,228		8,228
Tax benefit from employee stock plans	1,064		1,064
Cash dividends, per share - ($0.08 in 2015, $0.47 in 2014, $0.58 in 2013)	$ (6,074)			(6,074)
Ending balance, shares at Dec. 31, 2015	81,770,161	81,770,161
Ending balance, value at Dec. 31, 2015	$ 2,895,860	$ 818	$ 979,030	$ 2,046,016	$ 263	$ 1,965	$ (132,232)

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CONSLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (PARENTHETICAL) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
Common stock, cash dividends per share	$ 0.08	$ 0.47	$ 0.58
Treasury shares	73,206	32,768	14,766

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CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Operating Activities
Net income (loss)	$ (945,731)	$ 568,032	$ 204,554
Income from discontinued operations	0	(468,389)	(62,673)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	593,789	548,564	452,876
Asset impairment	1,292,308	416,801	13,906
Accretion of discount on asset retirement obligations	7,108	7,608	6,995
Deferred income taxes	(539,735)	302,890	118,600
Change in derivative fair value	233,315	(346,646)	48,029
(Gain) loss on sale of assets	(28,077)	55	(89)
Stock-based compensation expense	8,028	11,332	13,621
Exploration, including dry holes	7,097	9,325	2,102
Discontinued operations	0	91,510	109,318
Other, net	35,641	4,166	12,284
Net change in:
Accounts receivable	117,486	4,812	23,785
Inventories	(655)	(3,121)	10,817
Accounts payable	(46,283)	18,695	(52,946)
Accrued taxes/income tax receivable	(4,791)	(488,980)	4,092
Pension and other postretirement benefit contributions	(24,848)	(12,483)	(5,677)
Other current assets and liabilities	9,940	41,312	27,783
Net cash provided by operating activities	714,592	705,483	927,377
Investing Activities
Additions to oil and natural gas properties	(1,154,373)	(1,264,059)	(1,109,365)
Acquisitions, net of cash acquired	(87,410)	(70,730)	(31,331)
Proceeds from asset sales and sale of Alabama Gas Corporation	394,521	1,347,725	160,986
Purchase of short-term investments	(919,000)	(473,000)	(310,000)
Sale of short-term investments	919,000	473,000	310,000
Discontinued operations	0	(51,850)	(73,341)
Other, net	0	0	(559)
Net cash used in investing activities	(847,262)	(38,914)	(1,053,610)
Financing Activities
Payment of dividends on common stock	(6,074)	(34,304)	(41,993)
Issuance of common stock, net	399,600	23,053	17,780
Purchase and retirement of shares	0	(14,913)	0
Issuance of long-term debt	0	0	600,000
Reduction of long-term debt	0	(600,000)	(350,000)
Payment of debt issuance costs	0	(10,901)	(2,740)
Net change in credit facility	(262,500)	(4,000)	(77,000)
Tax benefit on stock compensation	1,064	5,906	3,142
Discontinued operations	0	(35,113)	(27,105)
Net cash provided by (used in) financing activities	132,090	(670,272)	122,084
Net change in cash and cash equivalents	(580)	(3,703)	(4,149)
Cash and cash equivalents at beginning of period	1,852	5,555	9,704
Cash and cash equivalents at end of period	1,272	1,852	5,555
Less cash and cash equivalents of discontinued operations at end of period	0	0	(3,032)
Cash and cash equivalents	$ 1,272	$ 1,852	$ 2,523

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Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Basis of Presentation

ORGANIZATION AND BASIS OF PRESENTATION

Energen Corporation (Energen or the Company) is an oil and natural gas exploration and production company engaged in the exploration, development and production of oil, natural gas liquids-rich properties and natural gas primarily in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Headquartered in Birmingham, Alabama, our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources).

Energen may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held for sale are reported at the lower of the carrying amount or estimated fair value. Certain of these held for sale properties also qualify as discontinued operations. The results of operations of these properties are reclassified and reported as discontinued operations for prior periods.

Prior to September 2, 2014, Energen owned Alabama Gas Corporation (Alagasco), which was engaged in the purchase, distribution and sale of natural gas principally in central and north Alabama. On September 2, 2014, Energen completed the transaction to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion resulting in a pre-tax gain of $726.5 million. This sale had an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness. During 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. See Note 16, Discontinued Operations and Held for Sale Properties, for further information regarding the sale of Alagasco.

Liquidity

At December 31, 2015, we had $1.3 million of cash on hand and $1.2 billion of committed financing available under our credit facilities. To finance our operations, working capital and capital spending, we expect to use internally generated cash flow from operations supplemented by our existing $1.4 billionfive-year syndicated credit facility. In addition, we have classified our remaining San Juan Basin properties as held for sale as at December 31, 2015 and, subsequent to year-end, we classified other Permian Basin non-core properties in the Delaware Basin as held for sale.

Energen may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. Access to capital is an integral part of Energen’s business plan. As of December 31, 2015, the Company has $222.5 million outstanding under its revolving credit facilities and $554.0 million outstanding under long term note agreements. While we expect to have ongoing access to our credit facility and capital markets, continued access could be adversely affected by current and future economic and business conditions and possible credit rating downgrades. To the extent current market conditions continue for a prolonged period or worsen, we may be forced to reduce or delay capital and operational expenditures, divest assets, seek additional debt or equity financing, or refinance all or a portion of our debt.

Our debt facilities are subject to certain financial and non-financial covenants as discussed in Note 3, Long Term Debt. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other noncash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0.As of December 31, 2015, we were in compliance with our covenants and expect to maintain compliance during 2016 assuming we are able to execute on our business plan which includes property divestitures and/or access to the capital markets and utilization of our credit facility. However, factors including those outside of our control may prevent us from maintaining compliance with the financial and non-financial covenants, including our total debt to EBITDAX covenant, at future measurement dates in 2016 and beyond. Such factors may include further commodity price declines, lack of liquidity in property and capital markets and our continuing ability to execute on our business plan. The borrowing base on our credit facility is scheduled to be redetermined in April and October of 2016. In the event that we are unable to remain in compliance with our financial and non-financial covenants, we would seek covenant relief at a scheduled redetermination date or at an interim date, as appropriate, during 2016. However, no assurances can be given with respect to such relief. If any such covenant violations are not waived by the lenders such violation would result in an event of default that could trigger acceleration of payment of the amounts outstanding under credit facilities and long term note agreements, which is an aggregate balance outstanding of $776.5 million at December 31, 2015. Additionally, the lenders could refuse to make additional loans under the credit facility, take possession of any collateral, and exercise other remedies or rights that may be available to them, all of which could have a material adverse effect on the business and financial condition of the Company.

Workforce Reduction

On January 22, 2016, we reduced our workforce as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In connection with the reduction, we will incur a total charge of approximately $3.2 million in the first quarter of 2016 for one-time termination benefits.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. Principles of Consolidation

The accompanying consolidated financial statements include Energen and its subsidiaries, principally Energen Resources, after elimination of all significant intercompany transactions in consolidation. In the opinion of management, our consolidated financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods and as of the dates shown. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior periods’ financial statements to the current-year presentation.

B. Oil and Natural Gas Operations

Property and Related Depletion: Energen follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, natural gas liquids and natural gas reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. Energen capitalizes exploratory drilling costs until a determination is made that the well or project has either found proved reserves or is impaired. After an exploratory well has been drilled and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas quantities can be classified as proved. In those circumstances, we continue to capitalize the drilling costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Capitalized exploratory drilling costs are presented in proved properties in the balance sheets. If the exploratory well is determined to be a dry well, the costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves.

Operating Revenues: Energen utilizes the sales method of accounting to recognize oil, natural gas liquids and natural gas production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining proved reserves for such property. Energen had no significant production imbalances at December 31, 2015 and 2014.

Derivative Commodity Instruments: We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen. All derivative transactions are included in operating activities on the consolidated statements of cash flows.

The majority of our counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Energen formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the nature of the risk being hedged. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes.

Effective June 30, 2013, Energen discontinued the use of cash flow hedge accounting and dedesignated all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen in accumulated other comprehensive income until the forecasted transactions actually occurred. Any subsequent gains or losses are accounted for as mark-to-market and recognized immediately through gain (loss) on derivative instruments, net. As a result of Energen’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 are accounted for as mark-to-market transactions with gains or losses recognized in the period of change in gain (loss) on derivative instruments, net.

Asset Impairments: Oil and natural gas proved properties periodically are assessed for possible impairment on a field-by-field basis using the estimated undiscounted future cash flows. Energen monitors its oil and natural gas properties as well as the market and business environments in which it operates and makes assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected production performance. If a material event occurs, we make an estimate of undiscounted future cash flows to determine whether the asset is impaired. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. If the asset is impaired, Energen will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows.

Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These variables can, and often do, differ from the estimates and can have a positive or negative impact on our need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact Energen’s original and ongoing assessments of potential impairment.

Energen also may recognize impairments of capitalized costs for unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by exploration activities, changes in economic factors and potential shifts in business strategy employed by management. We consider a combination of geologic and economic factors to evaluate the need for impairment of these costs.

Long-Lived Assets and Discontinued Operations: Energen may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held for sale are reported at the lower of the carrying amount or estimated fair value. Certain of these held for sale properties also qualify as discontinued operations and the results of operations of these properties are reclassified and reported as discontinued operations for prior periods.

Acquisitions: Energen recognizes all acquisitions at fair value. Energen estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen obtained control of the properties for all acquisitions that qualify as business combinations. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. Energen uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy. Acquisition related costs are expensed as incurred in general and administrative expense on the consolidated income statements.

C. Inventory

Inventories consist primarily of tubular goods and other oilfield equipment used in our operations and are stated at the lower of cost or market value, on a weighted average cost basis.

D. Fair Value Measurements

The carrying values of cash and cash equivalents, accounts payable, accounts receivable (net of allowance), derivative commodity instruments, pension and postretirement plan assets and liabilities and other current assets and liabilities approximate fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). In determining fair value, we use various valuation approaches and classify all assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own assumptions about the assumptions other market participants would use in pricing the asset or liability based on the best information available in the circumstances. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The hierarchy is broken down into three levels based on the observability of inputs as follows:

Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;

Level 2 - Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;

Level 3 - Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumptions that market participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

The fair value of Energen’s derivative commodity instruments is determined using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. Our OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which we are able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX oil and natural gas prices. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. We consider the frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While Energen does not have access to the specific assumptions used in its counterparties’ valuation models, we maintain communications with our counterparties and discuss pricing practices. Further, we corroborate the fair value of our transactions by comparison of market-based price sources.

Energen utilizes a discounted cash flow model in valuing its interest rate derivatives, which are comprised of interest rate swap agreements. The fair value attributable to Energen's interest rate derivative contracts is based on (i) the contracted notional amounts, (ii) active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

Pension and postretirement plan assets include cash and mutual funds. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and Level 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds.

E. Income Taxes

Energen uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. Energen and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.

F. Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in the existing accounts receivable. Energen determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered. Energen had allowance for doubtful accounts of $0.7 million at both December 31, 2015 and 2014, respectively.

G. Cash and Cash Equivalents

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value.

H. Short-term Investments

All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments. As of December 31, 2015 and 2014, Energen had no short-term investments.

I. Earnings Per Share (EPS)

Energen’s basic earnings per share amounts have been computed based on the weighted average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities.

J. Stock-Based Compensation

Energen recognizes all share-based compensation awards in general and administrative expense on the consolidated income statement over the requisite vesting period. Equity awards are measured at fair value as of the date of grant. Awards that are settled in cash are classified as liabilities and re-measured at fair value at the end of each reporting period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. We recognize all stock-based compensation expense in the period of grant, subject to certain vesting requirements, for retirement eligible employees. Energen utilizes the long-form method of calculating the available pool of windfall tax benefit. For the years ended December 31, 2015, 2014 and 2013, we recognized an excess tax benefit of $1.1 million, $5.9 million and $3.1 million, respectively, related to our stock-based compensation.

K. Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, physical quantities of proved oil and gas reserves, periodic assessments of oil and gas properties for impairment, Energen’s obligations under its employee pension and compensation plans, the valuation of derivative financial instruments, the allowance for doubtful accounts, tax contingency reserves, legal contingency reserves, asset retirement obligations and self insurance reserves. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.

L. Employee Benefit Plans

Plan Termination: In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015 and distributed benefits in December 2015.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 with the remainder to be paid in the first quarter of 2016.

Plan Separation: Effective April 30, 2014, Energen separated its defined benefit non-contributory pension plan and its postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan reflecting the separation of assets and obligations in accordance with ERISA provisions. Energen remeasured the plans using current assumptions.

Postretirement Benefit Plans: Energen provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. These postretirement healthcare and life insurance benefits are available upon reaching normal retirement age while working for Energen. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.

For other postretirement plans, certain financial assumptions are used in determining Energen’s projected benefit obligation. These assumptions are examined periodically by Energen, and any required changes are reflected in the subsequent determination of projected benefit obligations.

Energen calculates periodic expense for the other postretirement benefit plans on an actuarial basis and the net funded status is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. The benefit obligation is the accumulated postretirement benefit obligation. Energen measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.

For our other postretirement plan, we selected a yield curve comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments.

The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. Energen considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets.

M. Environmental Costs

Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated.

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Long-Term Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Long-term Debt

LONG-TERM DEBT

Long-term debt consisted of the following:

(in thousands)	December 31, 2015		December 31, 2014
Credit facility	$	222,500	$	485,000
7.40% Medium-term Notes, Series A, due July 24, 2017	2,000		2,000
7.36% Medium-term Notes, Series A, due July 24, 2017	15,000		15,000
7.23% Medium-term Notes, Series A, due July 28, 2017	2,000		2,000
7.32% Medium-term Notes, Series A, due July 28, 2022	20,000		20,000
7.60% Medium-term Notes, Series A, due July 26, 2027	5,000		5,000
7.35% Medium-term Notes, Series A, due July 28, 2027	10,000		10,000
7.125% Medium-term Notes, Series B, due February 15, 2028	100,000		100,000
4.625% Notes, due September 1, 2021	400,000		400,000
Total	776,500		1,039,000
Less unamortized debt discount	413		437
Total	$	776,087	$	1,038,563

The aggregate maturities of Energen’s long-term debt as of December 31, 2015 are as follows:

Years ending December 31, (in thousands)
2016	2017	2018	2019	2020	Thereafter
$—	$19,000	$—	$222,500	$—	$535,000

The debt agreements of Energen contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. Although none of the agreements have events of default based on credit ratings, the interest rates applicable to the syndicated credit facility discussed below may adjust based on credit rating changes during certain periods.

Under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee, a cross default provision provides that any debt default of more than $10 million by Energen or Energen Resources will constitute an event of default by Energen. The Indenture does not include a restriction on the payment of dividends.

Credit Facilities: On September 2, 2014, Energen entered into a five-year syndicated secured credit facility with domestic and foreign lenders. On October 20, 2015, the borrowing base and aggregate commitments were reduced to $1.4 billion in association with the semi-annual redetermination required under the agreement. Energen’s obligations under the $1.4 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. Subject to release of collateral in certain periods upon the achievement of certain investment grade ratings from designated ratings agencies, the credit facility is collateralized by certain assets of Energen, including a pledge of equity interests in subsidiaries of Energen other than Energen Resources, and by mortgages on substantially all of Energen Resources’ oil and natural gas properties. The current credit facility qualifies for classification as long-term debt on the consolidated balance sheets. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other non-cash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0; to maintain a ratio of consolidated current assets (adjusted to include amounts available for borrowings and exclude non-cash derivative instruments) to consolidated current liabilities (adjusted to exclude maturities under the credit facility and non-cash derivative instruments) greater than or equal to 1.0 to 1.0; and, during certain periods, to maintain a ratio of the net present value of proved reserves of our oil and natural gas properties to consolidated total debt greater than or equal to 1.50 to 1.0. We are also bound by covenants which limit our ability to incur additional indebtedness, make certain distributions or alter our corporate structure. Energen may not pay dividends during an event of default, if the payment would result in an event of default or if availability is less than 10 percent of the loan limit under the credit facility. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes. In addition, the terms of our credit facility limit the amount we can borrow to a borrowing base amount which is determined by our lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria including commodity price outlook. The borrowing base amount is subject to redetermination semi-annually and for event-driven unscheduled redeterminations. Our next scheduled redetermination is April 1, 2016. See Note 1, Organization and Basis of Presentation, for discussion of financial covenants under liquidity.

Under Energen’s credit facility, a cross default provision provides that any debt default of more than $75 million by Energen or Energen Resources will constitute an event of default by Energen.

Upon an uncured event of default under the credit facility, all amounts owing under the credit facility, if any, depending on the nature of the event of default will automatically, or may upon notice by the administrative agent or the requisite lenders thereunder, become immediately due and payable and the lenders may terminate their commitments under the defaulted facility. Energen was in compliance with the terms of its credit facility as of December 31, 2015.

The following is a summary of information relating to Energen’s credit facility:

(in thousands)	December 31, 2015			December 31, 2014
Credit facility outstanding	$	222,500		$	485,000
Available for borrowings	1,177,500			1,515,000
Total borrowing commitments	$	1,400,000		$	2,000,000
Maximum amount outstanding at any month-end	$	685,000		$	750,000
Average daily amount outstanding	$	358,929		$	482,166
Weighted average interest rates based on:
Average daily amount outstanding	1.60		%	1.46		%
Amount outstanding at year-end	1.64		%	1.67		%

Energen’s total interest expense was $43.1 million, $37.8 million and $39.7 million for the years ended December 31, 2015, 2014 and 2013, respectively. Energen’s total interest expense for the years ended December 31, 2015, 2014 and 2013 included amortization of debt issuance costs of $3.3 million, $5.7 million and $2.0 million, respectively. Capitalized interest expense for the year ended December 31, 2015 was not significant. Capitalized interest expense was $0.2 million for both the years ended December 31, 2014 and 2013. At December 31, 2015, Energen paid commitment fees on the unused portion of available credit facilities at a current annual rate of 30 basis points per annum.

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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

The components of Energen’s income taxes consisted of the following:

Years ended December 31, (in thousands)	2015			2014			2013
Taxes estimated to be payable currently:
Federal	$	3,972		$	161,576		$	23,342
State	758			72,379			2,516
Total current	4,730			233,955			25,858
Taxes deferred:
Federal	(513,187		)	144,645			85,950
State	(26,548		)	(34,447		)	(2,300		)
Total deferred	(539,735		)	110,198			83,650
Total income tax expense (benefit)	$	(535,005	)	$	344,153		$	109,508

The components of Energen’s income taxes consisted of the following:

Years ended December 31, (in thousands)	2015			2014		2013
Income tax expense (benefit) from continuing operations	$	(535,005	)	$	40,728	$	74,323
Income tax expense from discontinued operations	—			17,928		33,174
Income tax expense from gain on disposal of discontinued operations	—			285,497		2,011
Total income tax expense (benefit)	$	(535,005	)	$	344,153	$	109,508

Energen elected early adoption of Accounting Standards Update (ASU) No. 2015-17, Balance Sheet Classification of Deferred Taxes, prospectively as of December 31, 2015. This update requires that deferred tax liabilities and assets be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of each jurisdiction of an entity be offset and presented as a single amount is not affected by the amendments in this update. We reclassified $14.5 million from a current deferred income tax asset to a noncurrent deferred income tax liability at December 31, 2015.

Temporary differences and carryforwards which gave rise to Energen’s deferred tax assets and liabilities were as follows:

(in thousands)	December 31, 2015					December 31, 2014
	Current		Noncurrent			Current			Noncurrent
Deferred tax assets:
Minimum tax credit	$	—	$	44,862		$	—		$	46,338
Allowance for doubtful accounts	—		253			244			—
Insurance and other accruals	—		2,807			2,537			—
Compensation accruals	—		11,650			11,355			—
Pension and other costs	—		8,693			—			7,009
Other comprehensive income	—		—			10,732			1,581
State net operating losses and other carryforwards	—		12,577			—			15,392
Other	—		962			665			—
Total deferred tax assets	—		81,804			25,533			70,320
Valuation allowance	—		(4,235		)	(1,122		)	(2,467		)
Total deferred tax assets	—		77,569			24,411			67,853

Deferred tax liabilities:
Depreciation and basis differences	—		620,629			—			1,057,430
Derivative instruments	—		2,838			102,691			—
Other comprehensive income	—		141			—			—
Other	—		6,330			884			10,909
Total deferred tax liabilities	—		629,938			103,575			1,068,339
Net deferred tax liabilities	$	—	$	(552,369	)	$	(79,164	)	$	(1,000,486	)

Energen files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2015, the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $44.9 million. Energen has a noncurrent deferred tax asset of $8.4 million relating to Energen Resources’ $191.3 million state net operating loss carryforward which will expire beginning in 2027. Energen Resources anticipates generating adequate future taxable income from the reversals of its existing taxable temporary differences to fully realize this benefit. Energen has a full valuation allowance recorded against a noncurrent deferred tax asset of $4.2 million arising from certain state net operating loss and charitable contribution carryforwards. Energen intends to fully reserve this asset until it is determined that it is more likely than not that the asset can be realized through future taxable income in the respective state taxing jurisdictions. No other valuation allowance with respect to deferred taxes is deemed necessary as Energen anticipates generating adequate future taxable income from the reversals of its existing taxable temporary differences to realize the benefits of all remaining deferred tax assets on the consolidated balance sheets.

Total income tax expense from continuing operations differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:

Years ended December 31, (in thousands)	2015			2014			2013
Income tax expense (benefit) at statutory federal income tax rate	$	(518,258	)	$	49,130		$	75,671
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	(14,112		)	93			1,461
Impact of state law changes	(3,075		)	(121		)	(1,966		)
Impact of state deferred tax revaluation on San Juan properties	(1,241		)	(8,382		)	—
401(k) stock dividend deduction	—			(232		)	(449		)
Other, net	1,681			240			(394		)
Total income tax expense (benefit)	$	(535,005	)	$	40,728		$	74,323
Effective income tax rate (%)	36.13			29.01			34.38

In addition to other changes in state apportionment reflected in the state income taxes, net of federal income tax benefit above,Energen recognized a $1.2 million and an $8.4 million income tax benefit during the 4th quarter of 2015 and 2014, respectively, as a result of re-measuring its state deferred tax liabilities. This re-measurement reflected the state apportionment changes related to certain San Juan Basin properties designated as held for sale as of December 31, 2015, and 2014. 

A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows:

(in thousands)
Balance as of December 31, 2012	$	12,555
Additions based on tax positions related to the current year	4,546
Additions for tax positions of prior years	366
Reductions for tax positions of prior years	(46		)
Lapse of statute of limitations	(1,435		)
Balance as of December 31, 2013	15,986
Additions based on tax positions related to the current year	3,873
Additions for tax positions of prior years	19
Reductions for tax positions of prior years	(954		)
Lapse of statute of limitations	(1,394		)
Balance as of December 31, 2014	17,530
Additions based on tax positions related to the current year	2,378
Reductions based on tax positions related to the current year	(6,589		)
Reductions for tax positions of prior years	(345		)
Lapse of statute of limitations	(1,785		)
Balance as of December 31, 2015	$	11,189

The amount of unrecognized tax benefits at December 31, 2015 that would favorably impact Energen’s effective tax rate, if recognized, is $3 million. Energen recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2015, 2014, and 2013, Energen recognized approximately $2,000 of income, $27,000 of expense and $15,000 of expense for interest (net of tax benefit) and penalties, respectively. Energen had approximately $0.2 million and $0.2 million for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2015 and 2014, respectively.

Energen’s tax returns for years 2012-2014 remain open and subject to examination by the IRS and major state taxing jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations is highly uncertain, Energen does not expect that the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

Plan Terminations: In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015 and distributed benefits in December 2015.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 and with the remainder to be paid in the first quarter of 2016. In connection with the termination of these plans, Energen has also classified approximately $3.3 million as of December 31, 2015 of its investment in a Rabbi Trust from other long term assets to prepayments and other assets in the accompanying balance sheets to reflect its intent to utilize these assets to partially fund the estimated payments in the first quarter of 2016.

Effective April 30, 2014, Energen separated its defined benefit non-contributory pension plan and its postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan reflecting the separation of assets and obligations in accordance with ERISA provisions. Energen remeasured the plans using current assumptions.

Benefit Obligations: The following table sets forth the combined funded status of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in Energen’s consolidated financial statements.

As of December 31, (in thousands)	2015			2014			2015			2014
	Pension						Postretirement Benefits
Accumulated benefit obligation	$	15,729		$	107,669
Benefit obligation:
Balance at beginning of period	$	107,669		$	266,294		$	11,127		$	33,224
Service cost	—			8,329			392			262
Interest cost	816			5,325			466			716
Actuarial (gain) loss	(683		)	9,078			(1,185		)	6,385
Plan amendments	—			—			(4,071		)	—
Curtailment gain	—			(8,496		)	—			—
Transfer in connection with the sale of Alagasco	—			(124,783		)	—			(28,648		)
Termination benefit charge	—			2,477			—			—
Retiree drug subsidy program	—			—			—			48
Benefits paid	(92,073		)	(50,555		)	(241		)	(860		)
Balance at end of period	$	15,729		$	107,669		$	6,488		$	11,127
Plan assets:
Fair value of plan assets at beginning of period	$	67,542		$	193,457		$	10,693		$	55,459
Actual return (loss) on plan assets	(289		)	5,359			(83		)	(331		)
Employer contributions	24,847			19,164			—			21
Transfer in connection with the sale of Alagasco	—			(99,883		)	—			(43,596		)
Benefits paid	(92,073		)	(50,555		)	(241		)	(860		)
Fair value of plan assets at end of period	$	27		$	67,542		$	10,369		$	10,693
Funded status of plans	$	(15,702	)	$	(40,127	)	$	3,881		$	(434	)

Noncurrent assets	$	—		$	—		$	3,881		$	—
Current liabilities	(15,702		)	(24,626		)	—			—
Noncurrent liabilities	—			(15,501		)	—			(434		)
Net asset (liability) recognized	$	(15,702	)	$	(40,127	)	$	3,881		$	(434	)
Amounts recognized to accumulated other comprehensive income:
Prior service credit, net of taxes	$	—		$	—		$	(2,646	)	$	—
Net actuarial loss, net of taxes	2,179			22,246			205			624
Total accumulated other comprehensive income (loss)	$	2,179		$	22,246		$	(2,441	)	$	624

Other investment assets designated for payment of the nonqualified supplemental retirement plans were as follows:

	December 31, 2015
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	$	3,308	$	—	$	3,308
Total	$	3,308	$	—	$	3,308

	December 31, 2014
(in thousands)	Level 1		Level 2		Total
Fixed income	$	—	$	4,255	$	4,255
Cash and cash equivalents	9,929		—		9,929
Total	$	9,929	$	4,255	$	14,184

While intended for payment of the nonqualified supplemental retirement plan benefits, these assets remain subject to the claims of Energen’s creditors and are not recognized in the funded status of the plan. These assets are recorded at fair value and included in prepayments and other and other assets in the consolidated balance sheets.

The components of net periodic benefit cost from continuing operations were as follows:

Years ended December 31, (in thousands)	2015			2014			2013
Pension Plans
Components of net periodic benefit cost:
Service cost	$	—		$	6,808		$	5,196
Interest cost	816			4,498			4,496
Expected long-term return on assets	—			(4,386		)	(5,225		)
Prior service cost amortization	—			202			246
Actuarial loss amortization	737			4,995			6,919
Termination benefit charge	—			2,477			—
Settlement charge	29,767			4,082			161
Curtailment expense (gain)	—			254			(4		)
Net periodic expense	$	31,320		$	18,930		$	11,789
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	392		$	253		$	386
Interest cost	466			661			645
Expected long-term return on assets	(457		)	(1,122		)	(787		)
Actuarial gain amortization	—			(653		)	(28		)
Transition obligation amortization	—			44			229
Net periodic (income) expense	$	401		$	(817	)	$	445

Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows:

Years ended December 31, (in thousands)	2015			2014			2013
Pension Plans
Net actuarial (gain) loss experienced during the year	$	(394	)	$	10,495		$	(14,138	)
Net actuarial loss recognized as expense	(30,478		)	(25,433		)	(8,934		)
Prior service cost recognized as expense	—			(246		)	(311		)
Curtailment loss	—			(8,749		)	—
Total recognized in other comprehensive income (loss)	(30,872		)	(23,933		)	(23,383		)
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	(645	)	$	7,649		$	(8,057	)
Prior service credit during the year	(4,071		)	—			—
Net actuarial gain recognized as expense	—			1,908			550
Transition obligation recognized as expense	—			(48		)	(283		)
Total recognized in other comprehensive income (loss)	$	(4,716	)	$	9,509		$	(7,790	)

In the year ended December 31, 2015, Energen incurred settlement charges of $27.3 million for the payment of lump sums from the qualified defined benefit pension plans. Also in the first quarter of 2015, Energen incurred a settlement charge of $2.5 million for the payment of lump sums from the non-qualified supplemental retirement plans.

During the year ended December 31, 2014, Energen incurred settlement charges of $7.6 million for the payment of lump sums from the qualified defined benefit pension plans of which $3.7 million is included in discontinued operations. Also during 2014, Energen incurred settlement charges of $0.4 million for the payment of lump sums from the non-qualified supplemental retirement plans. In the fourth quarter of 2014, Energen incurred a settlement charge of $1.8 million for the payment of lump sums from the non-qualified supplemental retirement plans which is included in discontinued operations. In the fourth quarter of 2014, Energen recognized a termination benefit charge of $2.5 million to provide for early retirement of certain non-highly compensated employees. In conjunction with the sale of Alagasco, Energen recognized a curtailment loss of $0.3 million in the fourth quarter of 2014.

For the year ended December 31, 2013, Energen incurred settlement charges of $0.6 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.2 million was expensed and $0.4 million was recognized as a regulatory asset at Alagasco. In conjunction with the sale of its Black Warrior Basin coalbed methane properties in Alabama, Energen recognized a curtailment gain of $1.2 million in the fourth quarter of 2013.

Estimated amounts to be amortized, including settlement charges, from accumulated other comprehensive income into pension cost during 2016 are included in the table below.

(in thousands)
Amortization of net actuarial loss	$	3,352

Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2016 are included in the table below.

(in thousands)
Amortization of prior service credit	$	(515	)

Energen has a long-term disability plan covering most employees. Energen had expense of $0.2 million for each of the years ended December 31, 2015, 2014 and 2013.

Assumptions: The weighted average rate assumptions to determine net periodic benefit costs were as follows:

Years ended December 31,	2015		2014		2013
Pension Plans
Discount rate	0.96	%	3.66	%	3.63	%
Expected long-term return on plan assets	—	%	7.00	%	7.00	%
Rate of compensation increase for pay-related plans	—	%	3.63	%	3.71	%
Postretirement Benefit Plans
Discount rate	4.25	%	4.88	%	4.36	%
Expected long-term return on plan assets	6.20	%	7.00	%	7.00	%
Rate of compensation increase	—	%	3.60	%	3.70	%

The pension benefit obligation as of December 31, 2014 represents the present value of the estimated cost of settling the benefit obligation of the plan. For our defined benefit pension plan, we discounted the estimated termination liability using the one year spot rate of 0.70 percent. For the year ended December 31, 2015, the discount rate shown above represents the weighted average for the nonqualified supplemental retirement plan. The discount rate shown below represents the weighted average for both the defined qualified and nonqualified supplemental retirement plans for the year ended December 31, 2014. For the year ended December 31, 2015, the expected long-term return on plan assets no longer applies for our defined benefit pension plan as the assets of the nonqualified supplemental retirement plan are not considered qualifying assets. As the plans were frozen as of December 31, 2014, the rate of compensation increase no longer applies for any of the plans. The weighted average assumptions used to determine the benefit obligations at the measurement date were as follows:

Years ended December 31,	2015		2014
Pension Plans
Discount rate	3.90	%	0.96	%
Postretirement Benefit Plans
Discount rate	4.70	%	4.25	%

The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows:

As of December 31,	2015		2014
Health care cost trend rate assumed for next year	7.75	%	7.25	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2026		2021

Health care costs trend rates will not have a material impact to the accumulated postretirement benefit obligation due to the separation of assets and obligations of the postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan. Employees remaining at Energen will receive a fixed postretirement benefit.

Investment Strategy: For our postretirement benefit plan assets, we continue to employ a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.

Energen seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, commodity or class of investment fund.

The Company’s weighted average plan asset allocations by asset category were as follows:

	Pension						Postretirement Benefits
As of December 31,	Target		2015		2014		Target		2015		2014
Asset category:
Equity securities	—	%	—	%	—	%	56	%	56	%	60	%
Debt securities	—	%	—	%	—	%	44	%	44	%	40	%
Cash and cash equivalents	100	%	100	%	100	%	—	%	—	%	—	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

Equity securities for postretirement benefits do not include the Company’s common stock.

Plan assets included in the funded status of the pension plans were as follows:

	December 31, 2015
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	27		$	—	$	27
Total	$	27	$	—	$	27

	December 31, 2014
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	$	67,542	$	—	$	67,542
Total	$	67,542	$	—	$	67,542

Plan assets included in the funded status of the postretirement benefit plans were as follows:

	December 31, 2015
(in thousands)	Level 1		Level 2		Total
United States equities	$	4,185	$	—	$	4,185
Global equities	1,650		—		1,650
Fixed income	—		4,534		4,534
Total	$	5,835	$	4,534	$	10,369

	December 31, 2014
(in thousands)	Level 1		Level 2		Total
United States equities	$	4,715	$	—	$	4,715
Global equities	1,711		—		1,711
Fixed income	—		4,267		4,267
Total	$	6,426	$	4,267	$	10,693

Energen had no Level 3 postretirement benefit plan assets. United States equities consists of mutual funds with varying strategies. These funds invest largely in medium to large capitalized companies with exposure blending growth, market-oriented and value styles. Additional fund investments include small capitalization companies, and certain of these funds utilize tax-sensitive management approaches. Global equities are mutual funds that invest in non-United States securities broadly diversified across most developed markets with exposure blending growth, market-oriented and value styles. Fixed income securities are high-quality short-duration securities including investment-grade market sectors with tactical investments in non-investment grade sectors.

Cash Flows: The Company expects to make benefit payments, which will be partially funded by the Rabbi Trust, of approximately $14.6 million during 2016 with respect to the termination of the nonqualified supplemental retirement plans.

Due to restructuring of our plans, Energen no longer qualifies for benefits related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows:

(in thousands)	Pension Benefits	Postretirement Benefits
2016	$14,606	$198
2017	$117	$213
2018	$114	$245
2019	$110	$258
2020	$107	$289
2021-2025	$472	$1,769

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Common Stock Plans

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Common Stock Plans

COMMON STOCK PLANS

Energen Employee Savings Plan (ESP): In October 2014, Energen’s Board of Directors amended and restated the ESP to make certain benefit design changes effective January 1, 2015. The benefit design changes include an increase in the percentage of Energen match and other contributions. A majority of our employees are eligible to participate in the ESP by electing to contribute a portion of their compensation to the ESP. Energen may match a percentage of the contributions and make these contributions in Energen common stock or in funds for the purchase of Energen common stock. Employees may diversify 100 percent of their ESP Energen stock account into other ESP investment options. The ESP also contains employer supplemental contributions. Effective January 1, 2015, the Company match will no longer be contributed in Energen common stock. Expense associated with Energen contributions to the ESP was $5.7 million, $3.7 million and $3.7 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Stock Incentive Plan: The Stock Incentive Plan provided for the grant of performance share awards and restricted stock units and restricted stock. The Stock Incentive Plan also provided for the grant of non-qualified stock options and incentive stock options to officers and key employees. Energen has typically funded performance share obligations, restricted stock obligations and options through original issue shares and restricted stock through treasury shares. Under the Stock Incentive Plan, established in 1997, 8,600,000 shares of Energen common stock were reserved for issuance, adjusted for stock splits, with 2,294,740 remaining for issuance as of December 31, 2015.

Performance Share Awards: The Stock Incentive Plan provided for the grant of performance share awards to eligible employees based on predetermined Energen performance criteria at the end of an award period. The Stock Incentive Plan provided that payment of earned performance share awards be made in the form of Energen common stock.

A summary of performance share award activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 is presented below:

	Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2012	—		$	—
Granted (two-year vesting period)	86,221		61.14
Granted (three-year vesting period)	82,606		62.96
Forfeited	(8,008	)	60.03
Nonvested at December 31, 2013	160,819		62.13
Granted (two-year vesting period)	937		131.56
Granted (three-year vesting period)	65,309		93.49
Vested and paid	(14,097	)	70.06
Nonvested at December 31, 2014	212,968		71.53
Granted (three-year vesting period)	120,372		83.94
Vested and paid	(77,257	)	61.36
Nonvested at December 31, 2015	256,083		$	80.43

Energen recorded expense of $6.7 million, $6.2 million and $3.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, for performance share awards with a related deferred income tax benefit of $2.4 million, $2.3 million and $1.4 million. As of December 31, 2015, there was $8.9 million of total unrecognized compensation cost related to performance share awards. These awards have a remaining weighted average requisite service period of 1.66 years.

Restricted Stock: In addition, the Stock Incentive Plan provided for the grant of restricted stock and restricted stock units (restricted stock awards) which have been valued based on the quoted market price of Energen’s common stock at the date of grant. Restricted stock awards vest within three years from grant date. A summary of restricted stock award activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 is presented below:

	Stock Incentive Plan
	Awards		Weighted Average Price
Nonvested at December 31, 2012	11,115		$	45.24
Restricted stock granted	52,650		52.34
Forfeited	(1,247	)	48.36
Nonvested at December 31, 2013	62,518		51.16
Restricted stock units granted	48,904		71.91
Vested	(11,848	)	65.94
Nonvested at December 31, 2014	99,574		59.60
Restricted stock units granted	99,814		65.15
Vested	(14,446	)	53.20
Nonvested at December 31, 2015	184,942		$	63.09

Energen recorded expense of $6.0 million, $3.2 million and $1.9 million for the years ended December 31, 2015, 2014 and 2013, respectively, related to restricted stock awards, with a related deferred income tax benefit of $2.1 million, $1.2 million and $0.7 million, respectively. As of December 31, 2015, there was $1.9 million of total unrecognized compensation cost related to nonvested restricted stock awards recorded in premium on capital stock. These awards have a remaining requisite service period of 1.75 years.

Stock Options: The Stock Incentive Plan provided for the grant of non-qualified stock options, incentive stock options, or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provided for the purchase of Energen common stock at not less than the fair market value on the date the option was granted. The sale or transfer of the shares is limited during certain periods. All outstanding options are incentive or non-qualified, vest within three years from date of grant and expire 10 years from the grant date.

A summary of stock option activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 are presented below:

	Stock Incentive Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2012	1,648,475		$	47.58
Granted	137,762		49.22
Exercised	(590,119	)	40.92
Forfeited	(5,074	)	51.85
Outstanding at December 31, 2013	1,191,044		51.06
Granted	110,307		72.55
Exercised	(544,280	)	50.09
Outstanding at December 31, 2014	757,071		54.88
Exercised	(23,680	)	41.42
Outstanding at December 31, 2015	733,391		$	55.32
Exercisable at December 31, 2013	713,445		$	49.80
Exercisable at December 31, 2014	454,938		$	51.88
Exercisable at December 31, 2015	622,156		$	53.80

Energen uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values:

Grant date	4/15/2014	1/22/2014	10/15/2013	1/24/2013
Awards granted	2,439	107,868	3,686	134,076
Fair market value of stock option at grant	$32.22	$27.57	$30.53	$16.66
Expected life of award	5.8 years	5.8 years	5.8 years	5.8 years
Risk-free interest rate	1.93%	2.06%	1.79%	1.01	%
Annualized volatility rate	40.7%	40.7%	40.6%	40.3	%
Dividend yield	0.2%	0.8%	0.7%	1.2	%

Energen recorded stock option expense of $0.4 million, $2.9 million and $3.4 million during the years ended December 31, 2015, 2014 and 2013, respectively, with a related deferred tax benefit of $0.1 million, $1.1 million and $1.3 million, respectively.

The total intrinsic value of stock options exercised during the year ended December 31, 2015, was $0.7 million. During the year ended December 31, 2015, Energen received cash of $1.0 million from the exercise of stock options. Total intrinsic value for outstanding options as of December 31, 2015, was $0.3 million and $0.3 million for exercisable options. The fair value of options vested for the year ended December 31, 2015 was $3.7 million. As of December 31, 2015, there was $0.1 million of unrecognized compensation cost related to outstanding nonvested stock options.

The following table summarizes options outstanding as of December 31, 2015:

Stock Incentive Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
$46.45	19,990	1.00 year
$60.56	48,560	2.00 years
$29.79	24,291	3.00 years
$46.69	26,481	4.00 years
$54.99	104,841	5.00 years
$54.11	271,164	6.00 years
$48.36	124,071	7.00 years
$80.48	3,686	7.79 years
$72.39	107,868	8.00 years
$79.63	2,439	8.00 years
$29.79-$80.48	733,391	5.76 years

The weighted average remaining contractual life of currently exercisable stock options is 5.43 years as of December 31, 2015.

Stock Appreciation Rights Plan: The Energen Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Energen common stock. Officers of Energen are not eligible to participate in this Plan. These awards are liability awards which settle in cash and are remeasured each reporting period until settlement. These awards have a three year requisite service period.

A summary of stock appreciation rights activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 are presented below:

	Stock Appreciation Rights Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2012	653,030		$	44.14
Granted	88,000		48.36
Exercised/forfeited	(363,653	)	39.66
Outstanding at December 31, 2013	377,377		49.48
Granted	62,749		72.39
Exercised/forfeited	(164,976	)	52.37
Outstanding at December 31, 2014	275,150		52.96
Exercised/forfeited	(10,283	)	55.18
Outstanding at December 31, 2015	264,867		$	52.88

Energen issued the following awards with stock appreciation rights. Energen uses the Black-Scholes pricing model to calculate the fair values of the rights awarded. On December 19, 2013, we modified certain stock appreciation rights subsequent to the original grant date. For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2015:

Grant date	1/22/2014	1/22/2014	1/24/2013	1/24/2013	1/24/2013	1/26/2011
		(modified)		(modified)	(modified)
Awards granted	62,227	522	83,654	768	3,578	182,199
Fair market value of award	$5.11	$1.67	$8.30	$5.64	$4.24	$4.80
Expected life of award	4.56 years	2.13 years	3.57 years	2.13 years	1.50 years	2.53 years
Risk-free interest rate	1.67%	1.11%	1.43%	1.11%	0.80%	1.23%
Annualized volatility rate	33.4%	33.4%	33.4%	33.4%	33.4%	33.4%
Dividend yield	0.20%	0.20%	0.20%	0.20%	0.20%	0.20%

Grant date	1/26/2011	1/27/2010	1/28/2009	2/4/2008	2/1/2007
	(modified)
Awards granted	7,785	171,749	305,257	67,093	85,906
Fair market value of award	$2.74	$5.95	$13.18	$0.81	$2.16
Expected life of award	1.50 years	2.04 years	1.54 years	1.05 years	0.54 years
Risk-free interest rate	0.80%	1.08%	0.82%	0.65%	0.54%
Annualized volatility rate	33.4%	33.4%	33.4%	33.4%	33.4%
Dividend yield	0.20%	0.20%	0.20%	0.20%	0.20%

Income associated with stock appreciation rights of $3.2 million and $0.4 million was recorded for the years ended December 31, 2015 and 2014. Expense associated with stock appreciation rights of $9.9 million was recorded for the year ended 2013. During the year ended December 31, 2015, the total intrinsic value of stock appreciation rights exercised was $0.1 million. During the year ended December 31, 2015, Energen paid $0.1 million in settlement of stock appreciation rights.

Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provided for the grant of stock equivalent units which may include market conditions. Officers of Energen are not eligible to participate in this Plan. These awards are liability awards which are remeasured each reporting period and settle in cash at completion of the vesting period. Stock equivalent units with service conditions were valued based on Energen’s stock price at the end of the period adjusted to remove the present value of future dividends.

A summary of Petrotech unit activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 are presented below:

	Petrotech Incentive Plan
	Shares
Outstanding at December 31, 2012	141,243
Granted (three-year vesting period)	92,418
Granted (17 month vesting period)	2,952
Paid	(36,792	)
Forfeited	(26,529	)
Outstanding at December 31, 2013	173,292
Granted	76,084
Paid	(4,431	)
Forfeited	(31,075	)
Outstanding at December 31, 2014	213,870
Granted (three-year vesting period)	128,519
Granted (two-year vesting period)	297
Granted (16 month vesting period)	1,648
Paid	(78,430	)
Forfeited	(22,158	)
Outstanding at December 31, 2015	243,746

Energen recognized expense of $3.0 million, $4.5 million and $6.2 million during 2015, 2014 and 2013, respectively, related to these units.

1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allowed officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of Energen’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. Energen has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust’s assets remain subject to the claims of our creditors. Amounts earned under the 1997 Deferred Compensation Plan and invested in Energen common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the consolidated statements of shareholders’ equity. As of December 31, 2015 there were 576,850 shares reserved for issuance from the 1997 Deferred Compensation Plan.

1992 Energen Corporation Directors Stock Plan: In 1992 Energen adopted the Energen Corporation Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Energen common stock. Under the Plan, 11,550 shares, 10,360 shares and 13,500 shares were awarded during the years ended December 31, 2015, 2014 and 2013, respectively, leaving 116,374 shares reserved for issuance as of December 31, 2015.

Stock Repurchase Authorization: By resolution adopted October 22, 2014, the Board of Directors authorized Energen to repurchase up to 3,600,000 shares of Energen common stock. The resolution does not have an expiration date and does not limit Energen’s authorization to acquire shares in connection with tax withholdings and payment of exercise price on stock compensation plans. For the year ended December 31, 2014, Energen repurchased and retired 226,839 shares for $14.9 million pursuant to our repurchase authorization. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2015 and 2013. As of December 31, 2015, a total of 3,373,161 shares remain authorized for future repurchase. Energen also from time to time acquires shares in connection with participant elections under Energen’s stock compensation plans. For the years ended December 31, 2015, 2014 and 2013, Energen acquired 73,126 shares, 32,768 shares and 14,766 shares, respectively, in connection with its stock compensation plans.

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Derivative Commodity Instruments

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Commodity Instruments

DERIVATIVE COMMODITY INSTRUMENTS

The following table details gain (loss) on derivative instruments, net, as follows:

Years ended December 31, (in thousands)	2015			2014		2013
Open non-cash mark-to-market gains (losses) on derivative instruments	$	(281,752	)	$	315,445	$	(47,832	)
Closed gains (losses) on derivative instruments	397,045			19,574		(2,192		)
Gain (loss) on derivative instruments, net	$	115,293		$	335,019	$	(50,024	)

The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets:

(in thousands)	December 31, 2015
								Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	72,563	$	(15,600	)	$	56,963	$	—	$	—	$	56,963
Liabilities
Derivative instruments	16,059		(15,600		)	459		—		—		459
Total derivatives	$	56,504	$	—		$	56,504	$	—	$	—	$	56,504

(in thousands)	December 31, 2014
								Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	339,977	$	(17,640	)	$	322,337	$	—	$	—	$	322,337
Liabilities
Derivative instruments	18,628		(17,640		)	988		—		—		988
Total derivatives	$	321,349	$	—		$	321,349	$	—	$	—	$	321,349

*All derivative instruments were current at December 31, 2015 and 2014.

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. Additionally, Energen is at risk of economic loss based upon the creditworthiness of our counterparties. We were in a net gain position with eleven of our active counterparties and in a net loss position with the remaining one at December 31, 2015. The largest counterparty net gain positions at December 31, 2015, Morgan Stanley Capital Group Inc. and BP Corporation North America Inc., constituted approximately $18.1 million, and $10.7 million, respectively, of Energen’s total net gain on fair value of derivatives.

The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:

Years ended December 31, (in thousands)	Location on Statements of Income	2014		2013
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $23 and ($6,660)	—	$	37	$	(10,866	)
Gain reclassified from accumulated other comprehensive income into income (effective portion)	Gain (loss) on derivative instruments, net	$	21,612	$	34,293
Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Gain (loss) on derivative instruments, net	$	—	$	835

The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:

Years ended December 31, (in thousands)	Location on Statements of Income	2015		2014		2013
Gain (loss) recognized in income on derivatives	Gain (loss) on derivative instruments, net	$	115,293	$	313,408	$	(73,980	)

As of December 31, 2015, Energen entered into the following transactions for 2016 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Oil
2016	1,086	MBbl	$63.80 Bbl	NYMEX Swaps
Oil Basis Differential
2016	7,524	MBbl	$(1.92) Bbl	WTI/WTI Basis Swaps
2016	2,117	MBbl	$(1.63) Bbl	WTS/WTI Basis Swaps
WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

As of December 31, 2015, the maximum term over which Energen has hedged exposures to the variability of cash flows is through December 31, 2016.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Energen classifies the fair value of multiple derivative instruments executed under master netting arrangements as net derivative assets and liabilities. The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis:

	December 31, 2015
(in thousands)	Level 2		Level 3			Total
Assets
Derivative instruments	$	69,864	$	(12,901	)	$	56,963
Liabilities
Derivative instruments	2,699		(3,158		)	(459		)
Net derivative asset (liability)	$	72,563	$	(16,059	)	$	56,504

	December 31, 2014
(in thousands)	Level 2		Level 3			Total
Assets
Derivative instruments	$	294,865	$	27,472		$	322,337
Liabilities
Derivative instruments	2,048		(3,036		)	(988		)
Net derivative asset	$	296,913	$	24,436		$	321,349

At December 31, 2015, Energen had interest rate swap agreements with a notional value of $66.7 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 1.0425 percent. The fair value of our interest rate swap was a $0.2 million and a $0.8 million liability at December 31, 2015 and 2014, respectively, and are classified as Level 2 fair value liabilities. The fair value of our interest rate swaps are recognized on a gross basis in accounts payable on the consolidated balance sheet.

Energen prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its Level 3 instruments. We estimate that a 10 percent increase or decrease in commodity prices would result in an approximate $0.1 million change in the fair value of open Level 3 derivative contracts and to the results of operations.

The table below sets forth a summary of changes in the fair value of Energen’s Level 3 derivative commodity instruments as follows:

Years ended December 31, (in thousands)	2015			2014			2013
Balance at beginning of period	$	24,436		$	18,289		$	89,019
Realized gains	13,145			22,208			55,210
Unrealized gains (losses) relating to instruments held at the reporting date*	(40,495		)	2,981			(71,367		)
Settlements during period	(13,145		)	(19,042		)	(54,573		)
Balance at end of period	$	(16,059	)	$	24,436		$	18,289

*Includes $16.1 million in mark-to-market losses, $20.2 million in mark-to-market gains and $7.6 million in mark-to-market losses for the years ended December 31, 2015, 2014 and 2013, respectively.

The tables below set forth quantitative information about Energen’s Level 3 fair value measurements of derivative commodity instruments as follows:

(in thousands, except price data)	Fair Value as of December 31, 2015			Valuation Technique*	Unobservable Input*	Range
Oil Basis - WTI/WTI
2016	$	(13,181	)	Discounted Cash Flow	Forward Basis	($0.07 - $0.28) Bbl
Oil Basis - WTS/WTI
2016	$	(2,878	)	Discounted Cash Flow	Forward Basis	($0.19 - $0.31) Bbl

*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in Energen’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values.

Asset retirement obligations:Energen’s asset retirement obligations (ARO) primarily relate to the future plugging, abandonment and reclamation of wells and facilities. We recognize a liability for the fair value of the ARO in the periods incurred. See Note 13, Asset Retirement Obligations, for further discussion related to these ARO’s. These assumptions are classified as Level 3 fair value.

Asset Impairments: We monitor our oil and natural gas properties as well as the market and business environments in which we operate and make assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected field production performance. If a material event occurs, Energen makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, we will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows. Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future.

These assumptions are classified as Level 3 fair value. See Note 14, Asset Impairment, for impairments recognized by Energen during the years ended December 31, 2015, 2014 and 2013.

Financial Instruments Not Carried at Fair Value

The stated value of cash and cash equivalents, short-term investments, accounts receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. Short-term investments purchased and sold during 2015 of $919 million are not considered readily convertible into cash and accordingly are not classified in cash and cash equivalents. In addition, the Company also invested in certain short-term investments that qualify and were classified as cash and cash equivalents. The fair value of Energen’s long-term debt, including the current portion and notes payable to banks, approximates $690.1 million and $993.7 million and has a carrying value of $776.5 million and $1,039.0 million at December 31, 2015 and 2014, respectively. The fair values are based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

Concentration of Credit Risk

Revenues and related accounts receivable from oil and natural gas operations primarily are generated from the sale of produced oil and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect Energen’s overall exposure to credit risk, either positively or negatively, in that our oil and natural gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen considers the credit quality of its purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The two largest purchasers of Energen’s oiland natural gas, Plains Marketing, LP (Plains) and Shell Trading (US) Company, accounted for approximately 47 percent and 21 percent, respectively, of Energen’s accounts receivable for commodity sales as of December 31, 2015. Energen’s other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2015. During the year ended December 31, 2015, Plains accounted for approximately 33 percent of total revenues, excluding the impact of non-cash mark-to-market open derivatives. All other oil and natural gas purchasers each accounted for less than 10 percent of total revenues for the year ended December 31, 2015.

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Exploratory Costs

12 Months Ended

Dec. 31, 2015

Extractive Industries [Abstract]

Exploratory Costs

EXPLORATORY COSTS

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:

Years ended December 31, (in thousands)	2015			2014			2013
Capitalized exploratory well costs at beginning of period	$	119,439		$	57,600		$	79,791
Additions pending determination of proved reserves	634,908			946,751			421,599
Reclassifications due to determination of proved reserves	(650,759		)	(882,254		)	(442,909		)
Exploratory well costs charged to expense	—			(2,658		)	(881		)
Capitalized exploratory well costs at end of period	$	103,588		$	119,439		$	57,600

The following table sets forth capitalized exploratory wells costs:

(in thousands)	December 31, 2015		December 31, 2014
Exploratory wells in progress (drilling rig not released)	$	1,760	$	18,781
Capitalized exploratory well costs for a period of one year or less	101,828		100,658
Total capitalized exploratory well costs	$	103,588	$	119,439

No wells were capitalized for a period greater than one year as of December 31, 2015 and 2014. At December 31, 2015, Energen had 40 gross exploratory wells either drilling or waiting on results from completion and testing. These wells are located in the Permian Basin.

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Reconciliation of Earnings Per Share

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Reconciliation of Earnings Per Share

RECONCILIATION OF EARNINGS PER SHARE

Years ended December 31,
(in thousands, except per share amounts)				2015						2014					2013
	Net Loss			Shares	Per Share Amount			Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	(945,731	)	76,078	$	(12.43	)	$	568,032	72,897	$	7.79	$	204,554	72,318	$	2.83
Effect of dilutive securities
Stock options				—						216					112
Non-vested restricted stock				—						58					20
Performance share awards				—						104					21
Diluted EPS	$	(945,731	)	76,078	$	(12.43	)	$	568,032	73,275	$	7.75	$	204,554	72,471	$	2.82

In periods of loss, shares that otherwise would have been included in diluted average commons shares outstanding are excluded. Energen had 355,915 of excluded shares for the year ended December 31, 2015.

Energen had the following shares that were excluded from the computation of diluted EPS, as inclusion would be anti-dilutive.

Years ended December 31, (in thousands)	2015	2014	2013
Stock options	114	114	134
Non-vested restricted stock	—	3	7
Performance share awards	—	2	4

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Equity Offering

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Equity Offering

EQUITY OFFERING

During the second quarter of 2015, Energen issued 5,700,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $398.6 million, after deducting offering expenses. Net proceeds from this offering were used to repay borrowings under our credit facility and for general corporate purposes.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Under various agreements for third-party gathering, treatment, transportation or other services, Energen is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 5.8 MMBOE through October 2020.

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen and Energen Resources. Historically, the cost of environmental compliance has not materially affected our financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency regarding the Reef Environmental Site in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party under The Comprehensive Environmental Response, Compensation, and Liability Act for the cleanup of the Site. In 2008, Energen hired a third party to transport approximately 3,000 gallons of non-hazardous wastewater to Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Due to its one time use of Reef Environmental for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings and we have accrued a provision for our estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. We recognize a liability for contingencies, including an estimate of legal costs to be incurred, when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results.

On November 4, 2015, Energen Resources filed a suit against Endeavor Energy Resources. L.P. in the District Court of Howard County, Texas, to remove a cloud on the title to approximately 10,000 acres leased by Energen Resources in that county. Energen Resources believes the cloud on title arises from a prior, unreleased but partially terminated oil and gas lease covering the leased lands. The defendant in the action filed a counterclaim alleging Energen Resources tortiously interfered with a prospective contract. The counterclaim seeks $300 million in damages. Energen Resources believes the counterclaim is without merit, and no amount has been accrued as of December 31, 2015. Energen Resources intends to pursue a favorable ruling in the quiet title action and vigorously defend against the counterclaim.

We recently became aware that Energen Resources may be one of multiple defendants in a Petition for Damages to the Cameron Parish Coastal Zone filed by the Parish of Cameron in the 38th Judicial District Court for the Parish of Cameron, State of Louisiana alleging violation of Louisiana’s coastal zone management laws. We are in the very preliminary stages of evaluating our exposure, and no amount has been accrued as of December 31, 2015

New Mexico Audits: In 2011, Energen Resources received an Order to Perform Restructured Accounting and Pay Additional Royalties (the Order), following an audit performed by the Taxation and Revenue Department (the Department) of the State of New Mexico on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The Order addressed ONRR’s efforts to change accounting and reporting practices, and to unbundle fees charged by third parties that gather, compress and transport natural gas production. ONRR now maintains that all or some of such fees are not deductible.

Energen Resources appealed the Orderin 2011 and in July 2012, on a motion from ONRR, the Orderwas remanded. In August 2014, ONRR issued its Revised Order that is now under appeal. In the Revised Order, ONRR has ordered that Energen pay additional royalties on production from certain federal leases in the amount of $129,700. Energen estimates that application of the Revised Order to all of the Company’s federal leases would result in ONRR claims up to approximately $24 million, plus interest and penalties from 2004 forward. ONRR began implementing its unbundling initiative in 2010, but seeks to implement its revisions retroactively, despite the fact that they conflict with previous audits, allowances and industry practice. Energen continues to vigorously contest the Revised Order and the findings. Management is unable, at this time, to determine a range of reasonably possible losses, and no amount has been accrued as of December 31, 2015.

Lease Obligations: Energen’s total lease payments included as operating lease expense were $23.7 million, $24.1 million and $25.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. Minimum future rental payments required after 2015 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2016	2017	2018	2019	2020	2021 and thereafter
$2,537	$2,574	$2,537	$2,431	$—	$—

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

Energen’s asset retirement obligations primarily relate to the future plugging, abandonment and reclamation of wells and facilities. We recognize a liability for the fair value of the ARO in the periods incurred. The ARO fair value liability is determined by calculating the present value of the estimated future cash outflows we expect to incur to plug, abandon and reclaim our producing properties at the end of their productive lives, and is recognized on a discounted basis incorporating an estimate of performance risk specific to Energen. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful lives of the related assets. Upon settlement of the liability, Energen may recognize a gain or loss for differences between estimated and actual settlement costs.

The following table reflects the components of the change in Energen’s ARO balance:

(in thousands)
Balance as of December 31, 2012	$	118,023
Liabilities incurred	2,772
Liabilities settled	(5,525		)
Accretion expense (including discontinued operations of $1,197)	8,192
Reclassification associated with held for sale properties*	(14,929		)
Balance as of December 31, 2013	108,533
Liabilities incurred	2,266
Liabilities settled	(1,543		)
Accretion expense (including discontinued operations of $251)	7,859
Revision in estimated cash flows	692
Reclassification associated with held for sale properties**	(23,747		)
Balance as of December 31, 2014	$	94,060
Liabilities incurred	981
Liabilities settled	(686		)
Accretion expense	7,108
Reclassification associated with held for sale properties***	(11,473		)
Balance as of December 31, 2015	$	89,990

*Asset retirement obligation associated with North Louisiana/East Texas properties.

**Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2014.

***Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2015.

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Asset Impairment

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Asset Impairment

ASSET IMPAIRMENT

Impairments recognized by Energen during the years ended December 31, 2015, 2014 and 2013 are presented below:

Years ended December 31, (in thousands)	2015		2014		2013
Continuing operations
Permian Basin properties
Central Basin Platform	$	484,848	$	—	$	—
Delaware Basin	607,303		90,594		—
Midland Basin	—		25,776		—
San Juan Basin properties	133,055		230,315		—
Permian Basin unproved leasehold properties	29,168		64,361		13,906
San Juan Basin unproved leasehold properties	37,934		5,755		—
Total asset impairments from continuing operations	1,292,308		416,801		13,906
Discontinued operations
North Louisiana/East Texas oil and natural gas properties	—		1,936		29,794
Total asset impairments from discontinued operations	—		1,936		29,794
Total asset impairments	$	1,292,308	$	418,737	$	43,700

Non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement.

Permian Basin: For 2015, Energen recognized non-cash impairment writedowns on certain properties in the Permian Basin of $1,092.2 million to adjust the carrying amount of these properties to their fair value. We estimate future discounted cash flows in determining fair value using commodity assumptions, which are based on the commodity price curve for five years and then escalated at 3 percent through our assumed price cap. During the fourth quarter of 2015, Energen recognized non-cash impairment writedowns of $646.1 million due to commodity price declines and the related impact to our drilling plans. Our commodity price assumptions declined over the third quarter by approximately 12 percent for oil and 6 percent for natural gas in comparable periods. During the third quarter of 2015, Energen recognized non-cash impairment writedowns of $390.2 million due to commodity price declines. Our commodity price assumptions declined over the second quarter by approximately 19 percent for oil and 12 percent for natural gas in comparable periods. During the second quarter of 2015, Energen recognized non-cash impairment writedowns on certain properties in the Central Basin Platform of $51.5 million. Estimated future cash flows were revised due to the receipt of an unsolicited offer for these properties. During the first quarter of 2015, Energen recognized a non-cash impairment writedown of $4.3 million.

During the third and fourth quarters of 2014, Energen recognized non-cash impairment writedowns on certain Permian Basin properties in the Midland Basin of $25.8 million and in the Delaware Basin of $90.6 million, respectively, to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows.

Energen recognized unproved leasehold writedowns primarily on Permian Basin oil properties in the Delaware Basin of $29.2 million in 2015. During 2014, Energen recognized unproved leasehold writedowns of $64.4 million. These unproved leasehold writedowns include $55.1 million of leasehold expirations.

San Juan Basin: Energen recognized non-cash impairment writedowns on properties in the San Juan Basin of $133.1 million during the fourth quarter of 2015 to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. These remaining properties were designated as held for sale as of December 31, 2015. At December 31, 2015, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 16,930 MBOE.

During the third and fourth quarters of 2014, non-cash impairment writedowns of $142.2 million and $88.1 million, respectively, were recognized by Energen on certain natural gas properties in the San Juan Basin to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows in the third quarter and based on direct market data in the fourth quarter as these properties were designated as held for sale as of December 31, 2014. At December 31, 2014, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 69,038 MBOE.

During 2015 and 2014, Energen recognized unproved leasehold writedowns on San Juan Basin properties of $37.9 million and $5.8 million, respectively.

North Louisiana/East Texas: In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million. The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations. Energen recognized non-cash impairment writedowns on these properties in 2014 of $1.9 million to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2014. Energen also recognized non-cash impairment writedowns on these properties of $29.8 million in 2013. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2013. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment writedowns are classified as Level 3 fair value. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

Black Warrior Basin: In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million. Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

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Acquisition and Disposition of Properties

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

Acquisition and Disposition of Properties

ACQUISITION AND DISPOSITION OF PROPERTIES

Subsequent to December 31, 2015, Energen classified certain non-core assets in the eastern Delaware Basin as held for sale. Proved reserves associated with these Delaware Basin properties totaled 25,200 MBOE at December 31, 2015.

At December 31, 2015, our remaining San Juan Basin properties were classified as held for sale. Proved reserves associated with these San Juan Basin properties totaled 16,930 MBOE at December 31, 2015.

On March 31, 2015, Energen completed the sale of the majority of its natural gas assets in the San Juan Basin in New Mexico and Colorado (effective as of January 1, 2015) for an aggregate purchase price of $395 million. The sales proceeds were reduced by purchase price adjustments of approximately $11 million related to the operations of the San Juan Basin properties subsequent to December 31, 2014 and one-time adjustments related primarily to liabilities assumed by the buyer, which resulted in pre-tax proceeds to Energen of approximately $384 million before consideration of transaction costs of approximately $2.8 million. Energen recognized a pre-tax gain of $27.0 million on the sale. Energen used proceeds from the sale to reduce long-term indebtedness. At December 31, 2014, proved reserves associated with these San Juan Basin properties totaled 69,038 MBOE.

Energen completed an estimated total of $85.7 million in various purchases of unproved leasehold largely in the Permian Basin during 2015. During 2014, Energen completed a total of approximately $68.5 million in various purchases of unproved leasehold properties, including the October 2014, purchase of approximately 15,000 net acres of unproved leasehold in the Mancos formation oil play in the San Juan Basin for $22.8 million. During 2013, Energen also completed a total of approximately $26.8 million in various purchases of unproved leasehold properties.

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Discontinued Operations and Held for Sale Properties

12 Months Ended

Dec. 31, 2015

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations and Held for Sale Properties

DISCONTINUED OPERATIONS AND HELD FOR SALE PROPERTIES

As discussed in Note 15, Acquisition and Disposition of Properties, subsequent to December 31, 2015, Energen classified certain non-core assets in the eastern Delaware Basin as held for sale. Proved reserves associated with these Delaware Basin properties totaled 25,200 MBOE at December 31, 2015.

At December 31, 2015, our remaining San Juan Basin properties were classified as held for sale. Proved reserves associated with these San Juan Basin properties totaled 16,930 MBOE at December 31, 2015.

The following table details San Juan Basin held for sale properties by major classes of assets and liabilities. Property sales in the San Juan Basin do not qualify for discontinued operations:

(in thousands)	December 31, 2015			December 31, 2014
Inventories	$	3,651		$	—
Oil and natural gas properties	305,386			1,166,124
Less accumulated depreciation, depletion and amortization	(219,059		)	(770,327		)
Other property and equipment, net	3,761			—
Total assets held for sale	93,739			395,797
Other long-term liabilities	(12,789		)	(24,230		)
Total liabilities held for sale	(12,789		)	(24,230		)
Total net assets held for sale	$	80,950		$	371,567

On September 2, 2014, Energen completed the transaction to sell Alagasco to Laclede for $1.6 billion, less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion resulting in a pre-tax gain of $726.5 million. This sale has an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. Energen’s results of operations and cash flows for the years ended December 31, 2014 and 2013 presented in our consolidated financial statements and these notes reflect Alagasco as discontinued operations.

We classified as discontinued operations interest on debt required to be extinguished, certain depreciation costs that ended at close of transaction, the related income tax impact of these items and the earnings of Alagasco. In addition, we reclassified from discontinued operations certain general and administrative expenses, other income and the related tax impact from these items. The table below provides a detail of these items included in income (loss) from discontinued operations as follows:

Years ended December 31, (in thousands)	2014			2013
Alagasco net income	$	40,646		$	57,399
Depreciation, depletion and amortization	(408		)	(598		)
General and administrative	3,337			5,894
Interest expense	(17,306		)	(13,815		)
Other income	(347		)	(1,342		)
Income tax expense	5,567			3,728
Alagasco income from discontinued operations	31,489			51,266
Energen income (loss) from discontinued operations	(2,197		)	7,813
Income from discontinued operations	$	29,292		$	59,079

Years ended December 31, (in thousands, except per share data)	2014		2013
Natural gas distribution revenues	$	397,648	$	533,338
Oil and natural gas revenues	5,199		60,191
Total revenues	$	402,847	$	593,529
Pretax income from discontinued operations	$	47,220	$	92,253
Income tax expense	17,928		33,174
Income From Discontinued Operations	$	29,292	$	59,079
Gain on disposal of discontinued operations, net	$	724,594	$	5,605
Income tax expense	285,497		2,011
Gain on Disposal of Discontinued Operations, net	$	439,097	$	3,594
Total Income From Discontinued Operations	$	468,389	$	62,673
Diluted Earnings Per Average Common Share
Income from discontinued operations	$	0.40	$	0.81
Gain on disposal of discontinued operations, net	5.99		0.05
Total Income From Discontinued Operations	$	6.39	$	0.86
Basic Earnings Per Average Common Share
Income from discontinued operations	$	0.40	$	0.82
Gain on disposal of discontinued operations, net	6.02		0.05
Total Income From Discontinued Operations	$	6.42	$	0.87

In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million. The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations. Energen recognized non-cash impairment writedowns on these properties in 2014 of $1.9 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2014. Energen also recognized non-cash impairment writedowns on these properties of $29.8 million in 2013. These non-cash impairment writedowns are reflected in gain on disposal of discontinued operations, net in the year ended December 31, 2013. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million. Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 that was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2015

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental information concerning Energen’s cash flow activities from continuing operations was as follows:

Years ended December 31, (in thousands)	2015		2014		2013
Interest paid, net of amount capitalized	$	40,747	$	32,172	$	38,255
Income taxes paid	$	8,114	$	219,505	$	22,781
Noncash investing activities:
Accrued development, exploration costs and other capital	$	79,206	$	207,461	$	93,623
Capitalized asset retirement obligations costs	$	981	$	2,958	$	2,772
Receivable from sale of Alabama Gas Corporation	$	—	$	8,247	$	—
Noncash financing activities:
Issuance of common stock for employee benefit plans	$	5,758	$	2,448	$	1,015
Treasury stock acquired in connection with tax withholdings	$	4,722	$	2,547	$	977

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Accumulated Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects:

(in thousands)	Pension and Postretirement Plans
Balance as of December 31, 2014	$	(22,870	)
Other comprehensive income before reclassifications	3,305
Amounts reclassified from accumulated other comprehensive income	19,828
Change in accumulated other comprehensive income (loss)	23,133
Balance as of December 31, 2015	$	263

The following table provides details of the reclassifications out of accumulated other comprehensive income (loss):

Years ended December 31, (in thousands)	2015			2014			2013
				Amounts Reclassified						Line Item Where Presented
Gains (losses) on cash flow hedges:
Commodity contracts	$	—		$	21,611		$	35,684		Gain (loss) on derivative instruments, net
Interest rate swap	—			(2,280		)	(1,723		)	Interest expense
Total cash flow hedges	—			19,331			33,961
Income tax expense	—			(7,414		)	(12,957		)
Net of tax	—			11,917			21,004
Pension and postretirement plans:
Transition obligation	—			(22		)	(319		)	General and administrative
Prior service cost	—			(248		)	(257		)	General and administrative
Actuarial losses	(30,504		)	(21,932		)	(12,357		)	General and administrative
Actuarial losses on settlement charges*	—			—			(421		)	Assets held for sale
Total pension and postretirement plans	(30,504		)	(22,202		)	(13,354		)
Income tax benefit	10,676			7,771			4,674
Net of tax	(19,828		)	(14,431		)	(8,680		)
Total reclassifications for the period	$	(19,828	)	$	(2,514	)	$	12,324

*During the year ended December 31, 2013, Energen incurred settlement charges of $0.6 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.2 million was recognized in actuarial losses above and $0.4 million was recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

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Recently Issued Accounting Standards

12 Months Ended

Dec. 31, 2015

Accounting Changes and Error Corrections [Abstract]

Recently Issued Accounting Standards

RECENTLY ISSUED ACCOUNTING STANDARDS

In November 2015, the Financial Accounting Standards Board (FASB) issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. Prior year comparable periods have not been updated retrospectively, as we elected to adopt the standard prospectively. This update requires that deferred tax liabilities and assets be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of each jurisdiction of an entity be offset and presented as a single amount is not affected by the amendments in this update. The amendment is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Energen elected early adoption of this ASU prospectively as of December 31, 2015. We reclassified $14.5 million from a current deferred income tax asset to a noncurrent deferred income tax liability at December 31, 2015.

In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendment is effective for fiscal years beginning on or after December 15, 2015, and interim periods within those fiscal years. Energen does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This update clarifies the guidance regarding line-of-credit arrangements with regards to the recently issued ASU 2015-03. ASU 2015-15 allows entities to defer and present debt issue costs as an asset and subsequently amortize the deferred debt issue costs ratably over the term of the line-of-credit arrangement.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This update codifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. The amendments in this ASU will not impact the Company's financial position or results of operations. The new guidance will require a formal assessment of going concern by management based on criteria prescribed in the new guidance. The Company is reviewing its policies and processes to ensure compliance with this new guidance.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. This update is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. Companies may apply this update retrospectively or using a modified retrospective approach to adjust retained earnings. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers, which deferred the effective date of ASU No. 2014-09 to annual periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are currently evaluating the impact of this guidance on our financial statements.

In April 2014, the FASB issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held for sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment was effective for annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The adoption of this ASU did not have a material impact on the consolidated financial statements of Energen.

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Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Information (Unaudited)

SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

The following data summarizes quarterly operating results:

	Year ended December 31, 2015
(in thousands, except per share amounts)	First			Second			Third			Fourth
Revenues	$	221,858		$	168,326		$	295,571		$	192,799
Operating loss	$	(12,409	)	$	(161,678	)	$	(348,214	)	$	(915,550	)
Loss from continuing operations	$	(15,420	)	$	(111,601	)	$	(227,904	)	$	(590,806	)
Net loss	$	(15,420	)	$	(111,601	)	$	(227,904	)	$	(590,806	)
Diluted earnings per average common share
Continuing operations	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)
Net loss	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)
Basic earnings per average common share
Continuing operations	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)
Net loss	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)

	Year ended December 31, 2014
(in thousands, except per share amounts)	First			Second			Third		Fourth
Revenues as originally reported	$	561,178		$	270,097		$	497,761	$	611,435
Discontinued operations*	(263,900		)	—			—		—
Reclassification of loss on sale of assets and other	153			909			747		833
Adjusted revenues	$	297,431		$	271,006		$	498,508	$	612,268
Operating income as originally reported	$	104,599		$	3,107		$	48,171	$	94,223
Discontinued operations*	(73,139		)	—			—		—
Adjusted operating income	$	31,460		$	3,107		$	48,171	$	94,223
Income (loss) from continuing operations	$	15,647		$	(3,154	)	$	20,631	$	66,519
Net income (loss)	$	53,316		$	(7,953	)	$	457,251	$	65,418
Diluted earnings per average common share
Continuing operations	$	0.21		$	(0.04	)	$	0.28	$	0.91
Net income (loss)	$	0.73		$	(0.11	)	$	6.22	$	0.89
Basic earnings per average common share
Continuing operations	$	0.22		$	(0.04	)	$	0.28	$	0.91
Net income (loss)	$	0.73		$	(0.11	)	$	6.26	$	0.90

*As discussed in Note 16, Discontinued Operations and Held for Sale Properties, during the third quarter of 2014, Energen completed the transaction to sell Alagasco to Laclede. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations.

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Oil and Natural Gas Operations (Unaudited) Oil and Natural Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2015

Extractive Industries [Abstract]

Oil and Natural Gas Operations (Unaudited)

OIL AND NATURAL GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:

(in thousands)	December 31, 2015		December 31, 2014
Proved	$	7,911,554	$	8,069,638
Unproved	150,674		142,340
Total capitalized costs	8,062,228		8,211,978
Accumulated depreciation, depletion and amortization	3,673,569		2,663,434
Capitalized costs, net	$	4,388,659	$	5,548,544

Costs Incurred: The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year:

Years ended December 31, (in thousands)	2015		2014		2013
Property acquisition:
Proved	$	1,866	$	2,582	$	4,661
Unproved	85,690		68,514		26,820
Exploration	649,764		972,164		435,636
Development	372,177		408,949		655,353
Total costs incurred	$	1,109,497	$	1,452,209	$	1,122,470

Results of Operations From Producing Activities: The following table sets forth results of Energen’s oil, natural gas liquids and natural gas operations from producing activities:

Years ended December 31, (in thousands)	2015			2014		2013
Gross revenues*	$	878,554		$	1,679,213	$	1,206,293
Production (lifting costs)	285,760			376,495		351,541
Exploration expense	14,877			28,090		14,036
Depreciation, depletion and amortization including asset impairments	1,880,190			960,539		463,606
Accretion expense	7,108			7,608		6,995
Income tax expense (benefit)	(469,362		)	99,469		128,773
Results of operations from producing activities	$	(840,019	)	$	207,012	$	241,342

* The years ended December 31, 2015, 2014 and 2013 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $281.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million and a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, respectively.

Oil and Natural Gas Operations: The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that proved categories of reserves be disclosed. Proved reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2015, 2014 and 2013. Changes to prices and costs could have a significant effect on the disclosed amount of proved reserves and their associated values. In addition, the estimation of proved reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of proved reserves disclosed. The proved reserves are located onshore in the United States of America.

Estimates of physical quantities of oil and natural gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. (Ryder Scott) and Hickman McClaine and Associates, Inc. (Hickman McClaine), independent oil and natural gas reservoir engineers, have audited the estimates of proved reserves of oil, natural gas liquids and natural gas that Energen has attributed to its net interests in oil and natural gas properties as of December 31, 2015. Ryder Scott audited the proved reserve estimates for coalbed methane in the San Juan Basin and substantially all of the Permian Basin proved reserves. Hickman McClaine audited the conventional proved reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 99 percent of Energen’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

Year ended December 31, 2015	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	181,227		73,463		707,926		372.7
Revisions of previous estimates	(39,537	)	(11,979	)	(44,176	)	(58.9	)
Purchases	2		1		2		—
Extensions and discoveries	83,319		25,530		143,022		132.6
Production	(14,023	)	(4,065	)	(35,604	)	(24.0	)
Sales	(297	)	(11,237	)	(337,266	)	(67.7	)
Proved reserves at end of period	210,691		71,713		433,904		354.7
Proved developed reserves at end of period	108,319		36,374		236,112		184.0
Proved undeveloped reserves at end of period	102,372		35,339		197,792		170.7

Year ended December 31, 2014	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	164,870		63,011		719,725		347.8
Revisions of previous estimates	(48,548	)	(15,165	)	(71,806	)	(75.7	)
Purchases	88		26		116		0.1
Extensions and discoveries	76,722		29,695		141,209		130
Production	(11,818	)	(4,104	)	(59,562	)	(25.8	)
Sales	(87	)	—		(21,756	)	(3.7	)
Proved reserves at end of period	181,227		73,463		707,926		372.7
Proved developed reserves at end of period	118,697		47,621		589,074		264.5
Proved undeveloped reserves at end of period	62,530		25,842		118,852		108.2

Year ended December 31, 2013	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	155,348		56,155		809,128		346.4
Revisions of previous estimates	(680	)	2,211		18,465		4.6
Purchases	142		56		282		0.2
Extensions and discoveries	20,517		7,823		50,568		36.8
Production	(10,378	)	(3,233	)	(70,506	)	(25.4	)
Sales	(79	)	(1	)	(88,212	)	(14.8	)
Proved reserves at end of period	164,870		63,011		719,725		347.8
Proved developed reserves at end of period	113,795		42,087		623,305		259.8
Proved undeveloped reserves at end of period	51,075		20,924		96,420		88.0

2015 Activities: Energen had net downward reserve revisions during 2015 which totaled 58.9 MMBOE including negative revisions of approximately 38.0 MMBOE related to changes in year-end pricing and negative revisions of approximately 8.2 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period. Other negative revisions were 5.5 MMBOE due to increased declines in certain Wolfberry wells and 5.0 MMBOE of Wolfcamp reserves due to interference caused by our wellbore placement geometry.

During 2015, Energen had extensions and discoveries of 132.6 MMBOE, primarily in the Permian Basin, of which 78 percent were proved undeveloped reserves and 22 percent were proved developed reserves. Extension drilling resulted in 3.1 MMBOE of discoveries with exploratory drilling providing 129.5 MMBOE of discoveries.

During 2015, Energen had sales of 67.7 MMBOE primarily due to the sale of certain natural gas assets in the San Juan Basin.

2014 Activities: Energen had net downward reserve revisions during 2014 which totaled 75.7 MMBOE including downward revisions of approximately 53.4 MMBOE of proved undeveloped reserves that are now expected to be drilled after the original five year period and upward revisions of approximately 3.9 MMBOE related to changes in year-end pricing. The San Juan Basin had upward reserve revisions of 1.6 MMBOE including 4.4 MMBOE related to changes in year-end pricing and downward revisions of approximately 1.5 MMBOE due to higher operating costs. Net downward reserve revisions of 77.3 MMBOE in the Permian Basin were due to reclassifying 53.4 MMBOE as unproved because of changes in our development plans, downward revisions of approximately 13.3 MMBOE due to decreased well performance in certain Wolfberry wells, downward revisions of approximately 5.4 due to higher operating costs and approximately 0.5 MMBOE related to changes in the year-end pricing.

Energen purchased 0.1 MMBOE of reserves during 2014 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2014, Energen had extensions and discoveries of 130.0 MMBOE of which 70 percent were proved undeveloped reserves and 30 percent were proved developed reserves. Extension drilling resulted in 89.6 MMBOE of discoveries with exploratory drilling providing 40.4 MMBOE of discoveries. The San Juan Basin added 1.1 MMBOE of reserves through the drilling or identification of 16 well locations and 10 pay adds. The Permian Basin added 128.6 MMBOE of reserves primarily through the drilling or identification of 361 well locations.

During 2014, Energen had sales of 3.7 MMBOE primarily due to the sale of the North Louisiana/East Texas primarily natural gas properties.

2013 Activities: Energen had upward reserve revisions during 2013 which totaled 4.6 MMBOE including approximately 7 MMBOE related to changes in year-end pricing and downward revisions of approximately 5.3 MMBOE of proved undeveloped reserves of which 4.6 MMBOE are expected to be drilled beyond five years with the remainder no longer expected to be drilled. The San Juan Basin upward reserve revisions of 2.2 MMBOE including 5.9 MMBOE related to changes in year-end pricing and downward revisions of approximately 4.6 MMBOE of proved undeveloped reserves that are expected to be drilled beyond five years. Net upward reserve revisions of 1.2 MMBOE in the Permian Basin were due to improved well performance in certain Wolfberry wells and approximately 0.4 MMBOE related to changes in the year-end pricing and downward revisions of approximately 0.7 MMBOE of proved undeveloped reserves that are no longer expected to be drilled.

Energen purchased 0.2 MMBOE of reserves during 2013 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2013, Energen had extensions and discoveries of 36.8 MMBOE of which 45 percent were proved undeveloped reserves and 55 percent were proved developed reserves. Extension drilling resulted in 21.6 MMBOE of discoveries with exploratory drilling providing 15.2 MMBOE of discoveries. The San Juan Basin added 2.3 MMBOE of reserves through 30 pay adds. The Permian Basin added 34.4 MMBOE of reserves primarily through the drilling or identification of 262 well locations.

During 2013, Energen had sales of 14.8 MMBOE primarily due to the sale of the Black Warrior Basin coalbed methane properties.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of Energen’s crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. Open mark-to-market derivatives applicable to future periods are excluded from the calculation of standardized measure of future net cash flows.

Years ended December 31, (in thousands)	2015		2014		2013
Future gross revenues	$	11,714,729	$	20,971,672	$	19,509,305
Future production costs	4,353,974		7,532,273		6,136,709
Future development costs	1,961,661		1,784,738		1,896,602
Future income tax expense	1,065,887		3,440,582		3,209,697
Future net cash flows	4,333,207		8,214,079		8,266,297
Discount at 10% per annum	2,299,859		3,994,423		4,248,456
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	2,033,348	$	4,219,656	$	4,017,841

The following are the principal sources of changes in the standardized measure of discounted future net cash flows:

Years ended December 31, (in thousands)	2015			2014			2013
Balance at beginning of year	$	4,219,656		$	4,017,841		$	3,699,319
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(2,861,591		)	(1,147,028		)	566,838
Net changes due to revisions in quantity estimates	(404,708		)	(1,285,394		)	(81,762		)
Development costs incurred, previously estimated	350,560			337,198			299,432
Accretion of discount	421,966			401,784			369,932
Changes in timing and other*	(903,975		)	987,652			(179,502		)
Total revisions	(3,397,748		)	(705,788		)	974,938
New field discoveries and extensions, net of future production and development costs	776,315			2,321,028			376,326
Sales of oil and gas produced, net of production costs	(514,380		)	(1,054,553		)	(1,014,593		)
Purchases	8			4,241			4,690
Sales	(372,039		)	(21,092		)	(24,876		)
Net change in income taxes	1,321,536			(342,021		)	2,037
Net change in standardized measure of discounted future net cash flows	(2,186,308		)	201,815			318,522
Balance at end of year	$	2,033,348		$	4,219,656		$	4,017,841

*Amount represents changes in production timing and other. In 2015, the production timing is significantly affected by changes related to the delay of the drilling program. For 2014, the production timing is significantly affected by changes related to the acceleration of the horizontal drilling program and the delay of the vertical drilling program.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Principles of Consolidation

The accompanying consolidated financial statements include Energen and its subsidiaries, principally Energen Resources, after elimination of all significant intercompany transactions in consolidation. In the opinion of management, our consolidated financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods and as of the dates shown. Such adjustments consist of normal recurring items.

Property and Related Depletion

Energen follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, natural gas liquids and natural gas reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. Energen capitalizes exploratory drilling costs until a determination is made that the well or project has either found proved reserves or is impaired. After an exploratory well has been drilled and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas quantities can be classified as proved. In those circumstances, we continue to capitalize the drilling costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Capitalized exploratory drilling costs are presented in proved properties in the balance sheets. If the exploratory well is determined to be a dry well, the costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves.

Operating Revenues

Energen utilizes the sales method of accounting to recognize oil, natural gas liquids and natural gas production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining proved reserves for such property.

Derivative Commodity Instruments

We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen. All derivative transactions are included in operating activities on the consolidated statements of cash flows.

The majority of our counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Energen formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the nature of the risk being hedged. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes.

Effective June 30, 2013, Energen discontinued the use of cash flow hedge accounting and dedesignated all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen in accumulated other comprehensive income until the forecasted transactions actually occurred. Any subsequent gains or losses are accounted for as mark-to-market and recognized immediately through gain (loss) on derivative instruments, net. As a result of Energen’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 are accounted for as mark-to-market transactions with gains or losses recognized in the period of change in gain (loss) on derivative instruments, net.

Asset Impairments

Oil and natural gas proved properties periodically are assessed for possible impairment on a field-by-field basis using the estimated undiscounted future cash flows. Energen monitors its oil and natural gas properties as well as the market and business environments in which it operates and makes assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected production performance. If a material event occurs, we make an estimate of undiscounted future cash flows to determine whether the asset is impaired. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. If the asset is impaired, Energen will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows.

Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These variables can, and often do, differ from the estimates and can have a positive or negative impact on our need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact Energen’s original and ongoing assessments of potential impairment.

Energen also may recognize impairments of capitalized costs for unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by exploration activities, changes in economic factors and potential shifts in business strategy employed by management. We consider a combination of geologic and economic factors to evaluate the need for impairment of these costs.

Long-Lived Assets and Discontinued Operations

Energen may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held for sale are reported at the lower of the carrying amount or estimated fair value. Certain of these held for sale properties also qualify as discontinued operations and the results of operations of these properties are reclassified and reported as discontinued operations for prior periods.

Acquisitions

Energen recognizes all acquisitions at fair value. Energen estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen obtained control of the properties for all acquisitions that qualify as business combinations. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. Energen uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy. Acquisition related costs are expensed as incurred in general and administrative expense on the consolidated income statements.

Inventory

Inventories consist primarily of tubular goods and other oilfield equipment used in our operations and are stated at the lower of cost or market value, on a weighted average cost basis.

Fair Value Measurements

The carrying values of cash and cash equivalents, accounts payable, accounts receivable (net of allowance), derivative commodity instruments, pension and postretirement plan assets and liabilities and other current assets and liabilities approximate fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). In determining fair value, we use various valuation approaches and classify all assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own assumptions about the assumptions other market participants would use in pricing the asset or liability based on the best information available in the circumstances. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The hierarchy is broken down into three levels based on the observability of inputs as follows:

Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;

Level 2 - Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;

Level 3 - Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumptions that market participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

The fair value of Energen’s derivative commodity instruments is determined using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. Our OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which we are able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX oil and natural gas prices. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. We consider the frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While Energen does not have access to the specific assumptions used in its counterparties’ valuation models, we maintain communications with our counterparties and discuss pricing practices. Further, we corroborate the fair value of our transactions by comparison of market-based price sources.

Energen utilizes a discounted cash flow model in valuing its interest rate derivatives, which are comprised of interest rate swap agreements. The fair value attributable to Energen's interest rate derivative contracts is based on (i) the contracted notional amounts, (ii) active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

Pension and postretirement plan assets include cash and mutual funds. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and Level 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds.

Income Taxes

Energen uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. Energen and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.

Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in the existing accounts receivable. Energen determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value.

Short-term investments

All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments.

Earnings Per Share (EPS)

Energen’s basic earnings per share amounts have been computed based on the weighted average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities.

Stock-Based Compensation

Energen recognizes all share-based compensation awards in general and administrative expense on the consolidated income statement over the requisite vesting period. Equity awards are measured at fair value as of the date of grant. Awards that are settled in cash are classified as liabilities and re-measured at fair value at the end of each reporting period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. We recognize all stock-based compensation expense in the period of grant, subject to certain vesting requirements, for retirement eligible employees. Energen utilizes the long-form method of calculating the available pool of windfall tax benefit.

Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, physical quantities of proved oil and gas reserves, periodic assessments of oil and gas properties for impairment, Energen’s obligations under its employee pension and compensation plans, the valuation of derivative financial instruments, the allowance for doubtful accounts, tax contingency reserves, legal contingency reserves, asset retirement obligations and self insurance reserves. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.

Employee Benefit Plans

Plan Termination: In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015 and distributed benefits in December 2015.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 with the remainder to be paid in the first quarter of 2016.

Plan Separation: Effective April 30, 2014, Energen separated its defined benefit non-contributory pension plan and its postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan reflecting the separation of assets and obligations in accordance with ERISA provisions. Energen remeasured the plans using current assumptions.

Postretirement Benefit Plans: Energen provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. These postretirement healthcare and life insurance benefits are available upon reaching normal retirement age while working for Energen. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.

For other postretirement plans, certain financial assumptions are used in determining Energen’s projected benefit obligation. These assumptions are examined periodically by Energen, and any required changes are reflected in the subsequent determination of projected benefit obligations.

Energen calculates periodic expense for the other postretirement benefit plans on an actuarial basis and the net funded status is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. The benefit obligation is the accumulated postretirement benefit obligation. Energen measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.

For our other postretirement plan, we selected a yield curve comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments.

The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. Energen considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets.

Environmental Costs

Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated.

Investment Strategy

For our postretirement benefit plan assets, we continue to employ a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.

Energen seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, commodity or class of investment fund.

Recently Issued Accounting Pronouncements

In November 2015, the Financial Accounting Standards Board (FASB) issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. Prior year comparable periods have not been updated retrospectively, as we elected to adopt the standard prospectively. This update requires that deferred tax liabilities and assets be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of each jurisdiction of an entity be offset and presented as a single amount is not affected by the amendments in this update. The amendment is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Energen elected early adoption of this ASU prospectively as of December 31, 2015. We reclassified $14.5 million from a current deferred income tax asset to a noncurrent deferred income tax liability at December 31, 2015.

In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendment is effective for fiscal years beginning on or after December 15, 2015, and interim periods within those fiscal years. Energen does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This update clarifies the guidance regarding line-of-credit arrangements with regards to the recently issued ASU 2015-03. ASU 2015-15 allows entities to defer and present debt issue costs as an asset and subsequently amortize the deferred debt issue costs ratably over the term of the line-of-credit arrangement.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This update codifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. The amendments in this ASU will not impact the Company's financial position or results of operations. The new guidance will require a formal assessment of going concern by management based on criteria prescribed in the new guidance. The Company is reviewing its policies and processes to ensure compliance with this new guidance.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. This update is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. Companies may apply this update retrospectively or using a modified retrospective approach to adjust retained earnings. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers, which deferred the effective date of ASU No. 2014-09 to annual periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are currently evaluating the impact of this guidance on our financial statements.

In April 2014, the FASB issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held for sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment was effective for annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The adoption of this ASU did not have a material impact on the consolidated financial statements of Energen.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Schedule of Long-Term Debt

Long-term debt consisted of the following:

(in thousands)	December 31, 2015		December 31, 2014
Credit facility	$	222,500	$	485,000
7.40% Medium-term Notes, Series A, due July 24, 2017	2,000		2,000
7.36% Medium-term Notes, Series A, due July 24, 2017	15,000		15,000
7.23% Medium-term Notes, Series A, due July 28, 2017	2,000		2,000
7.32% Medium-term Notes, Series A, due July 28, 2022	20,000		20,000
7.60% Medium-term Notes, Series A, due July 26, 2027	5,000		5,000
7.35% Medium-term Notes, Series A, due July 28, 2027	10,000		10,000
7.125% Medium-term Notes, Series B, due February 15, 2028	100,000		100,000
4.625% Notes, due September 1, 2021	400,000		400,000
Total	776,500		1,039,000
Less unamortized debt discount	413		437
Total	$	776,087	$	1,038,563

Schedule of Aggregate Maturities of Long-Term Debt

The aggregate maturities of Energen’s long-term debt as of December 31, 2015 are as follows:

Years ending December 31, (in thousands)
2016	2017	2018	2019	2020	Thereafter
$—	$19,000	$—	$222,500	$—	$535,000

Schedule of Credit Facilities

The following is a summary of information relating to Energen’s credit facility:

(in thousands)	December 31, 2015			December 31, 2014
Credit facility outstanding	$	222,500		$	485,000
Available for borrowings	1,177,500			1,515,000
Total borrowing commitments	$	1,400,000		$	2,000,000
Maximum amount outstanding at any month-end	$	685,000		$	750,000
Average daily amount outstanding	$	358,929		$	482,166
Weighted average interest rates based on:
Average daily amount outstanding	1.60		%	1.46		%
Amount outstanding at year-end	1.64		%	1.67		%

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Schedule of Components of Income Taxes

The components of Energen’s income taxes consisted of the following:

Years ended December 31, (in thousands)	2015			2014			2013
Taxes estimated to be payable currently:
Federal	$	3,972		$	161,576		$	23,342
State	758			72,379			2,516
Total current	4,730			233,955			25,858
Taxes deferred:
Federal	(513,187		)	144,645			85,950
State	(26,548		)	(34,447		)	(2,300		)
Total deferred	(539,735		)	110,198			83,650
Total income tax expense (benefit)	$	(535,005	)	$	344,153		$	109,508

Schedule of Components of Income Tax Expense (Benefit), Continuing and Discontinued Operations

The components of Energen’s income taxes consisted of the following:

Years ended December 31, (in thousands)	2015			2014		2013
Income tax expense (benefit) from continuing operations	$	(535,005	)	$	40,728	$	74,323
Income tax expense from discontinued operations	—			17,928		33,174
Income tax expense from gain on disposal of discontinued operations	—			285,497		2,011
Total income tax expense (benefit)	$	(535,005	)	$	344,153	$	109,508

Schedule of Deferred Tax Assets and Liabilities

Temporary differences and carryforwards which gave rise to Energen’s deferred tax assets and liabilities were as follows:

(in thousands)	December 31, 2015					December 31, 2014
	Current		Noncurrent			Current			Noncurrent
Deferred tax assets:
Minimum tax credit	$	—	$	44,862		$	—		$	46,338
Allowance for doubtful accounts	—		253			244			—
Insurance and other accruals	—		2,807			2,537			—
Compensation accruals	—		11,650			11,355			—
Pension and other costs	—		8,693			—			7,009
Other comprehensive income	—		—			10,732			1,581
State net operating losses and other carryforwards	—		12,577			—			15,392
Other	—		962			665			—
Total deferred tax assets	—		81,804			25,533			70,320
Valuation allowance	—		(4,235		)	(1,122		)	(2,467		)
Total deferred tax assets	—		77,569			24,411			67,853

Deferred tax liabilities:
Depreciation and basis differences	—		620,629			—			1,057,430
Derivative instruments	—		2,838			102,691			—
Other comprehensive income	—		141			—			—
Other	—		6,330			884			10,909
Total deferred tax liabilities	—		629,938			103,575			1,068,339
Net deferred tax liabilities	$	—	$	(552,369	)	$	(79,164	)	$	(1,000,486	)

Schedule of Effective Income Tax Rate Reconciliation

Total income tax expense from continuing operations differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:

Years ended December 31, (in thousands)	2015			2014			2013
Income tax expense (benefit) at statutory federal income tax rate	$	(518,258	)	$	49,130		$	75,671
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	(14,112		)	93			1,461
Impact of state law changes	(3,075		)	(121		)	(1,966		)
Impact of state deferred tax revaluation on San Juan properties	(1,241		)	(8,382		)	—
401(k) stock dividend deduction	—			(232		)	(449		)
Other, net	1,681			240			(394		)
Total income tax expense (benefit)	$	(535,005	)	$	40,728		$	74,323
Effective income tax rate (%)	36.13			29.01			34.38

Schedule of Reconciliation of Unrecognized Tax Benefits

A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows:

(in thousands)
Balance as of December 31, 2012	$	12,555
Additions based on tax positions related to the current year	4,546
Additions for tax positions of prior years	366
Reductions for tax positions of prior years	(46		)
Lapse of statute of limitations	(1,435		)
Balance as of December 31, 2013	15,986
Additions based on tax positions related to the current year	3,873
Additions for tax positions of prior years	19
Reductions for tax positions of prior years	(954		)
Lapse of statute of limitations	(1,394		)
Balance as of December 31, 2014	17,530
Additions based on tax positions related to the current year	2,378
Reductions based on tax positions related to the current year	(6,589		)
Reductions for tax positions of prior years	(345		)
Lapse of statute of limitations	(1,785		)
Balance as of December 31, 2015	$	11,189

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2015

Defined Benefit Plan Disclosure [Line Items]

Schedule of Benefit Obligations

The following table sets forth the combined funded status of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in Energen’s consolidated financial statements.

As of December 31, (in thousands)	2015			2014			2015			2014
	Pension						Postretirement Benefits
Accumulated benefit obligation	$	15,729		$	107,669
Benefit obligation:
Balance at beginning of period	$	107,669		$	266,294		$	11,127		$	33,224
Service cost	—			8,329			392			262
Interest cost	816			5,325			466			716
Actuarial (gain) loss	(683		)	9,078			(1,185		)	6,385
Plan amendments	—			—			(4,071		)	—
Curtailment gain	—			(8,496		)	—			—
Transfer in connection with the sale of Alagasco	—			(124,783		)	—			(28,648		)
Termination benefit charge	—			2,477			—			—
Retiree drug subsidy program	—			—			—			48
Benefits paid	(92,073		)	(50,555		)	(241		)	(860		)
Balance at end of period	$	15,729		$	107,669		$	6,488		$	11,127
Plan assets:
Fair value of plan assets at beginning of period	$	67,542		$	193,457		$	10,693		$	55,459
Actual return (loss) on plan assets	(289		)	5,359			(83		)	(331		)
Employer contributions	24,847			19,164			—			21
Transfer in connection with the sale of Alagasco	—			(99,883		)	—			(43,596		)
Benefits paid	(92,073		)	(50,555		)	(241		)	(860		)
Fair value of plan assets at end of period	$	27		$	67,542		$	10,369		$	10,693
Funded status of plans	$	(15,702	)	$	(40,127	)	$	3,881		$	(434	)

Noncurrent assets	$	—		$	—		$	3,881		$	—
Current liabilities	(15,702		)	(24,626		)	—			—
Noncurrent liabilities	—			(15,501		)	—			(434		)
Net asset (liability) recognized	$	(15,702	)	$	(40,127	)	$	3,881		$	(434	)
Amounts recognized to accumulated other comprehensive income:
Prior service credit, net of taxes	$	—		$	—		$	(2,646	)	$	—
Net actuarial loss, net of taxes	2,179			22,246			205			624
Total accumulated other comprehensive income (loss)	$	2,179		$	22,246		$	(2,441	)	$	624

Schedule of Allocation of Plan Assets

The Company’s weighted average plan asset allocations by asset category were as follows:

	Pension						Postretirement Benefits
As of December 31,	Target		2015		2014		Target		2015		2014
Asset category:
Equity securities	—	%	—	%	—	%	56	%	56	%	60	%
Debt securities	—	%	—	%	—	%	44	%	44	%	40	%
Cash and cash equivalents	100	%	100	%	100	%	—	%	—	%	—	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

Schedule of Net Periodic Benefit Cost

The components of net periodic benefit cost from continuing operations were as follows:

Years ended December 31, (in thousands)	2015			2014			2013
Pension Plans
Components of net periodic benefit cost:
Service cost	$	—		$	6,808		$	5,196
Interest cost	816			4,498			4,496
Expected long-term return on assets	—			(4,386		)	(5,225		)
Prior service cost amortization	—			202			246
Actuarial loss amortization	737			4,995			6,919
Termination benefit charge	—			2,477			—
Settlement charge	29,767			4,082			161
Curtailment expense (gain)	—			254			(4		)
Net periodic expense	$	31,320		$	18,930		$	11,789
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	392		$	253		$	386
Interest cost	466			661			645
Expected long-term return on assets	(457		)	(1,122		)	(787		)
Actuarial gain amortization	—			(653		)	(28		)
Transition obligation amortization	—			44			229
Net periodic (income) expense	$	401		$	(817	)	$	445

Schedule of Other Changes in Plan Assets and Projected Benefit Obligations Recognized in Other Comprehensive Income

Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows:

Years ended December 31, (in thousands)	2015			2014			2013
Pension Plans
Net actuarial (gain) loss experienced during the year	$	(394	)	$	10,495		$	(14,138	)
Net actuarial loss recognized as expense	(30,478		)	(25,433		)	(8,934		)
Prior service cost recognized as expense	—			(246		)	(311		)
Curtailment loss	—			(8,749		)	—
Total recognized in other comprehensive income (loss)	(30,872		)	(23,933		)	(23,383		)
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	(645	)	$	7,649		$	(8,057	)
Prior service credit during the year	(4,071		)	—			—
Net actuarial gain recognized as expense	—			1,908			550
Transition obligation recognized as expense	—			(48		)	(283		)
Total recognized in other comprehensive income (loss)	$	(4,716	)	$	9,509		$	(7,790	)

Schedule of Estimated Amount to be Amortized from Accumulated Other Comprehensive Income

Estimated amounts to be amortized, including settlement charges, from accumulated other comprehensive income into pension cost during 2016 are included in the table below.

(in thousands)
Amortization of net actuarial loss	$	3,352

Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2016 are included in the table below.

(in thousands)
Amortization of prior service credit	$	(515	)

Schedule of Weighted Average Rate Assumptions

The weighted average rate assumptions to determine net periodic benefit costs were as follows:

Years ended December 31,	2015		2014		2013
Pension Plans
Discount rate	0.96	%	3.66	%	3.63	%
Expected long-term return on plan assets	—	%	7.00	%	7.00	%
Rate of compensation increase for pay-related plans	—	%	3.63	%	3.71	%
Postretirement Benefit Plans
Discount rate	4.25	%	4.88	%	4.36	%
Expected long-term return on plan assets	6.20	%	7.00	%	7.00	%
Rate of compensation increase	—	%	3.60	%	3.70	%

The pension benefit obligation as of December 31, 2014 represents the present value of the estimated cost of settling the benefit obligation of the plan. For our defined benefit pension plan, we discounted the estimated termination liability using the one year spot rate of 0.70 percent. For the year ended December 31, 2015, the discount rate shown above represents the weighted average for the nonqualified supplemental retirement plan. The discount rate shown below represents the weighted average for both the defined qualified and nonqualified supplemental retirement plans for the year ended December 31, 2014. For the year ended December 31, 2015, the expected long-term return on plan assets no longer applies for our defined benefit pension plan as the assets of the nonqualified supplemental retirement plan are not considered qualifying assets. As the plans were frozen as of December 31, 2014, the rate of compensation increase no longer applies for any of the plans. The weighted average assumptions used to determine the benefit obligations at the measurement date were as follows:

Years ended December 31,	2015		2014
Pension Plans
Discount rate	3.90	%	0.96	%
Postretirement Benefit Plans
Discount rate	4.70	%	4.25	%

Schedule of Assumed Post-65 Health Care Cost Trend Rates

The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows:

As of December 31,	2015		2014
Health care cost trend rate assumed for next year	7.75	%	7.25	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2026		2021

Schedule of Expected Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows:

(in thousands)	Pension Benefits	Postretirement Benefits
2016	$14,606	$198
2017	$117	$213
2018	$114	$245
2019	$110	$258
2020	$107	$289
2021-2025	$472	$1,769

Pension Benefits

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets

Plan assets included in the funded status of the pension plans were as follows:

	December 31, 2015
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	27		$	—	$	27
Total	$	27	$	—	$	27

	December 31, 2014
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	$	67,542	$	—	$	67,542
Total	$	67,542	$	—	$	67,542

Postretirement Benefits

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets

Plan assets included in the funded status of the postretirement benefit plans were as follows:

	December 31, 2015
(in thousands)	Level 1		Level 2		Total
United States equities	$	4,185	$	—	$	4,185
Global equities	1,650		—		1,650
Fixed income	—		4,534		4,534
Total	$	5,835	$	4,534	$	10,369

	December 31, 2014
(in thousands)	Level 1		Level 2		Total
United States equities	$	4,715	$	—	$	4,715
Global equities	1,711		—		1,711
Fixed income	—		4,267		4,267
Total	$	6,426	$	4,267	$	10,693

Nonqualified Supplemental Retirement Plans

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets

Other investment assets designated for payment of the nonqualified supplemental retirement plans were as follows:

	December 31, 2015
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	$	3,308	$	—	$	3,308
Total	$	3,308	$	—	$	3,308

	December 31, 2014
(in thousands)	Level 1		Level 2		Total
Fixed income	$	—	$	4,255	$	4,255
Cash and cash equivalents	9,929		—		9,929
Total	$	9,929	$	4,255	$	14,184

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Common Stock Plans (Tables)

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Performance Share Award Activity

A summary of performance share award activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 is presented below:

	Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2012	—		$	—
Granted (two-year vesting period)	86,221		61.14
Granted (three-year vesting period)	82,606		62.96
Forfeited	(8,008	)	60.03
Nonvested at December 31, 2013	160,819		62.13
Granted (two-year vesting period)	937		131.56
Granted (three-year vesting period)	65,309		93.49
Vested and paid	(14,097	)	70.06
Nonvested at December 31, 2014	212,968		71.53
Granted (three-year vesting period)	120,372		83.94
Vested and paid	(77,257	)	61.36
Nonvested at December 31, 2015	256,083		$	80.43

Schedule of Restricted Stock Activity and Transactions

A summary of restricted stock award activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 is presented below:

	Stock Incentive Plan
	Awards		Weighted Average Price
Nonvested at December 31, 2012	11,115		$	45.24
Restricted stock granted	52,650		52.34
Forfeited	(1,247	)	48.36
Nonvested at December 31, 2013	62,518		51.16
Restricted stock units granted	48,904		71.91
Vested	(11,848	)	65.94
Nonvested at December 31, 2014	99,574		59.60
Restricted stock units granted	99,814		65.15
Vested	(14,446	)	53.20
Nonvested at December 31, 2015	184,942		$	63.09

Schedule of Stock Option Activity and Transactions

A summary of stock option activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 are presented below:

	Stock Incentive Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2012	1,648,475		$	47.58
Granted	137,762		49.22
Exercised	(590,119	)	40.92
Forfeited	(5,074	)	51.85
Outstanding at December 31, 2013	1,191,044		51.06
Granted	110,307		72.55
Exercised	(544,280	)	50.09
Outstanding at December 31, 2014	757,071		54.88
Exercised	(23,680	)	41.42
Outstanding at December 31, 2015	733,391		$	55.32
Exercisable at December 31, 2013	713,445		$	49.80
Exercisable at December 31, 2014	454,938		$	51.88
Exercisable at December 31, 2015	622,156		$	53.80

Schedule of Stock Options Valuation Assumptions

Energen uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values:

Grant date	4/15/2014	1/22/2014	10/15/2013	1/24/2013
Awards granted	2,439	107,868	3,686	134,076
Fair market value of stock option at grant	$32.22	$27.57	$30.53	$16.66
Expected life of award	5.8 years	5.8 years	5.8 years	5.8 years
Risk-free interest rate	1.93%	2.06%	1.79%	1.01	%
Annualized volatility rate	40.7%	40.7%	40.6%	40.3	%
Dividend yield	0.2%	0.8%	0.7%	1.2	%

Schedule of Outstanding Stock Options by Range of Exercise Prices

The following table summarizes options outstanding as of December 31, 2015:

Stock Incentive Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
$46.45	19,990	1.00 year
$60.56	48,560	2.00 years
$29.79	24,291	3.00 years
$46.69	26,481	4.00 years
$54.99	104,841	5.00 years
$54.11	271,164	6.00 years
$48.36	124,071	7.00 years
$80.48	3,686	7.79 years
$72.39	107,868	8.00 years
$79.63	2,439	8.00 years
$29.79-$80.48	733,391	5.76 years

Summary of Stock Appreciation Rights Activity

A summary of stock appreciation rights activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 are presented below:

	Stock Appreciation Rights Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2012	653,030		$	44.14
Granted	88,000		48.36
Exercised/forfeited	(363,653	)	39.66
Outstanding at December 31, 2013	377,377		49.48
Granted	62,749		72.39
Exercised/forfeited	(164,976	)	52.37
Outstanding at December 31, 2014	275,150		52.96
Exercised/forfeited	(10,283	)	55.18
Outstanding at December 31, 2015	264,867		$	52.88

Schedule of Stock Appreciation Rights Valuation Assumptions

For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2015:

Grant date	1/22/2014	1/22/2014	1/24/2013	1/24/2013	1/24/2013	1/26/2011
		(modified)		(modified)	(modified)
Awards granted	62,227	522	83,654	768	3,578	182,199
Fair market value of award	$5.11	$1.67	$8.30	$5.64	$4.24	$4.80
Expected life of award	4.56 years	2.13 years	3.57 years	2.13 years	1.50 years	2.53 years
Risk-free interest rate	1.67%	1.11%	1.43%	1.11%	0.80%	1.23%
Annualized volatility rate	33.4%	33.4%	33.4%	33.4%	33.4%	33.4%
Dividend yield	0.20%	0.20%	0.20%	0.20%	0.20%	0.20%

Grant date	1/26/2011	1/27/2010	1/28/2009	2/4/2008	2/1/2007
	(modified)
Awards granted	7,785	171,749	305,257	67,093	85,906
Fair market value of award	$2.74	$5.95	$13.18	$0.81	$2.16
Expected life of award	1.50 years	2.04 years	1.54 years	1.05 years	0.54 years
Risk-free interest rate	0.80%	1.08%	0.82%	0.65%	0.54%
Annualized volatility rate	33.4%	33.4%	33.4%	33.4%	33.4%
Dividend yield	0.20%	0.20%	0.20%	0.20%	0.20%

Schedule of Incentive Units Activity

A summary of Petrotech unit activity as of December 31, 2015, and transactions during the years ended December 31, 2015, 2014 and 2013 are presented below:

	Petrotech Incentive Plan
	Shares
Outstanding at December 31, 2012	141,243
Granted (three-year vesting period)	92,418
Granted (17 month vesting period)	2,952
Paid	(36,792	)
Forfeited	(26,529	)
Outstanding at December 31, 2013	173,292
Granted	76,084
Paid	(4,431	)
Forfeited	(31,075	)
Outstanding at December 31, 2014	213,870
Granted (three-year vesting period)	128,519
Granted (two-year vesting period)	297
Granted (16 month vesting period)	1,648
Paid	(78,430	)
Forfeited	(22,158	)
Outstanding at December 31, 2015	243,746

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Derivative Commodity Instruments (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Gain (Loss) on Derivative Instruments

The following table details gain (loss) on derivative instruments, net, as follows:

Years ended December 31, (in thousands)	2015			2014		2013
Open non-cash mark-to-market gains (losses) on derivative instruments	$	(281,752	)	$	315,445	$	(47,832	)
Closed gains (losses) on derivative instruments	397,045			19,574		(2,192		)
Gain (loss) on derivative instruments, net	$	115,293		$	335,019	$	(50,024	)

Schedule of Derivative Assets and Liabilities at Fair Value

The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets:

(in thousands)	December 31, 2015
								Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	72,563	$	(15,600	)	$	56,963	$	—	$	—	$	56,963
Liabilities
Derivative instruments	16,059		(15,600		)	459		—		—		459
Total derivatives	$	56,504	$	—		$	56,504	$	—	$	—	$	56,504

(in thousands)	December 31, 2014
								Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	339,977	$	(17,640	)	$	322,337	$	—	$	—	$	322,337
Liabilities
Derivative instruments	18,628		(17,640		)	988		—		—		988
Total derivatives	$	321,349	$	—		$	321,349	$	—	$	—	$	321,349

*All derivative instruments were current at December 31, 2015 and 2014.

The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis:

	December 31, 2015
(in thousands)	Level 2		Level 3			Total
Assets
Derivative instruments	$	69,864	$	(12,901	)	$	56,963
Liabilities
Derivative instruments	2,699		(3,158		)	(459		)
Net derivative asset (liability)	$	72,563	$	(16,059	)	$	56,504

	December 31, 2014
(in thousands)	Level 2		Level 3			Total
Assets
Derivative instruments	$	294,865	$	27,472		$	322,337
Liabilities
Derivative instruments	2,048		(3,036		)	(988		)
Net derivative asset	$	296,913	$	24,436		$	321,349

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location

The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:

Years ended December 31, (in thousands)	Location on Statements of Income	2014		2013
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $23 and ($6,660)	—	$	37	$	(10,866	)
Gain reclassified from accumulated other comprehensive income into income (effective portion)	Gain (loss) on derivative instruments, net	$	21,612	$	34,293
Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Gain (loss) on derivative instruments, net	$	—	$	835

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location

The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:

Years ended December 31, (in thousands)	Location on Statements of Income	2015		2014		2013
Gain (loss) recognized in income on derivatives	Gain (loss) on derivative instruments, net	$	115,293	$	313,408	$	(73,980	)

Schedule of Hedging Transactions

As of December 31, 2015, Energen entered into the following transactions for 2016 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Oil
2016	1,086	MBbl	$63.80 Bbl	NYMEX Swaps
Oil Basis Differential
2016	7,524	MBbl	$(1.92) Bbl	WTI/WTI Basis Swaps
2016	2,117	MBbl	$(1.63) Bbl	WTS/WTI Basis Swaps
WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Schedule of Derivative Liabilities at Fair Value

The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets:

(in thousands)	December 31, 2015
								Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	72,563	$	(15,600	)	$	56,963	$	—	$	—	$	56,963
Liabilities
Derivative instruments	16,059		(15,600		)	459		—		—		459
Total derivatives	$	56,504	$	—		$	56,504	$	—	$	—	$	56,504

(in thousands)	December 31, 2014
								Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	339,977	$	(17,640	)	$	322,337	$	—	$	—	$	322,337
Liabilities
Derivative instruments	18,628		(17,640		)	988		—		—		988
Total derivatives	$	321,349	$	—		$	321,349	$	—	$	—	$	321,349

*All derivative instruments were current at December 31, 2015 and 2014.

The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis:

	December 31, 2015
(in thousands)	Level 2		Level 3			Total
Assets
Derivative instruments	$	69,864	$	(12,901	)	$	56,963
Liabilities
Derivative instruments	2,699		(3,158		)	(459		)
Net derivative asset (liability)	$	72,563	$	(16,059	)	$	56,504

	December 31, 2014
(in thousands)	Level 2		Level 3			Total
Assets
Derivative instruments	$	294,865	$	27,472		$	322,337
Liabilities
Derivative instruments	2,048		(3,036		)	(988		)
Net derivative asset	$	296,913	$	24,436		$	321,349

Schedule of Changes in Fair Value of Derivative Instruments Classified as Level 3

The table below sets forth a summary of changes in the fair value of Energen’s Level 3 derivative commodity instruments as follows:

Years ended December 31, (in thousands)	2015			2014			2013
Balance at beginning of period	$	24,436		$	18,289		$	89,019
Realized gains	13,145			22,208			55,210
Unrealized gains (losses) relating to instruments held at the reporting date*	(40,495		)	2,981			(71,367		)
Settlements during period	(13,145		)	(19,042		)	(54,573		)
Balance at end of period	$	(16,059	)	$	24,436		$	18,289

*Includes $16.1 million in mark-to-market losses, $20.2 million in mark-to-market gains and $7.6 million in mark-to-market losses for the years ended December 31, 2015, 2014 and 2013, respectively.

Schedule of Level Three Fair Value Measurements of Derivative Commodity Instruments

The tables below set forth quantitative information about Energen’s Level 3 fair value measurements of derivative commodity instruments as follows:

(in thousands, except price data)	Fair Value as of December 31, 2015			Valuation Technique*	Unobservable Input*	Range
Oil Basis - WTI/WTI
2016	$	(13,181	)	Discounted Cash Flow	Forward Basis	($0.07 - $0.28) Bbl
Oil Basis - WTS/WTI
2016	$	(2,878	)	Discounted Cash Flow	Forward Basis	($0.19 - $0.31) Bbl

*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

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Exploratory Costs (Tables)

12 Months Ended

Dec. 31, 2015

Extractive Industries [Abstract]

Schedule of Capitalized Exploratory Wells

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:

Years ended December 31, (in thousands)	2015			2014			2013
Capitalized exploratory well costs at beginning of period	$	119,439		$	57,600		$	79,791
Additions pending determination of proved reserves	634,908			946,751			421,599
Reclassifications due to determination of proved reserves	(650,759		)	(882,254		)	(442,909		)
Exploratory well costs charged to expense	—			(2,658		)	(881		)
Capitalized exploratory well costs at end of period	$	103,588		$	119,439		$	57,600

The following table sets forth capitalized exploratory wells costs:

(in thousands)	December 31, 2015		December 31, 2014
Exploratory wells in progress (drilling rig not released)	$	1,760	$	18,781
Capitalized exploratory well costs for a period of one year or less	101,828		100,658
Total capitalized exploratory well costs	$	103,588	$	119,439

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Reconciliation of Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Schedule of Earnings Per Share Reconciliation

Years ended December 31,
(in thousands, except per share amounts)				2015						2014					2013
	Net Loss			Shares	Per Share Amount			Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	(945,731	)	76,078	$	(12.43	)	$	568,032	72,897	$	7.79	$	204,554	72,318	$	2.83
Effect of dilutive securities
Stock options				—						216					112
Non-vested restricted stock				—						58					20
Performance share awards				—						104					21
Diluted EPS	$	(945,731	)	76,078	$	(12.43	)	$	568,032	73,275	$	7.75	$	204,554	72,471	$	2.82

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

Energen had the following shares that were excluded from the computation of diluted EPS, as inclusion would be anti-dilutive.

Years ended December 31, (in thousands)	2015	2014	2013
Stock options	114	114	134
Non-vested restricted stock	—	3	7
Performance share awards	—	2	4

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Schedule of Minimum Future Rental Payments

Minimum future rental payments required after 2015 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2016	2017	2018	2019	2020	2021 and thereafter
$2,537	$2,574	$2,537	$2,431	$—	$—

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

The following table reflects the components of the change in Energen’s ARO balance:

(in thousands)
Balance as of December 31, 2012	$	118,023
Liabilities incurred	2,772
Liabilities settled	(5,525		)
Accretion expense (including discontinued operations of $1,197)	8,192
Reclassification associated with held for sale properties*	(14,929		)
Balance as of December 31, 2013	108,533
Liabilities incurred	2,266
Liabilities settled	(1,543		)
Accretion expense (including discontinued operations of $251)	7,859
Revision in estimated cash flows	692
Reclassification associated with held for sale properties**	(23,747		)
Balance as of December 31, 2014	$	94,060
Liabilities incurred	981
Liabilities settled	(686		)
Accretion expense	7,108
Reclassification associated with held for sale properties***	(11,473		)
Balance as of December 31, 2015	$	89,990

*Asset retirement obligation associated with North Louisiana/East Texas properties.

**Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2014.

***Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2015.

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Asset Impairment (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Impairment of Long-Lived Assets Held and Used by Asset

Impairments recognized by Energen during the years ended December 31, 2015, 2014 and 2013 are presented below:

Years ended December 31, (in thousands)	2015		2014		2013
Continuing operations
Permian Basin properties
Central Basin Platform	$	484,848	$	—	$	—
Delaware Basin	607,303		90,594		—
Midland Basin	—		25,776		—
San Juan Basin properties	133,055		230,315		—
Permian Basin unproved leasehold properties	29,168		64,361		13,906
San Juan Basin unproved leasehold properties	37,934		5,755		—
Total asset impairments from continuing operations	1,292,308		416,801		13,906
Discontinued operations
North Louisiana/East Texas oil and natural gas properties	—		1,936		29,794
Total asset impairments from discontinued operations	—		1,936		29,794
Total asset impairments	$	1,292,308	$	418,737	$	43,700

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Discontinued Operations and Held for Sale Properties (Tables)

12 Months Ended

Dec. 31, 2015

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Discontinued Operations

The following table details San Juan Basin held for sale properties by major classes of assets and liabilities. Property sales in the San Juan Basin do not qualify for discontinued operations:

(in thousands)	December 31, 2015			December 31, 2014
Inventories	$	3,651		$	—
Oil and natural gas properties	305,386			1,166,124
Less accumulated depreciation, depletion and amortization	(219,059		)	(770,327		)
Other property and equipment, net	3,761			—
Total assets held for sale	93,739			395,797
Other long-term liabilities	(12,789		)	(24,230		)
Total liabilities held for sale	(12,789		)	(24,230		)
Total net assets held for sale	$	80,950		$	371,567

We classified as discontinued operations interest on debt required to be extinguished, certain depreciation costs that ended at close of transaction, the related income tax impact of these items and the earnings of Alagasco. In addition, we reclassified from discontinued operations certain general and administrative expenses, other income and the related tax impact from these items. The table below provides a detail of these items included in income (loss) from discontinued operations as follows:

Years ended December 31, (in thousands)	2014			2013
Alagasco net income	$	40,646		$	57,399
Depreciation, depletion and amortization	(408		)	(598		)
General and administrative	3,337			5,894
Interest expense	(17,306		)	(13,815		)
Other income	(347		)	(1,342		)
Income tax expense	5,567			3,728
Alagasco income from discontinued operations	31,489			51,266
Energen income (loss) from discontinued operations	(2,197		)	7,813
Income from discontinued operations	$	29,292		$	59,079

Years ended December 31, (in thousands, except per share data)	2014		2013
Natural gas distribution revenues	$	397,648	$	533,338
Oil and natural gas revenues	5,199		60,191
Total revenues	$	402,847	$	593,529
Pretax income from discontinued operations	$	47,220	$	92,253
Income tax expense	17,928		33,174
Income From Discontinued Operations	$	29,292	$	59,079
Gain on disposal of discontinued operations, net	$	724,594	$	5,605
Income tax expense	285,497		2,011
Gain on Disposal of Discontinued Operations, net	$	439,097	$	3,594
Total Income From Discontinued Operations	$	468,389	$	62,673
Diluted Earnings Per Average Common Share
Income from discontinued operations	$	0.40	$	0.81
Gain on disposal of discontinued operations, net	5.99		0.05
Total Income From Discontinued Operations	$	6.39	$	0.86
Basic Earnings Per Average Common Share
Income from discontinued operations	$	0.40	$	0.82
Gain on disposal of discontinued operations, net	6.02		0.05
Total Income From Discontinued Operations	$	6.42	$	0.87

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2015

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Supplemental information concerning Energen’s cash flow activities from continuing operations was as follows:

Years ended December 31, (in thousands)	2015		2014		2013
Interest paid, net of amount capitalized	$	40,747	$	32,172	$	38,255
Income taxes paid	$	8,114	$	219,505	$	22,781
Noncash investing activities:
Accrued development, exploration costs and other capital	$	79,206	$	207,461	$	93,623
Capitalized asset retirement obligations costs	$	981	$	2,958	$	2,772
Receivable from sale of Alabama Gas Corporation	$	—	$	8,247	$	—
Noncash financing activities:
Issuance of common stock for employee benefit plans	$	5,758	$	2,448	$	1,015
Treasury stock acquired in connection with tax withholdings	$	4,722	$	2,547	$	977

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Accumulated Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects:

(in thousands)	Pension and Postretirement Plans
Balance as of December 31, 2014	$	(22,870	)
Other comprehensive income before reclassifications	3,305
Amounts reclassified from accumulated other comprehensive income	19,828
Change in accumulated other comprehensive income (loss)	23,133
Balance as of December 31, 2015	$	263

Reclassification out of Accumulated Other Comprehensive Income

The following table provides details of the reclassifications out of accumulated other comprehensive income (loss):

Years ended December 31, (in thousands)	2015			2014			2013
				Amounts Reclassified						Line Item Where Presented
Gains (losses) on cash flow hedges:
Commodity contracts	$	—		$	21,611		$	35,684		Gain (loss) on derivative instruments, net
Interest rate swap	—			(2,280		)	(1,723		)	Interest expense
Total cash flow hedges	—			19,331			33,961
Income tax expense	—			(7,414		)	(12,957		)
Net of tax	—			11,917			21,004
Pension and postretirement plans:
Transition obligation	—			(22		)	(319		)	General and administrative
Prior service cost	—			(248		)	(257		)	General and administrative
Actuarial losses	(30,504		)	(21,932		)	(12,357		)	General and administrative
Actuarial losses on settlement charges*	—			—			(421		)	Assets held for sale
Total pension and postretirement plans	(30,504		)	(22,202		)	(13,354		)
Income tax benefit	10,676			7,771			4,674
Net of tax	(19,828		)	(14,431		)	(8,680		)
Total reclassifications for the period	$	(19,828	)	$	(2,514	)	$	12,324

*During the year ended December 31, 2013, Energen incurred settlement charges of $0.6 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.2 million was recognized in actuarial losses above and $0.4 million was recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Operating Results

The following data summarizes quarterly operating results:

	Year ended December 31, 2015
(in thousands, except per share amounts)	First			Second			Third			Fourth
Revenues	$	221,858		$	168,326		$	295,571		$	192,799
Operating loss	$	(12,409	)	$	(161,678	)	$	(348,214	)	$	(915,550	)
Loss from continuing operations	$	(15,420	)	$	(111,601	)	$	(227,904	)	$	(590,806	)
Net loss	$	(15,420	)	$	(111,601	)	$	(227,904	)	$	(590,806	)
Diluted earnings per average common share
Continuing operations	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)
Net loss	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)
Basic earnings per average common share
Continuing operations	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)
Net loss	$	(0.21	)	$	(1.52	)	$	(2.89	)	$	(7.50	)

	Year ended December 31, 2014
(in thousands, except per share amounts)	First			Second			Third		Fourth
Revenues as originally reported	$	561,178		$	270,097		$	497,761	$	611,435
Discontinued operations*	(263,900		)	—			—		—
Reclassification of loss on sale of assets and other	153			909			747		833
Adjusted revenues	$	297,431		$	271,006		$	498,508	$	612,268
Operating income as originally reported	$	104,599		$	3,107		$	48,171	$	94,223
Discontinued operations*	(73,139		)	—			—		—
Adjusted operating income	$	31,460		$	3,107		$	48,171	$	94,223
Income (loss) from continuing operations	$	15,647		$	(3,154	)	$	20,631	$	66,519
Net income (loss)	$	53,316		$	(7,953	)	$	457,251	$	65,418
Diluted earnings per average common share
Continuing operations	$	0.21		$	(0.04	)	$	0.28	$	0.91
Net income (loss)	$	0.73		$	(0.11	)	$	6.22	$	0.89
Basic earnings per average common share
Continuing operations	$	0.22		$	(0.04	)	$	0.28	$	0.91
Net income (loss)	$	0.73		$	(0.11	)	$	6.26	$	0.90

*As discussed in Note 16, Discontinued Operations and Held for Sale Properties, during the third quarter of 2014, Energen completed the transaction to sell Alagasco to Laclede. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations.

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Oil and Natural Gas Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Extractive Industries [Abstract]

Schedule of Capitalized Costs

The following table sets forth capitalized costs:

(in thousands)	December 31, 2015		December 31, 2014
Proved	$	7,911,554	$	8,069,638
Unproved	150,674		142,340
Total capitalized costs	8,062,228		8,211,978
Accumulated depreciation, depletion and amortization	3,673,569		2,663,434
Capitalized costs, net	$	4,388,659	$	5,548,544

Schedule of Cost Incurred in Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year:

Years ended December 31, (in thousands)	2015		2014		2013
Property acquisition:
Proved	$	1,866	$	2,582	$	4,661
Unproved	85,690		68,514		26,820
Exploration	649,764		972,164		435,636
Development	372,177		408,949		655,353
Total costs incurred	$	1,109,497	$	1,452,209	$	1,122,470

Schedule of Results of Operations from Producing Activities

The following table sets forth results of Energen’s oil, natural gas liquids and natural gas operations from producing activities:

Years ended December 31, (in thousands)	2015			2014		2013
Gross revenues*	$	878,554		$	1,679,213	$	1,206,293
Production (lifting costs)	285,760			376,495		351,541
Exploration expense	14,877			28,090		14,036
Depreciation, depletion and amortization including asset impairments	1,880,190			960,539		463,606
Accretion expense	7,108			7,608		6,995
Income tax expense (benefit)	(469,362		)	99,469		128,773
Results of operations from producing activities	$	(840,019	)	$	207,012	$	241,342

* The years ended December 31, 2015, 2014 and 2013 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $281.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million and a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, respectively.

Schedule of Proved Developed and Undeveloped Oil and Gas Reserves

The independent reservoir engineers have issued reports covering approximately 99 percent of Energen’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

Year ended December 31, 2015	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	181,227		73,463		707,926		372.7
Revisions of previous estimates	(39,537	)	(11,979	)	(44,176	)	(58.9	)
Purchases	2		1		2		—
Extensions and discoveries	83,319		25,530		143,022		132.6
Production	(14,023	)	(4,065	)	(35,604	)	(24.0	)
Sales	(297	)	(11,237	)	(337,266	)	(67.7	)
Proved reserves at end of period	210,691		71,713		433,904		354.7
Proved developed reserves at end of period	108,319		36,374		236,112		184.0
Proved undeveloped reserves at end of period	102,372		35,339		197,792		170.7

Year ended December 31, 2014	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	164,870		63,011		719,725		347.8
Revisions of previous estimates	(48,548	)	(15,165	)	(71,806	)	(75.7	)
Purchases	88		26		116		0.1
Extensions and discoveries	76,722		29,695		141,209		130
Production	(11,818	)	(4,104	)	(59,562	)	(25.8	)
Sales	(87	)	—		(21,756	)	(3.7	)
Proved reserves at end of period	181,227		73,463		707,926		372.7
Proved developed reserves at end of period	118,697		47,621		589,074		264.5
Proved undeveloped reserves at end of period	62,530		25,842		118,852		108.2

Year ended December 31, 2013	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	155,348		56,155		809,128		346.4
Revisions of previous estimates	(680	)	2,211		18,465		4.6
Purchases	142		56		282		0.2
Extensions and discoveries	20,517		7,823		50,568		36.8
Production	(10,378	)	(3,233	)	(70,506	)	(25.4	)
Sales	(79	)	(1	)	(88,212	)	(14.8	)
Proved reserves at end of period	164,870		63,011		719,725		347.8
Proved developed reserves at end of period	113,795		42,087		623,305		259.8
Proved undeveloped reserves at end of period	51,075		20,924		96,420		88.0

Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Years ended December 31, (in thousands)	2015		2014		2013
Future gross revenues	$	11,714,729	$	20,971,672	$	19,509,305
Future production costs	4,353,974		7,532,273		6,136,709
Future development costs	1,961,661		1,784,738		1,896,602
Future income tax expense	1,065,887		3,440,582		3,209,697
Future net cash flows	4,333,207		8,214,079		8,266,297
Discount at 10% per annum	2,299,859		3,994,423		4,248,456
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	2,033,348	$	4,219,656	$	4,017,841

Schedule of Principal Sources of Changes in Standardized Measure of Discounted Future Net Cash Flows

The following are the principal sources of changes in the standardized measure of discounted future net cash flows:

Years ended December 31, (in thousands)	2015			2014			2013
Balance at beginning of year	$	4,219,656		$	4,017,841		$	3,699,319
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(2,861,591		)	(1,147,028		)	566,838
Net changes due to revisions in quantity estimates	(404,708		)	(1,285,394		)	(81,762		)
Development costs incurred, previously estimated	350,560			337,198			299,432
Accretion of discount	421,966			401,784			369,932
Changes in timing and other*	(903,975		)	987,652			(179,502		)
Total revisions	(3,397,748		)	(705,788		)	974,938
New field discoveries and extensions, net of future production and development costs	776,315			2,321,028			376,326
Sales of oil and gas produced, net of production costs	(514,380		)	(1,054,553		)	(1,014,593		)
Purchases	8			4,241			4,690
Sales	(372,039		)	(21,092		)	(24,876		)
Net change in income taxes	1,321,536			(342,021		)	2,037
Net change in standardized measure of discounted future net cash flows	(2,186,308		)	201,815			318,522
Balance at end of year	$	2,033,348		$	4,219,656		$	4,017,841

*Amount represents changes in production timing and other. In 2015, the production timing is significantly affected by changes related to the delay of the drilling program. For 2014, the production timing is significantly affected by changes related to the acceleration of the horizontal drilling program and the delay of the vertical drilling program. 

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Organization and Basis of Presentation (Sale of Alabama Gas Corporation) (Details) - USD ($) $ in Thousands		12 Months Ended
	Sep. 02, 2014	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Pre-tax gain on disposal of discontinued operations		$ 724,594	$ 5,605
Alabama Gas Corporation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration	$ 1,600,000
Debt assumed	267,000
Proceeds from sale	1,320,000
Pre-tax gain on disposal of discontinued operations	$ 726,500

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Organization and Basis of Presentation (Additional Information) (Details)		3 Months Ended
	Sep. 02, 2014	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Oct. 20, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Line of Credit Facility [Line Items]
Cash			$ 1,272,000		$ 1,852,000	$ 2,523,000
Available for borrowings			1,177,500,000		1,515,000,000
Long-term debt, gross			776,500,000		1,039,000,000
Outstanding long-term debt			$ 776,500,000
Syndicated Credit Facility | Credit Facility, September 2, 2014
Line of Credit Facility [Line Items]
Credit facility				$ 1,400,000,000
Debt instrument, term	5 years
Debt covenant, debt to EBITDAX ratio			4.0
Medium-term Notes and Notes Payable, Other Payables [Member]
Line of Credit Facility [Line Items]
Long-term debt, gross			$ 554,000,000
Credit facility | Credit facility
Line of Credit Facility [Line Items]
Long-term debt, gross			$ 222,500,000		$ 485,000,000
One-time Termination Benefits | Subsequent Event
Line of Credit Facility [Line Items]
Incurred cost in connection with workforce reduction		$ 3,200,000

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Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allowance for doubtful accounts receivable	$ 700,000	$ 700,000
Short-term investments	0	0
Excess tax benefit from share-based compensation	$ 1,100,000	$ 5,900,000	$ 3,100,000
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Yield curve, term	0 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Yield curve, term	30 years

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Long-Term Debt (Schedule of Long-Term Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt, gross	$ 776,500	$ 1,039,000
Less unamortized debt discount	413	437
Long-term debt	776,087	1,038,563
Credit facility | Credit facility
Debt Instrument [Line Items]
Long-term debt, gross	222,500	485,000
Medium-term Notes | 7.40% Medium-term Notes, Series A, due July 24, 2017
Debt Instrument [Line Items]
Long-term debt, gross	$ 2,000	$ 2,000
Debt instrument, interest rate	7.40%	7.40%
Medium-term Notes | 7.36% Medium-term Notes, Series A, due July 24, 2017
Debt Instrument [Line Items]
Long-term debt, gross	$ 15,000	$ 15,000
Debt instrument, interest rate	7.36%	7.36%
Medium-term Notes | 7.23% Medium-term Notes, Series A, due July 28, 2017
Debt Instrument [Line Items]
Long-term debt, gross	$ 2,000	$ 2,000
Debt instrument, interest rate	7.23%	7.23%
Medium-term Notes | 7.32% Medium-term Notes, Series A, due July 28, 2022
Debt Instrument [Line Items]
Long-term debt, gross	$ 20,000	$ 20,000
Debt instrument, interest rate	7.32%	7.32%
Medium-term Notes | 7.60% Medium-term Notes, Series A, due July 26, 2027
Debt Instrument [Line Items]
Long-term debt, gross	$ 5,000	$ 5,000
Debt instrument, interest rate	7.60%	7.60%
Medium-term Notes | 7.35% Medium-term Notes, Series A, due July 28, 2027
Debt Instrument [Line Items]
Long-term debt, gross	$ 10,000	$ 10,000
Debt instrument, interest rate	7.35%	7.35%
Medium-term Notes | 7.125% Medium-term Notes, Series B, due February 15, 2028
Debt Instrument [Line Items]
Long-term debt, gross	$ 100,000	$ 100,000
Debt instrument, interest rate	7.125%	7.125%
Notes | 4.625% Notes, due September 1, 2021
Debt Instrument [Line Items]
Long-term debt, gross	$ 400,000	$ 400,000
Debt instrument, interest rate	4.625%	4.625%

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Long-Term Debt (Aggregate Maturities) (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Maturities of Long-term Debt [Abstract]
2016	$ 0
2017	19,000
2018	0
2019	222,500
2020	0
Thereafter	$ 535,000

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Long-Term Debt (Additional Information) (Details) - USD ($)		12 Months Ended
	Sep. 02, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 20, 2015
Debt Instrument [Line Items]
Cross default provision, minimum threshold amount		$ 10,000,000
Loan limit percentage (less than)		10.00%
Cross default provision, minimum debt default amount		$ 75,000,000
Interest expense		43,108,000	$ 37,771,000	$ 39,736,000
Amortization of debt issuance costs		$ 3,300,000	5,700,000	2,000,000
Interest expense, capitalized			$ 200,000	$ 200,000
Unused capacity, commitment fee percentage		0.30%
Syndicated Credit Facility | Credit Facility, September 2, 2014
Debt Instrument [Line Items]
Debt instrument, term	5 years
Credit facility					$ 1,400,000,000
Debt covenant, debt to EBITDAX ratio		4.0
Debt covenant, current assets to current liabilities ratio		1.0
Debt covenant, minimum net present value of proved reserves to consolidated debt, ratio		1.50

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Long-Term Debt (Lines of Credit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Abstract]
Credit facility outstanding	$ 222,500	$ 485,000
Available for borrowings	1,177,500	1,515,000
Total borrowing commitments	1,400,000	2,000,000
Maximum amount outstanding at any month-end	685,000	750,000
Average daily amount outstanding	$ 358,929	$ 482,166
Average daily amount outstanding	1.60%	1.46%
Amount outstanding at year-end	1.64%	1.67%

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Income Taxes (Components of Income Taxes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Taxes estimated to be payable currently:
Federal	$ 3,972	$ 161,576	$ 23,342
State	758	72,379	2,516
Total current	4,730	233,955	25,858
Taxes deferred:
Federal	(513,187)	144,645	85,950
State	(26,548)	(34,447)	(2,300)
Total deferred	(539,735)	110,198	83,650
Total income tax expense (benefit)	$ (535,005)	$ 344,153	$ 109,508

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Income Taxes (Components of Income Taxes, Continuing and Discontinued Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Income tax expense (benefit) from continuing operations	$ (535,005)	$ 40,728	$ 74,323
Income tax expense from discontinued operations	0	17,928	33,174
Income tax expense from gain on disposal of discontinued operations	0	285,497	2,011
Total income tax expense (benefit)	$ (535,005)	$ 344,153	$ 109,508

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Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Income Tax Contingency [Line Items]
Full valuation allowance	$ 4,200
Deferred tax assets:
Total deferred tax assets, Current	0	$ 25,533
Total deferred tax assets, Noncurrent	81,804	70,320
Valuation allowance, Current	0	(1,122)
Valuation allowance, Noncurrent	(4,235)	(2,467)
Total deferred tax assets, net, Current	0	24,411
Total deferred tax assets, net, Noncurrent	77,569	67,853
Deferred tax liabilities:
Total deferred tax liabilities, current	0	103,575
Total deferred tax liabilities, noncurrent	629,938	1,068,339
Deferred tax liabilities, net, current	0	(79,164)
Deferred tax liabilities, net, noncurrent	(552,369)	(1,000,486)
Oil and Gas Operations
Income Tax Contingency [Line Items]
State operating loss carryforwards and other tax carryforwards portion about to expire	191,300
Deferred tax assets, Current
Deferred tax assets:
Minimum tax credit	0	0
Allowance for doubtful accounts	0	244
Insurance and other accruals	0	2,537
Compensation accruals	0	11,355
Pension and other costs	0	0
Other comprehensive income	0	10,732
State net operating losses and other carryforwards	0	0
Other	0	665
Deferred tax assets, Noncurrent
Income Tax Contingency [Line Items]
State net operating loss carryforwards, subject to expiration	8,400
Deferred tax assets:
Minimum tax credit	44,862	46,338
Allowance for doubtful accounts	253	0
Insurance and other accruals	2,807	0
Compensation accruals	11,650	0
Pension and other costs	8,693	7,009
Other comprehensive income	0	1,581
State net operating losses and other carryforwards	12,577	15,392
Other	962	0
Deferred tax liabilities, Current
Deferred tax liabilities:
Depreciation and basis differences	0	0
Derivative instruments	0	102,691
Other comprehensive income	0	0
Other	0	884
Deferred tax liabilities, Noncurrent
Deferred tax liabilities:
Depreciation and basis differences	620,629	1,057,430
Derivative instruments	2,838	0
Other comprehensive income	141	0
Other	6,330	$ 10,909
New Accounting Pronouncement, Early Adoption, Effect
Income Tax Contingency [Line Items]
Amount of reclassified current deferred tax asset	(14,500)
Deferred tax liabilities:
Deferred tax liabilities, net, noncurrent	$ (14,500)

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Income Taxes (Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Statutory federal income tax rate			35.00%	35.00%	35.00%
Income tax expense (benefit) at statutory federal income tax rate			$ (518,258)	$ 49,130	$ 75,671
State income taxes, net of federal income tax benefit			(14,112)	93	1,461
Impact of state law changes			(3,075)	(121)	(1,966)
Impact of state deferred tax revaluation on San Juan properties	$ 1,200	$ 8,400	(1,241)	(8,382)	0
401(k) stock dividend deduction			0	(232)	(449)
Other, net			1,681	240	(394)
Total income tax expense (benefit)			$ (535,005)	$ 40,728	$ 74,323
Effective income tax rate (%)			36.13%	29.01%	34.38%

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Income Taxes (Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance	$ 17,530	$ 15,986	$ 12,555
Additions based on tax positions related to the current year	2,378	3,873	4,546
Additions for tax positions of prior years		19	366
Reductions based on tax positions related to the current year	(6,589)
Reductions for tax positions of prior years	(345)	(954)	(46)
Lapse of statute of limitations	(1,785)	(1,394)	(1,435)
Unrecognized Tax Benefits, Ending Balance	11,189	17,530	15,986
Unrecognized tax benefits that would impact effective tax rate	3,000
Income tax interest expense (income) net of tax benefit and penalties	(2)	27	$ 15
Accrued interest (net of tax benefit) and penalties payments	$ 200	$ 200

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Employee Benefit Plans (Benefit Obligations) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Benefit obligation:
Termination benefit charge	$ 2,500
Amounts recognized in balance sheet
Noncurrent assets	0	$ 3,881	$ 0
Noncurrent liabilities	(15,935)	0	(15,935)
Amounts recognized to accumulated other comprehensive income:
Total accumulated other comprehensive income (loss)	22,870	(263)	22,870
Nonqualified Supplemental Retirement Plans
Defined Benefit Plan Disclosure [Line Items]
Reclassification of assets		3,300
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	107,669	15,729	107,669
Benefit obligation:
Balance at beginning of period		107,669	266,294
Service cost		0	8,329
Interest cost		816	5,325
Actuarial (gain) loss		(683)	9,078
Plan amendments		0	0
Curtailment gain		0	(8,496)
Transfer in connection with the sale of Alagasco		0	(124,783)
Termination benefit charge		0	2,477	$ 0
Retiree drug subsidy program		0	0
Benefits paid		(92,073)	(50,555)
Balance at end of period	107,669	15,729	107,669	266,294
Plan assets:
Fair value of plan assets at beginning of period		67,542	193,457
Actual return (loss) on plan assets		(289)	5,359
Employer contributions		24,847	19,164
Transfer in connection with the sale of Alagasco		0	(99,883)
Benefits paid		(92,073)	(50,555)
Fair value of plan assets at end of period	67,542	27	67,542	193,457
Funded status of plans	(40,127)	(15,702)	(40,127)
Amounts recognized in balance sheet
Noncurrent assets	0	0	0
Current liabilities	(24,626)	(15,702)	(24,626)
Noncurrent liabilities	(15,501)	0	(15,501)
Net asset (liability) recognized	(40,127)	(15,702)	(40,127)
Amounts recognized to accumulated other comprehensive income:
Prior service credit, net of taxes	0	0	0
Net actuarial loss, net of taxes	22,246	2,179	22,246
Total accumulated other comprehensive income (loss)	22,246	2,179	22,246
Postretirement Benefits
Benefit obligation:
Balance at beginning of period		11,127	33,224
Service cost		392	262
Interest cost		466	716
Actuarial (gain) loss		(1,185)	6,385
Plan amendments		(4,071)	0
Curtailment gain		0	0
Transfer in connection with the sale of Alagasco		0	(28,648)
Termination benefit charge		0	0
Retiree drug subsidy program		0	48
Benefits paid		(241)	(860)
Balance at end of period	11,127	6,488	11,127	33,224
Plan assets:
Fair value of plan assets at beginning of period		10,693	55,459
Actual return (loss) on plan assets		(83)	(331)
Employer contributions		0	21
Transfer in connection with the sale of Alagasco		0	(43,596)
Benefits paid		(241)	(860)
Fair value of plan assets at end of period	10,693	10,369	10,693	$ 55,459
Funded status of plans	(434)	3,881	(434)
Amounts recognized in balance sheet
Noncurrent assets	0	3,881	0
Current liabilities	0	0	0
Noncurrent liabilities	(434)	0	(434)
Net asset (liability) recognized	(434)	3,881	(434)
Amounts recognized to accumulated other comprehensive income:
Prior service credit, net of taxes	0	(2,646)	0
Net actuarial loss, net of taxes	624	205	624
Total accumulated other comprehensive income (loss)	$ 624	$ (2,441)	$ 624

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Employee Benefit Plans (Other Investment Assets) (Details) - Nonqualified Supplemental Retirement Plans - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 3,308	$ 14,184
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		4,255
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,308	9,929
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,308	9,929
Level 1 | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0
Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,308	9,929
Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	4,255
Level 2 | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		4,255
Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 0	$ 0

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Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Components of net periodic benefit cost:
Termination benefit charge	$ 2,500
Pension Benefits
Components of net periodic benefit cost:
Service cost		$ 0	$ 8,329
Interest cost		816	5,325
Expected long-term return on assets		0	(4,386)	$ (5,225)
Prior service cost amortization		0	202	246
Actuarial loss amortization		737	4,995	6,919
Termination benefit charge		0	2,477	0
Settlement charge		29,767	4,082	161
Curtailment expense (gain)		0	254	(4)
Net periodic expense		31,320	18,930	11,789
Postretirement Benefits
Components of net periodic benefit cost:
Service cost		392	262
Interest cost		466	716
Expected long-term return on assets		(457)	(1,122)	(787)
Actuarial loss amortization		0	(653)	(28)
Termination benefit charge		0	0
Transition obligation amortization		0	44	229
Net periodic expense		401	(817)	445
Continuing Operations | Pension Benefits
Components of net periodic benefit cost:
Service cost		0	6,808	5,196
Interest cost		816	4,498	4,496
Continuing Operations | Postretirement Benefits
Components of net periodic benefit cost:
Service cost		392	253	386
Interest cost		$ 466	$ 661	$ 645

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Employee Benefit Plans (Other Comprehensive Income) (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Termination benefit charge		$ 2,500
Pension Benefits
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net actuarial (gain) loss experienced during the year				$ (394)	$ 10,495	$ (14,138)
Net actuarial loss recognized as expense				(30,478)	(25,433)	(8,934)
Prior service cost recognized as expense				0	(246)	(311)
Curtailment loss				0	(8,749)	0
Total recognized in other comprehensive income (loss)				(30,872)	(23,933)	(23,383)
Settlement charges				27,300	7,600
Settlement charges expensed					3,700
Termination benefit charge				0	2,477	0
Curtailment gain				0	8,496
Settlement charge				29,767	4,082	161
Amortization of net actuarial loss				3,352
Postretirement Benefits
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net actuarial (gain) loss experienced during the year				(645)	7,649	(8,057)
Net actuarial loss recognized as expense				0	1,908	550
Prior service cost recognized as expense				(4,071)	0	0
Transition obligation recognized as expense				0	(48)	(283)
Total recognized in other comprehensive income (loss)				(4,716)	9,509	(7,790)
Termination benefit charge				0	0
Curtailment gain				0	0
Amortization of prior service credit				(515)
Nonqualified Supplemental Retirement Plans
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Settlement charges	$ 2,500	1,800			400	600
Settlement charges expensed						200
Long-term Disability Plan
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Expense related to long-term disability plan				$ 200	$ 200	200
Alabama Gas Corporation | Nonqualified Supplemental Retirement Plans
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Settlement charges						$ 400
Alagasco
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Curtailment gain		$ 300
Black Warrior Basin
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Curtailment gain			$ 1,200

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Employee Benefit Plans (Assumptions) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plans
One year spot rate	0.70%
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year	7.75%	7.25%
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%
Year that rate reaches ultimate rate	2026	2021
Pension Benefits
Pension Plans
Discount rate	0.96%	3.66%	3.63%
Expected long-term return on plan assets	0.00%	7.00%	7.00%
Rate of compensation increase for pay-related plans	0.00%	3.63%	3.71%
Postretirement Benefit Plans
Discount rate	3.90%	0.96%
Postretirement Benefits
Pension Plans
Discount rate	4.25%	4.88%	4.36%
Expected long-term return on plan assets	6.20%	7.00%	7.00%
Rate of compensation increase for pay-related plans	0.00%	3.60%	3.70%
Postretirement Benefit Plans
Discount rate	4.70%	4.25%

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Employee Benefit Plans (Allocation of Plan Assets) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation	100.00%
Actual plan asset allocation	100.00%	100.00%
Postretirement Benefits
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation	100.00%
Actual plan asset allocation	100.00%	100.00%
Equity securities | Pension Benefits
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation	0.00%
Actual plan asset allocation	0.00%	0.00%
Equity securities | Postretirement Benefits
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation	56.00%
Actual plan asset allocation	56.00%	60.00%
Debt securities | Pension Benefits
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation	0.00%
Actual plan asset allocation	0.00%	0.00%
Debt securities | Postretirement Benefits
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation	44.00%
Actual plan asset allocation	44.00%	40.00%
Cash and cash equivalents | Pension Benefits
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation	100.00%
Actual plan asset allocation	100.00%	100.00%
Cash and cash equivalents | Postretirement Benefits
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation	0.00%
Actual plan asset allocation	0.00%	0.00%

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Employee Benefit Plans (Fair Value of Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 27	$ 67,542	$ 193,457
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	27	67,542
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Pension Benefits | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	27	67,542
Pension Benefits | Cash and cash equivalents | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	27	67,542
Pension Benefits | Cash and cash equivalents | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10,369	10,693	$ 55,459
Postretirement Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,835	6,426
Postretirement Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,534	4,267
Postretirement Benefits | United States equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,185	4,715
Postretirement Benefits | United States equities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,185	4,715
Postretirement Benefits | United States equities | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Postretirement Benefits | Global equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,650	1,711
Postretirement Benefits | Global equities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1,650	1,711
Postretirement Benefits | Global equities | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Postretirement Benefits | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,534	4,267
Postretirement Benefits | Fixed income | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Postretirement Benefits | Fixed income | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 4,534	$ 4,267

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Employee Benefit Plans (Cash Flows) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($)
Nonqualified Supplemental Retirement Plans
Defined Benefit Plan Disclosure [Line Items]
Anticipated required or discretionary contributions during in next fiscal year	$ 14,600
Pension Benefits
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
2016	14,606
2017	117
2018	114
2019	110
2020	107
2021-2025	472
Postretirement Benefits
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
2016	198
2017	213
2018	245
2019	258
2020	289
2021-2025	$ 1,769

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Common Stock Plans (Energen Employee Savings Plan) (Details) - Energen Employee Savings Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of common stock that might be diversified into other investment options	100.00%
Expense associated with contributions to employee savings plan	$ 5.7	$ 3.7	$ 3.7

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Common Stock Plans (Stock Incentive Plan) (Details) - Stock Incentive Plan - shares	Dec. 31, 2015	Apr. 27, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for issuance		8,600,000
Number of shares remaining for issuance	2,294,740

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Common Stock Plans (Performance Share Awards) (Details) - Performance share awards - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Weighted Average Price
Share-based compensation expense	$ 6.7	$ 6.2	$ 3.8
Tax benefit related to stock-based compensation	2.4	$ 2.3	$ 1.4
Unrecognized compensation cost	$ 8.9
Weighted average requisite service period	1 year 7 months 28 days
Stock Incentive Plan
Shares
Nonvested, Beginning of Period, Shares	212,968	160,819	0
Forfeited, Shares			(8,008)
Vested and paid, Shares	(77,257)	(14,097)
Nonvested, End of Period, Shares	256,083	212,968	160,819
Weighted Average Price
Nonvested, Beginning of Period, Weighted Average Price (in dollars per share)	$ 71.53	$ 62.13	$ 0.00
Forfeited, Weighted Average Price (in dollars per share)			60.03
Vested and paid, Weighted Average Price (in dollars per share)	61.36	70.06
Nonvested, End of Period, Weighted Average Price (in dollars per share)	$ 80.43	$ 71.53	$ 62.13
Stock Incentive Plan | Two year vesting period
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, vesting period	2 years
Shares
Granted, Shares		937	86,221
Weighted Average Price
Granted, Weighted Average Price (in dollars per share)		$ 131.56	$ 61.14
Stock Incentive Plan | Three year vesting period
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, vesting period	3 years
Shares
Granted, Shares	120,372	65,309	82,606
Weighted Average Price
Granted, Weighted Average Price (in dollars per share)	$ 83.94	$ 93.49	$ 62.96

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Common Stock Plans (Restricted Stock) (Details) - Restricted Stock and Restricted Stock Units - Stock Incentive Plan - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 6.0	$ 3.2	$ 1.9
Tax benefit related to stock-based compensation	2.1	$ 1.2	$ 0.7
Unrecognized compensation cost	$ 1.9
Remaining requisite service period (in years)	1 year 9 months
Shares
Nonvested, Beginning of Period, Shares	99,574	62,518	11,115
Granted, Shares	99,814	48,904	52,650
Forfeited, Shares			(1,247)
Vested, Shares	(14,446)	(11,848)
Nonvested, End of Period, Shares	184,942	99,574	62,518
Weighted Average Price
Nonvested, Beginning of Period, Weighted Average Price (in dollars per share)	$ 59.60	$ 51.16	$ 45.24
Granted, Weighted Average Price (in dollars per share)	65.15	71.91	52.34
Forfeited, Weighted Average Price (in dollars per share)			48.36
Vested and paid, Weighted Average Price (in dollars per share)	53.20	65.94
Nonvested, End of Period, Weighted Average Price (in dollars per share)	$ 63.09	$ 59.60	$ 51.16

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Common Stock Plans (Stock Options) (Details) - Stock Incentive Plan - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Shares
Remaining reserved for issuance	2,294,740
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, vesting period	3 years
Share-based compensation, expiration period	10 years
Shares
Outstanding, Beginning of Period, Shares	757,071	1,191,044	1,648,475
Granted, Shares		110,307	137,762
Exercised, Shares	(23,680)	(544,280)	(590,119)
Forfeited, Shares			(5,074)
Outstanding, End of Period, Shares	733,391	757,071	1,191,044
Exercisable, Shares	622,156	454,938	713,445
Weighted Average Exercise Price
Outstanding, Beginning of Period, Weighted Average Exercise Price (in dollars per share)	$ 54.88	$ 51.06	$ 47.58
Granted, Weighted Average Exercise Price (in dollars per share)		72.55	49.22
Exercised, Weighted Average Exercise Price (in dollars per share)	41.42	50.09	40.92
Forfeited, Weighted Average Exercise Price (in dollars per share)			51.85
Outstanding, End of Period, Weighted Average Exercise Price (in dollars per share)	55.32	54.88	51.06
Exercisable, Weighted Average Exercise Price (in dollars per share)	$ 53.80	$ 51.88	$ 49.80

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Common Stock Plans (Stock Options, Valuation Assumptions) (Details) - Stock options - Stock Incentive Plan - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted		110,307	137,762
4/15/2014
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	2,439
Fair market value of stock option at grant (in dollars per share)	$ 32.22
Expected life of award	5 years 9 months 18 days
Risk-free interest rate	1.93%
Annualized volatility rate	40.70%
Dividend yield	0.20%
1/22/2014
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	107,868
Fair market value of stock option at grant (in dollars per share)	$ 27.57
Expected life of award	5 years 9 months 18 days
Risk-free interest rate	2.06%
Annualized volatility rate	40.70%
Dividend yield	0.80%
10/15/2013
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	3,686
Fair market value of stock option at grant (in dollars per share)	$ 30.53
Expected life of award	5 years 9 months 18 days
Risk-free interest rate	1.79%
Annualized volatility rate	40.60%
Dividend yield	0.70%
1/24/2013
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	134,076
Fair market value of stock option at grant (in dollars per share)	$ 16.66
Expected life of award	5 years 9 months 18 days
Risk-free interest rate	1.01%
Annualized volatility rate	40.30%
Dividend yield	1.20%

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Common Stock Plans (Stock Options, Textual) (Details) - Stock options - Stock Incentive Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 0.4	$ 2.9	$ 3.4
Tax benefit related to stock-based compensation	0.1	$ 1.1	$ 1.3
Intrinsic value of stock options exercised during period	0.7
Cash received from exercise of stock options	1.0
Intrinsic value for outstanding options	0.3
Intrinsic value for exercisable options	0.3
Fair value of vested options	3.7
Unrecognized compensation cost	$ 0.1

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Common Stock Plans (Stock Options, Range of Exercise Prices) (Details)	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Weighted average remaining contractual life of exercisable stock options	5 years 5 months 5 days
Stock options | Stock Incentive Plan
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices, Lower Range Limit	$ 29.79
Number of outstanding options, Range of Exercise Prices, Upper Range Limit	$ 80.48
Shares | shares	733,391
Weighted Average Remaining Contractual Life	5 years 9 months 5 days
Stock options | Stock Incentive Plan | $46.45
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices	$ 46.45
Shares | shares	19,990
Weighted Average Remaining Contractual Life	1 year
Stock options | Stock Incentive Plan | $60.56
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices	$ 60.56
Shares | shares	48,560
Weighted Average Remaining Contractual Life	2 years
Stock options | Stock Incentive Plan | $29.79
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices	$ 29.79
Shares | shares	24,291
Weighted Average Remaining Contractual Life	3 years
Stock options | Stock Incentive Plan | $46.69
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices	$ 46.69
Shares | shares	26,481
Weighted Average Remaining Contractual Life	4 years
Stock options | Stock Incentive Plan | $54.99
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices	$ 54.99
Shares | shares	104,841
Weighted Average Remaining Contractual Life	5 years
Stock options | Stock Incentive Plan | $54.11
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices	$ 54.11
Shares | shares	271,164
Weighted Average Remaining Contractual Life	6 years
Stock options | Stock Incentive Plan | $48.36
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices	$ 48.36
Shares | shares	124,071
Weighted Average Remaining Contractual Life	7 years
Stock options | Stock Incentive Plan | $80.48
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices	$ 80.48
Shares | shares	3,686
Weighted Average Remaining Contractual Life	7 years 9 months 15 days
Stock options | Stock Incentive Plan | $72.39
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices	$ 72.39
Shares | shares	107,868
Weighted Average Remaining Contractual Life	8 years
Stock options | Stock Incentive Plan | $79.63
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of Exercise Prices	$ 79.63
Shares | shares	2,439
Weighted Average Remaining Contractual Life	8 years

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Common Stock Plans (2004 Stock Appreciation Rights Plan) (Details) - Stock Appreciation Rights - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining requisite service period (in years)	3 years
Shares
Outstanding, Beginning of Period, Shares	275,150	377,377	653,030
Granted, Shares		62,749	88,000
Exercised/forfeited, Shares	(10,283)	(164,976)	(363,653)
Outstanding, End of Period, Shares	264,867	275,150	377,377
Weighted Average Exercise Price
Outstanding, Beginning of Period, Weighted Average Exercise Price (in dollars per share)	$ 52.96	$ 49.48	$ 44.14
Granted, Weighted Average Exercise Price (in dollars per share)		72.39	48.36
Exercised/forfeited, Weighted Average Exercise Price (in dollars per share)	55.18	52.37	39.66
Outstanding, End of Period, Weighted Average Exercise Price (in dollars per share)	$ 52.88	$ 52.96	$ 49.48
Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Share-based compensation expense (income)	$ 3.2	$ 0.4	$ 9.9
Intrinsic value of stock options exercised during period	0.1
Settlement of stock appreciation rights	$ 0.1
1/22/2014 | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	522
Fair market value of stock option at grant (in dollars per share)	$ 1.67
Expected life of award	2 years 1 month 17 days
Risk-free interest rate	1.11%
Annualized volatility rate	33.40%
Dividend yield	0.20%
1/22/2014 | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	62,227
Fair market value of stock option at grant (in dollars per share)	$ 5.11
Expected life of award	4 years 6 months 22 days
Risk-free interest rate	1.67%
Annualized volatility rate	33.40%
Dividend yield	0.20%
1/24/2013 | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	83,654
Fair market value of stock option at grant (in dollars per share)	$ 8.30
Expected life of award	3 years 6 months 26 days
Risk-free interest rate	1.43%
Annualized volatility rate	33.40%
Dividend yield	0.20%
1/26/2011 | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	7,785
Fair market value of stock option at grant (in dollars per share)	$ 2.74
Expected life of award	1 year 6 months
Risk-free interest rate	0.80%
Annualized volatility rate	33.40%
Dividend yield	0.20%
1/26/2011 | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	182,199
Fair market value of stock option at grant (in dollars per share)	$ 4.80
Expected life of award	2 years 6 months 10 days
Risk-free interest rate	1.23%
Annualized volatility rate	33.40%
Dividend yield	0.20%
1/27/2010 | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	171,749
Fair market value of stock option at grant (in dollars per share)	$ 5.95
Expected life of award	2 years 15 days
Risk-free interest rate	1.08%
Annualized volatility rate	33.40%
Dividend yield	0.20%
1/28/2009 | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	305,257
Fair market value of stock option at grant (in dollars per share)	$ 13.18
Expected life of award	1 year 6 months 15 days
Risk-free interest rate	0.82%
Annualized volatility rate	33.40%
Dividend yield	0.20%
2/4/2008 | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	67,093
Fair market value of stock option at grant (in dollars per share)	$ 0.81
Expected life of award	12 months 18 days
Risk-free interest rate	0.65%
Annualized volatility rate	33.40%
Dividend yield	0.20%
2/1/2007 | 2004 Stock Appreciation Rights Plan | Originally reported
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	85,906
Fair market value of stock option at grant (in dollars per share)	$ 2.16
Expected life of award	6 months 16 days
Risk-free interest rate	0.54%
Annualized volatility rate	33.40%
Dividend yield	0.20%
San Juan Basin properties | 1/24/2013 | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	768
Fair market value of stock option at grant (in dollars per share)	$ 5.64
Expected life of award	2 years 1 month 17 days
Risk-free interest rate	1.11%
Annualized volatility rate	33.40%
Dividend yield	0.20%
Black Warrior Basin | 1/24/2013 | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	3,578
Fair market value of stock option at grant (in dollars per share)	$ 4.24
Expected life of award	1 year 6 months
Risk-free interest rate	0.80%
Annualized volatility rate	33.40%
Dividend yield	0.20%

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Common Stock Plans (Other Plans) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock Equivalent Units | Petrotech Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding, Beginning of Period, Shares	213,870	173,292	141,243
Granted		76,084
Paid, Shares	(78,430)	(4,431)	(36,792)
Forfeited	(22,158)	(31,075)	(26,529)
Outstanding, End of Period, Shares	243,746	213,870	173,292
Share-based compensation expense	$ 3.0	$ 4.5	$ 6.2
Stock Equivalent Units | Petrotech Incentive Plan | Three years vesting period
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted	128,519		92,418
Share-based compensation, vesting period	3 years		3 years
Stock Equivalent Units | Petrotech Incentive Plan | Two years vesting period
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted	297
Share-based compensation, vesting period	2 years
Stock Equivalent Units | Petrotech Incentive Plan | 17-month vesting period
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted			2,952
Share-based compensation, vesting period			17 months
Stock Equivalent Units | Petrotech Incentive Plan | 16-month vesting period
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted	1,648
Share-based compensation, vesting period	16 months
Management | 1997 Deferred Compensation Plan
Deferred Compensation Arrangements [Abstract]
Deferred compensation, reserved for issuance	576,850
Director | Stock options | 1992 Energen Corporation Directors Stock Plan
Deferred Compensation Arrangements [Abstract]
Granted, Shares	11,550	10,360	13,500
Number of shares remaining for issuance	116,374

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Common Stock Plans (Stock Repurchase Program) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 22, 2014
Equity, Class of Treasury Stock [Line Items]
Purchase and retirement of shares, value		$ 14,913,000
Common Stock
Equity, Class of Treasury Stock [Line Items]
Stock repurchase program, authorized amount				$ 3,600,000
Stock repurchase program, remaining authorized repurchase amount	$ 3,373,161
Shares acquired in connection with stock compensation plans	73,126	32,768	14,766
Common Stock
Equity, Class of Treasury Stock [Line Items]
Purchase and retirement of shares, shares	0	226,839	0
Purchase and retirement of shares, value		$ 2,000

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Derivative Commodity Instruments (Gain (Loss) on Derivative Instruments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Gain (loss) on derivative instruments, net	$ 115,293	$ 335,019	$ (50,024)
Commodity contracts
Derivative [Line Items]
Open non-cash mark-to-market gains (losses) on derivative instruments	(281,752)	315,445	(47,832)
Closed gains (losses) on derivative instruments	397,045	19,574	(2,192)
Gain (loss) on derivative instruments, net	$ 115,293	$ 335,019	$ (50,024)

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Derivative Commodity Instruments (Offsetting of Derivative Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets
Gross Amounts Recognized at Fair Value	$ 72,563	$ 339,977
Gross Amounts Offset in the Balance Sheets	(15,600)	(17,640)
Net Amount Presented in the Balance Sheets	56,963	322,337
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Fair Value Presented in the Balance Sheets	56,963	322,337
Liabilities
Gross Amounts Recognized at Fair Value	16,059	18,628
Gross Amounts Offset in the Balance Sheets	(15,600)	(17,640)
Net Amount Presented in the Balance Sheets	459	988
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Fair Value Presented in the Balance Sheets	459	988
Total derivatives	$ 56,504	$ 321,349

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Derivative Commodity Instruments (Cash Flow Hedging Relationship in Financial Statements) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $23 and ($6,660)	$ 37	$ (10,866)
Gain (loss) recognized in other comprehensive income on derivatives	23	(6,660)
Gain (Loss) on Derivative Instruments, Net
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain reclassified from accumulated other comprehensive income into income (effective portion)	21,612	34,293
Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	$ 0	$ 835

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Derivative Commodity Instruments (Effect of Open and Closed Derivative Commodity Instruments Not Designated as Hedging Instruments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Gain (Loss) on Derivative Instruments, Net
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in income on derivatives	$ 115,293	$ 313,408	$ (73,980)

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Derivative Commodity Instruments (Reclassification) (Details) - Crude Oil - Production Period, Year One	12 Months Ended
	Dec. 31, 2015 MBbls $ / bbl
NYMEX Swaps
Derivatives, Fair Value [Line Items]
Total Hedged Volumes | MBbls	1,086
Average Contract Price | $ / bbl	63.80
WTI/WTI Basis Swaps
Derivatives, Fair Value [Line Items]
Total Hedged Volumes | MBbls	7,524	[1]
Average Contract Price | $ / bbl	(1.92)	[1]
WTS/WTI Basis Swaps
Derivatives, Fair Value [Line Items]
Total Hedged Volumes | MBbls	2,117	[2]
Average Contract Price | $ / bbl	(1.63)	[2]

[1] WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

[2] WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

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Derivative Commodity Instruments (Additional Information) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) counterparty	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Derivative [Line Items]
Number of Active Counterparties with Whom Company Holds Net Gain Positions | counterparty	11
Counterparties with whom company holds net loss positions | counterparty	1
Gain on fair value of derivatives	$ 115,293	$ 335,019	$ (50,024)
Commodity contracts
Derivative [Line Items]
Gain on fair value of derivatives	115,293	$ 335,019	$ (50,024)
Morgan Stanley Capital Group | Commodity contracts
Derivative [Line Items]
Gain on fair value of derivatives	18,100
BP Corporation North America, Inc. | Commodity contracts
Derivative [Line Items]
Gain on fair value of derivatives	$ 10,700

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Fair Value Measurements (Derivative Instruments, Fair Value) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets
Derivative instruments	$ 56,963	$ 322,337
Liabilities
Derivative instruments	(459)	(988)
Net derivative asset	56,504	321,349
Level 2
Assets
Derivative instruments	69,864	294,865
Liabilities
Derivative instruments	2,699	2,048
Net derivative asset	72,563	296,913
Level 3
Assets
Derivative instruments	(12,901)	27,472
Liabilities
Derivative instruments	(3,158)	(3,036)
Net derivative asset	$ (16,059)	$ 24,436

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Fair Value Measurements (Derivative Instruments Change in Fair Value of Level 3) (Details) - Derivative Commodity Instruments - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period		$ 24,436	$ 18,289	$ 89,019
Realized gains		13,145	22,208	55,210
Unrealized gains (losses) relating to instruments held at the reporting date	[1]	(40,495)	2,981	(71,367)
Settlements during period		(13,145)	(19,042)	(54,573)
Balance at end of period		(16,059)	24,436	18,289
Mark-to-market gains (losses)		$ (16,100)	$ 20,200	$ (7,600)

[1] Includes $16.1 million in mark-to-market losses, $20.2 million in mark-to-market gains and $7.6 million in mark-to-market losses for the years ended December 31, 2015, 2014 and 2013, respectively.

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Fair Value Measurements (Level 3 Fair Value Measurements of Derivative Commodity Instruments) (Details) - Crude Oil - 2015 - Level 3 $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) $ / bbl
WTI/WTI Basis Swaps
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value (in USD) | $	$ (13,181)
WTS/WTI Basis Swaps
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value (in USD) | $	$ (2,878)
Discounted Cash Flow Valuation Technique | Minimum | WTI/WTI Basis Swaps
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	0.07
Discounted Cash Flow Valuation Technique | Minimum | WTS/WTI Basis Swaps
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	0.19
Discounted Cash Flow Valuation Technique | Maximum | WTI/WTI Basis Swaps
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	0.28
Discounted Cash Flow Valuation Technique | Maximum | WTS/WTI Basis Swaps
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	0.31

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Fair Value Measurements (Additional Information) (Details)	12 Months Ended
	Dec. 31, 2015 USD ($) customer	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Concentration Risk [Line Items]
Sale of short-term investments	$ 919,000,000	$ 473,000,000	$ 310,000,000
Impact of ten percent change in commodity prices	$ 100,000
Number of large customers | customer	2
Plains Marketing | Accounts receivable
Concentration Risk [Line Items]
Concentration of credit risk (less than 9 percent)	47.00%
Plains Marketing | Total operating revenues
Concentration Risk [Line Items]
Concentration of credit risk (less than 9 percent)	33.00%
Shell Trading | Accounts receivable
Concentration Risk [Line Items]
Concentration of credit risk (less than 9 percent)	21.00%
Remaining Customer Concentration Risk | Accounts receivable
Concentration Risk [Line Items]
Concentration of credit risk (less than 9 percent)	9.00%
Reported Value Measurement
Concentration Risk [Line Items]
Fair value of long-term debt	$ 776,500,000	1,039,000,000
Estimate of Fair Value Measurement
Concentration Risk [Line Items]
Fair value of long-term debt	690,100,000	993,700,000
Swap [Member] | Credit facility
Concentration Risk [Line Items]
Long-term debt	$ 66,667,000
Interest rate	1.0425%
Interest rate cash flow hedge liability at fair value	$ 200,000	$ 800,000

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Exploratory Costs (Capitalized Exploratory Well Costs) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) well	Dec. 31, 2014 USD ($) well	Dec. 31, 2013 USD ($)
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized exploratory well costs at beginning of period	$ 119,439	$ 57,600	$ 79,791
Additions pending determination of proved reserves	634,908	946,751	421,599
Reclassifications due to determination of proved reserves	(650,759)	(882,254)	(442,909)
Exploratory well costs charged to expense	0	(2,658)	(881)
Capitalized exploratory well costs at end of period	103,588	119,439	$ 57,600
Capitalized Exploratory Well Costs [Abstract]
Exploratory wells in progress (drilling rig not released)	1,760	18,781
Capitalized exploratory well costs for a period of one year or less	101,828	100,658
Total capitalized exploratory well costs	$ 103,588	$ 119,439
Number of wells capitalized for a period greater than one year | well	0	0
Wells in process of drilling | well	40

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Reconciliation of Earnings Per Share (Reconciliation) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income (Loss)	$ (590,806)	$ (227,904)	$ (111,601)	$ (15,420)	$ 65,418	$ 457,251	$ (7,953)	$ 53,316	$ (945,731)	$ 568,032	$ 204,554
Basic Shares Outstanding (in shares)									76,078,371	72,896,579	72,317,865
Basic earnings per average common share (in dollars per share)	$ (7.50)	$ (2.89)	$ (1.52)	$ (0.21)	$ 0.90	$ 6.26	$ (0.11)	$ 0.73	$ (12.43)	$ 7.79	$ 2.83
Effect of dilutive securities
Net Income (Loss), Diluted EPS	$ (590,806)	$ (227,904)	$ (111,601)	$ (15,420)	$ 65,418	$ 457,251	$ (7,953)	$ 53,316	$ (945,731)	$ 568,032	$ 204,554
Diluted Shares Outstanding (in shares)									76,078,371	73,274,631	72,470,622
Diluted earnings per average common share (in dollars per share)	$ (7.50)	$ (2.89)	$ (1.52)	$ (0.21)	$ 0.89	$ 6.22	$ (0.11)	$ 0.73	$ (12.43)	$ 7.75	$ 2.82
Stock options
Effect of dilutive securities
Effect of dilutive securities									0	216,000	112,000
Non-vested restricted stock
Effect of dilutive securities
Effect of dilutive securities									0	58,000	20,000
Performance share awards
Effect of dilutive securities
Effect of dilutive securities									0	104,000	21,000

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Reconciliation of Earnings Per Share (Antidilutive Securities) (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of diluted EPS (in options or shares)	355,915
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of diluted EPS (in options or shares)	114,000	114,000	134,000
Non-vested restricted stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of diluted EPS (in options or shares)	0	3,000	7,000
Performance share awards
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of diluted EPS (in options or shares)	0	2,000	4,000

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Equity Offering (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Proceeds from issuance of common stock net of offering expenses	$ 398,600	$ 399,600	$ 23,053	$ 17,780
Common Stock
Class of Stock [Line Items]
Shares issued	5,700,000

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Commitments and Contingencies (Additional Information) (Details) gal in Thousands, a in Thousands		12 Months Ended
	Nov. 04, 2015 USD ($) a	Dec. 31, 2008 gal	Dec. 31, 2015 USD ($) MMBoe
Unfavorable Regulatory Action
Site Contingency [Line Items]
Order for payment of additional royalties			$ 129,700
Preliminary estimates of order maximum liabilities for additional royalties			$ 24,000,000
Sylacauga, Talladega County, Alabama
Site Contingency [Line Items]
Gallons of wastewater transported | gal		3
Crude Oil and Natural Gas
Site Contingency [Line Items]
Oil and gas delivery commitments, volume | MMBoe			5.8
Pending Litigation | Energen vs. Endeavor Energy Resources
Site Contingency [Line Items]
Number of acres with cloud on the title | a	10
Amount of counterclaim	$ 300,000,000

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Commitments and Contingencies (Lease Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Total lease payments	$ 23,700	$ 24,100	$ 25,000
Operating Leases, Future Minimum Payments Due [Abstract]
2016	2,537
2017	2,574
2018	2,537
2019	2,431
2020	0
2021 and thereafter	$ 0

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning	$ 94,060		$ 108,533		$ 118,023
Liabilities incurred	981		2,266		2,772
Liabilities settled	(686)		(1,543)		(5,525)
Accretion expense	7,108		7,859		8,192
Accretion expense of discontinued operations			251		1,197
Revision in estimated cash flows			692
Reclassification associated with held for sale properties	(11,473)	[1]	(23,747)	[2]	(14,929)	[3]
Balance of ARO, end	$ 89,990		$ 94,060		$ 108,533

[1] Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2015.

[2] Asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale in current liabilities on the balance sheet at December 31, 2014.

[3] Asset retirement obligation associated with North Louisiana/East Texas properties.

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Asset Impairment (Summary of Impairments) (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment			$ 1,292,308	$ 416,801	$ 13,906
Assets impairments from discontinued operations			0	1,936	29,794
Total asset impairments			1,292,308	418,737	43,700
Central Basin Platform
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment			484,848	0	0
Delaware Basin
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment	$ 90,600		607,303	90,594	0
Midland Basin
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment		$ 25,800	0	25,776	0
San Juan Basin properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment			133,055	230,315	0
Permian Basin Unproved Leasehold Properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment	$ 55,100		29,168	64,361	13,906
San Juan Basin unproved leasehold properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment			37,934	5,755	0
North Louisiana/East Texas oil and natural gas properties
Impaired Long-Lived Assets Held and Used [Line Items]
Assets impairments from discontinued operations			$ 0	$ 1,936	$ 29,794

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Asset Impairment (Additional Information) (Details) $ in Thousands	1 Months Ended	3 Months Ended							12 Months Ended
	Oct. 31, 2013 USD ($)	Dec. 31, 2015 USD ($) MMBoe MBbls MMcf	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) MMBoe MBbls MMcf	Sep. 30, 2014 USD ($)	Dec. 31, 2013 USD ($) MMBoe MBbls MMcf	Dec. 31, 2015 USD ($) MMBoe MBbls MMcf	Dec. 31, 2014 USD ($) MMBoe MBbls MMcf	Dec. 31, 2013 USD ($) MMBoe MBbls MMcf	Mar. 31, 2014 USD ($)
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment									$ 1,292,308	$ 416,801	$ 13,906
Price curve, term									5 years
Increase (decrease) in commodity price assumptions (percent)									3.00%
Proved developed reserves at end of period (BOE) | MMBoe		184.0				264.5		259.8	184.0	264.5	259.8
Assets impairments from discontinued operations									$ 0	$ 1,936	$ 29,794
Central Basin Platform
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment									484,848	0	0
San Juan Basin properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment									$ 133,055	$ 230,315	0
Proved developed reserves at end of period (BOE) | MMBoe		16.930				69.038			16.930	69.038
Cash received from sale of oil properties					$ 384,000
San Juan Basin properties | Discontinued Operations, Held-for-sale or Disposed of by Sale
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment						$ 88,100	$ 142,200
San Juan Proved and Unproved Properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment		$ 133,100
Permian Basin Unproved Leasehold Properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment						55,100			$ 29,168	$ 64,361	13,906
San Juan Basin unproved leasehold properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment									37,934	5,755	0
Midland Basin
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment							$ 25,800		0	25,776	0
Delaware Basin
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment						$ 90,600			607,303	90,594	0
North Louisiana/East Texas
Impaired Long-Lived Assets Held and Used [Line Items]
Sales price												$ 30,300
Assets impairments from discontinued operations									$ 0	$ 1,936	$ 29,794
Natural Gas
Impaired Long-Lived Assets Held and Used [Line Items]
Increase (decrease) in commodity price assumptions (percent)			(6.00%)	(12.00%)
Proved developed reserves at end of period (volume) | MMcf		236,112				589,074		623,305	236,112	589,074	623,305
Natural Gas | North Louisiana/East Texas
Impaired Long-Lived Assets Held and Used [Line Items]
Proved developed reserves at end of period (volume) | MMcf						23,000				23,000
Oil Reserves
Impaired Long-Lived Assets Held and Used [Line Items]
Increase (decrease) in commodity price assumptions (percent)			(12.00%)	(19.00%)
Proved developed reserves at end of period (volume) | MBbls		108,319				118,697		113,795	108,319	118,697	113,795
Oil Reserves | Permian Basin unproved leasehold properties
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment		$ 646,100	$ 390,200		$ 4,300				$ 1,092,200
Oil Reserves | Central Basin Platform
Impaired Long-Lived Assets Held and Used [Line Items]
Asset impairment				$ 51,500
Oil Reserves | North Louisiana/East Texas
Impaired Long-Lived Assets Held and Used [Line Items]
Proved developed reserves at end of period (volume) | MBbls						91				91
Alabama | Black Warrior Basin
Impaired Long-Lived Assets Held and Used [Line Items]
Cash received from sale of oil properties	$ 160,000
Gain on sale of oil and gas property								$ 35,000
Black Warrior Basin | Natural Gas
Impaired Long-Lived Assets Held and Used [Line Items]
Proved developed reserves at end of period (volume) | MMcf								97,000			97,000

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Acquisition and Disposition of Properties (Additional Information) (Details) a in Thousands, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Oct. 31, 2014 USD ($) a	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($) MMBoe	Dec. 31, 2014 USD ($) MMBoe	Dec. 31, 2013 USD ($) MMBoe	Feb. 16, 2016 MMBoe
Business Acquisition [Line Items]
Proved developed reserves at end of period (BOE) | MMBoe			184.0	264.5	259.8
Payments to acquire unproved leasehold properties			$ 85.7	$ 68.5	$ 26.8
San Juan Basin properties
Business Acquisition [Line Items]
Proved developed reserves at end of period (BOE) | MMBoe			16.930	69.038
Sale of assets		$ 395.0
Purchase price adjustments		11.0
Cash received from sale of oil properties		384.0
Transaction costs		2.8
Payments to acquire unproved leasehold properties	$ 22.8
Net acres | a	15
PUERTO RICO | San Juan Basin properties
Business Acquisition [Line Items]
Pre-tax gain on disposal		$ 27.0
Subsequent Event | Delaware Basin
Business Acquisition [Line Items]
Proved developed reserves at end of period (BOE) | MMBoe						25.200

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Discontinued Operations and Held for Sale Properties (Additional Information) (Details) $ in Thousands		1 Months Ended	3 Months Ended		12 Months Ended
	Sep. 02, 2014 USD ($)	Oct. 31, 2013 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2013 USD ($) MMBoe MBbls MMcf	Dec. 31, 2015 USD ($) MMBoe MBbls MMcf	Dec. 31, 2014 USD ($) MMBoe MBbls MMcf	Dec. 31, 2013 USD ($) MMBoe MBbls MMcf	Feb. 16, 2016 MMBoe	Mar. 31, 2014 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved developed reserves at end of period (BOE) | MMBoe				259.8	184.0	264.5	259.8
Gain on disposal of discontinued operations, net						$ 724,594	$ 5,605
Assets impairments from discontinued operations					$ 0	$ 1,936	$ 29,794
Natural Gas Reserves
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved developed reserves at end of period (volume) | MMcf				623,305	236,112	589,074	623,305
Oil Reserves
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved developed reserves at end of period (volume) | MBbls				113,795	108,319	118,697	113,795
Black Warrior Basin | Natural Gas Reserves
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved developed reserves at end of period (volume) | MMcf				97,000			97,000
Alabama Gas Corporation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration	$ 1,600,000
Debt assumed	267,000
Proceeds from sale	1,320,000
Gain on disposal of discontinued operations, net	$ 726,500
Black Warrior Basin | Alabama
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash received from sale of oil properties		$ 160,000
Gain on sale of oil and gas property				$ 35,000
North Louisiana/East Texas
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sales price									$ 30,300
Assets impairments from discontinued operations					$ 0	$ 1,936	$ 29,794
North Louisiana/East Texas | Natural Gas Reserves
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved developed reserves at end of period (volume) | MMcf						23,000
North Louisiana/East Texas | Oil Reserves
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved developed reserves at end of period (volume) | MBbls						91
San Juan Basin properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved developed reserves at end of period (BOE) | MMBoe					16.930	69.038
Cash received from sale of oil properties			$ 384,000
Subsequent Event | Delaware Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved developed reserves at end of period (BOE) | MMBoe								25.200

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Discontinued Operations and Held for Sale Properties (Balance Sheet) (Details) - San Juan Basin properties - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets of Disposal Group, Including Discontinued Operation [Abstract]
Inventories	$ 3,651	$ 0
Oil and natural gas properties	305,386	1,166,124
Less accumulated depreciation, depletion and amortization	(219,059)	(770,327)
Other property and equipment, net	3,761	0
Total assets held-for-sale	93,739	395,797
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]
Other long-term liabilities	(12,789)	(24,230)
Total liabilities held-for-sale	(12,789)	(24,230)
Total held-for-sale properties	$ 80,950	$ 371,567

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Discontinued Operations and Held for Sale Properties (Income Statement) (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
	Sep. 02, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Natural gas distribution revenues			$ 397,648	$ 533,338
Oil and natural gas revenues			5,199	60,191
Total revenues			402,847	593,529
Pretax income from discontinued operations			47,220	92,253
Income tax expense		$ 0	17,928	33,174
Income From Discontinued Operations		0	29,292	59,079
Gain on disposal of discontinued operations, net			724,594	5,605
Income tax expense		0	285,497	2,011
Gain on Disposal of Discontinued Operations, net		0	439,097	3,594
Income From Discontinued Operations		$ 0	$ 468,389	$ 62,673
Diluted earnings per average common share
Income from discontinued operations			$ 0.40	$ 0.81
Gain on disposal of discontinued operations, net			5.99	0.05
Total Income From Discontinued Operations		$ 0.00	6.39	0.86
Basic earnings per average common share
Income from discontinued operations			0.40	0.82
Gain on disposal of discontinued operations, net			6.02	0.05
Total Income From Discontinued Operations		$ 0.00	$ 6.42	$ 0.87
Alabama Gas Corporation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Alagasco net income			$ 40,646	$ 57,399
Depreciation, depletion and amortization			(408)	(598)
General and administrative			3,337	5,894
Interest expense			(17,306)	(13,815)
Other income			(347)	(1,342)
Income tax expense			5,567	3,728
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Gain on disposal of discontinued operations, net	$ 726,500
Income From Discontinued Operations			31,489	51,266
Parent Company
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Income From Discontinued Operations			$ (2,197)	$ 7,813

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Supplemental Cash Flow Information (Schedule of Supplemental Cash Flow Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]
Interest paid, net of amount capitalized	$ 40,747	$ 32,172	$ 38,255
Income taxes paid	8,114	219,505	22,781
Noncash investing activities:
Accrued development, exploration costs and other capital	79,206	207,461	93,623
Capitalized asset retirement obligations costs	981	2,958	2,772
Receivable from sale of Alabama Gas Corporation	0	8,247	0
Noncash financing activities:
Issuance of common stock for employee benefit plans	5,758	2,448	1,015
Treasury stock acquired in connection with tax withholdings	$ 4,722	$ 2,547	$ 977

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Accumulated Other Comprehensive Income (Loss) (Rollforward of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Amounts reclassified from accumulated other comprehensive income	$ (19,828)	$ (14,256)	$ (8,306)
Pension and Postretirement Plans
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance as of December 31, 2014	(22,870)
Other comprehensive income before reclassifications	3,305
Amounts reclassified from accumulated other comprehensive income	(19,828)
Change in accumulated other comprehensive income (loss)	23,133
Balance as of December 31, 2015	$ 263	$ (22,870)

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Accumulated Other Comprehensive Income (Loss) (Reclassifications of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Gains (losses) on cash flow hedges:
Income (Loss) From Continuing Operations Before Income Taxes										$ (1,480,736)	$ 140,371	$ 216,204
Income tax expense										535,005	(40,728)	(74,323)
Income (Loss) From Continuing Operations		$ (590,806)	$ (227,904)	$ (111,601)	$ (15,420)	$ 66,519	$ 20,631	$ (3,154)	$ 15,647	(945,731)	99,643	141,881
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax										(19,828)	(2,514)	12,324
Nonqualified Supplemental Retirement Plans
Pension and postretirement plans:
Settlement charges					$ 2,500	$ 1,800					400	600
Settlement charges expensed												200
Nonqualified Supplemental Retirement Plans | Alabama Gas Corporation
Pension and postretirement plans:
Settlement charges												400
Transition obligation
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax										0	(22)	(319)
Prior service cost
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax										0	(248)	(257)
Actuarial losses
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax										(30,504)	(21,932)	(12,357)
Actuarial losses on settlement charges
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	[1]									0	0	(421)
Pension and Postretirement Plans
Gains (losses) on cash flow hedges:
Income tax expense										10,676	7,771	4,674
Pension and postretirement plans:
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax										(30,504)	(22,202)	(13,354)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax										(19,828)	(14,431)	(8,680)
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedges
Gains (losses) on cash flow hedges:
Income (Loss) From Continuing Operations Before Income Taxes										0	19,331	33,961
Income tax expense										0	(7,414)	(12,957)
Income (Loss) From Continuing Operations										0	11,917	21,004
Reclassification out of Accumulated Other Comprehensive Income | Commodity contracts | Cash Flow Hedges
Gains (losses) on cash flow hedges:
Commodity contracts										0	21,611	35,684
Reclassification out of Accumulated Other Comprehensive Income | Interest rate swap | Cash Flow Hedges
Gains (losses) on cash flow hedges:
Interest rate swap										$ 0	$ (2,280)	$ (1,723)

[1] During the year ended December 31, 2013, Energen incurred settlement charges of $0.6 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.2 million was recognized in actuarial losses above and $0.4 million was recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

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Recently Issued Accounting Standards Recently Issued Accounting Standards (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Deferred tax liability, noncurrent	$ 552,369	$ 1,000,486
New Accounting Pronouncement, Early Adoption, Effect
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Amount of reclassified current deferred tax asset	(14,500)
Deferred tax liability, noncurrent	$ 14,500

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Summarized Quarterly Financial Data (Unaudited) (Quarterly Operating Results) (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Selected Quarterly Financial Information [Abstract]
Revenues		$ 192,799	$ 295,571	$ 168,326	$ 221,858					$ 878,554	$ 1,679,213	$ 1,206,293
Discontinued operations											402,847	593,529
Reclassification of loss on sale of assets and other										(26,570)	2,642	981
Operating income (loss)		(915,550)	(348,214)	(161,678)	(12,409)					(1,437,851)	176,961	252,137
Income (loss) from continuing operations		(590,806)	(227,904)	(111,601)	(15,420)	$ 66,519	$ 20,631	$ (3,154)	$ 15,647	(945,731)	99,643	141,881
Net income (loss)		$ (590,806)	$ (227,904)	$ (111,601)	$ (15,420)	$ 65,418	$ 457,251	$ (7,953)	$ 53,316	$ (945,731)	$ 568,032	$ 204,554
Diluted earnings per average common share
Continuing operations (in dollars per share)		$ (7.50)	$ (2.89)	$ (1.52)	$ (0.21)	$ 0.91	$ 0.28	$ (0.04)	$ 0.21	$ (12.43)	$ 1.36	$ 1.96
Net income (loss) (in dollars per share)		(7.50)	(2.89)	(1.52)	(0.21)	0.89	6.22	(0.11)	0.73	(12.43)	7.75	2.82
Basic earnings per average common share
Continuing operations (in dollars per share)		(7.50)	(2.89)	(1.52)	(0.21)	0.91	0.28	(0.04)	0.22	(12.43)	1.37	1.96
Net income (loss) (in dollars per share)		$ (7.50)	$ (2.89)	$ (1.52)	$ (0.21)	$ 0.90	$ 6.26	$ (0.11)	$ 0.73	$ (12.43)	$ 7.79	$ 2.83
Originally reported
Selected Quarterly Financial Information [Abstract]
Revenues						$ 611,435	$ 497,761	$ 270,097	$ 561,178
Operating income (loss)						94,223	48,171	3,107	104,599
Adjustment
Selected Quarterly Financial Information [Abstract]
Revenues						612,268	498,508	271,006	297,431
Discontinued operations	[1]					0	0	0	(263,900)
Reclassification of loss on sale of assets and other						833	747	909	153
Operating income (loss)						94,223	48,171	3,107	31,460
Discontinued operations	[1]					$ 0	$ 0	$ 0	$ (73,139)

[1] As discussed in Note 16, Discontinued Operations and Held for Sale Properties, during the third quarter of 2014, Energen completed the transaction to sell Alagasco to Laclede. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations.

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Oil and Natural Gas Operations (Unaudited) (Capitalized Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Proved	$ 7,911,554	$ 8,069,638
Unproved	150,674	142,340
Total capitalized costs	8,062,228	8,211,978
Accumulated depreciation, depletion and amortization	3,673,569	2,663,434
Capitalized costs, net	$ 4,388,659	$ 5,548,544

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Oil and Natural Gas Operations (Unaudited) (Costs Incurred) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property acquisition:
Proved	$ 1,866	$ 2,582	$ 4,661
Unproved	85,690	68,514	26,820
Exploration	649,764	972,164	435,636
Development	372,177	408,949	655,353
Total costs incurred	$ 1,109,497	$ 1,452,209	$ 1,122,470

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Oil and Natural Gas Operations (Unaudited) (Results of Operations) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reserve Quantities [Line Items]
Gross revenues	[1]	$ 878,554	$ 1,679,213	$ 1,206,293
Production (lifting costs)		285,760	376,495	351,541
Exploration expense		14,877	28,090	14,036
Depreciation, depletion and amortization including asset impairments		1,880,190	960,539	463,606
Accretion expense		7,108	7,608	6,995
Income tax expense (benefit)		(469,362)	99,469	128,773
Results of operations from producing activities		(840,019)	207,012	241,342
Commodity contracts
Reserve Quantities [Line Items]
Open non-cash mark-to-market gains (losses) on derivative instruments		$ (281,752)	$ 315,445	$ (47,832)

[1] The years ended December 31, 2015, 2014 and 2013 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $281.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million and a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, respectively.

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Oil and Natural Gas Operations (Unaudited) (Oil and Gas Operations) (Details)	12 Months Ended
	Dec. 31, 2015 MMBoe MBbls MMcf	Dec. 31, 2014 MMBoe MBbls MMcf	Dec. 31, 2013 MMBoe MBbls MMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period, total | MMBoe	372.7	347.8	346.4
Revisions of previous estimates, total | MMBoe	(58.9)	(75.7)	4.6
Purchases, total | MMBoe	0.0	0.1	0.2
Extensions and discoveries, total | MMBoe	132.6	130.0	36.8
Production, total | MMBoe	(24.0)	(25.8)	(25.4)
Sales, total | MMBoe	(67.7)	(3.7)	(14.8)
Proved reserves at end of period, total | MMBoe	354.7	372.7	347.8
Proved developed reserves at end of period (BOE) | MMBoe	184.0	264.5	259.8
Proved undeveloped reserves at end of period (BOE) | MMBoe	170.7	108.2	88.0
Oil Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period	181,227	164,870	155,348
Revisions of previous estimates	(39,537)	(48,548)	(680)
Purchases	2	88	142
Extensions and discoveries	83,319	76,722	20,517
Production	(14,023)	(11,818)	(10,378)
Sales	(297)	(87)	(79)
Proved reserves at end of period	210,691	181,227	164,870
Proved developed reserves at end of period (volume)	108,319	118,697	113,795
Proved undeveloped reserves at end of period (volume)	102,372	62,530	51,075
Natural Gas Liquids Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period	73,463	63,011	56,155
Revisions of previous estimates	(11,979)	(15,165)	2,211
Purchases	1	26	56
Extensions and discoveries	25,530	29,695	7,823
Production	(4,065)	(4,104)	(3,233)
Sales	(11,237)	0	(1)
Proved reserves at end of period	71,713	73,463	63,011
Proved developed reserves at end of period (volume)	36,374	47,621	42,087
Proved undeveloped reserves at end of period (volume)	35,339	25,842	20,924
Natural Gas Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period | MMcf	707,926	719,725	809,128
Revisions of previous estimates | MMcf	(44,176)	(71,806)	18,465
Purchases | MMcf	2	116	282
Extensions and discoveries | MMcf	143,022	141,209	50,568
Production | MMcf	(35,604)	(59,562)	(70,506)
Sales | MMcf	(337,266)	(21,756)	(88,212)
Proved reserves at end of period | MMcf	433,904	707,926	719,725
Proved developed reserves at end of period (volume) | MMcf	236,112	589,074	623,305
Proved undeveloped reserves at end of period (volume) | MMcf	197,792	118,852	96,420

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Oil and Natural Gas Operations (Unaudited) (Oil and Gas Operations, Activities) (Details)	12 Months Ended
	Dec. 31, 2015 MMBoe	Dec. 31, 2014 MMBoe well_location pay_add	Dec. 31, 2013 MMBoe well_location pay_add
Reserve Quantities [Line Items]
Reserves included in engineer estimates, percent	99.00%
Revisions of previous estimates	(58.9)	(75.7)	4.6
Purchases	0.0	0.1	0.2
Extensions and discoveries	132.6	130.0	36.8
Percentage of undeveloped portion of proved reserves	78.00%	70.00%	45.00%
Percentage of developed portion of proved reserves	22.00%	30.00%	55.00%
Sales	67.7	3.7	14.8
Extension Drilling
Reserve Quantities [Line Items]
Extensions and discoveries	3.1	89.6	21.6
Exploratory Drilling
Reserve Quantities [Line Items]
Extensions and discoveries	129.5	40.4	15.2
Price Related Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates	(38.0)	3.9	7
Expected to Be Drilled Beyond Five Years
Reserve Quantities [Line Items]
Revisions of previous estimates	(8.2)
No Longer Expected to be Drilled
Reserve Quantities [Line Items]
Revisions of previous estimates			(5.3)
No Longer Expected to Be Drilled Beyond Five Years
Reserve Quantities [Line Items]
Revisions of previous estimates		(53.4)	(4.6)
San Juan Basin properties
Reserve Quantities [Line Items]
Revisions of previous estimates		1.6	2.2
Extensions and discoveries		1.1	2.3
Number of well locations | well_location		16
Pay-add locations | pay_add		10	30
San Juan Basin properties | Price Related Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates		4.4	5.9
San Juan Basin properties | Higher Operating Costs
Reserve Quantities [Line Items]
Revisions of previous estimates		(1.5)
San Juan Basin properties | Expected to Be Drilled Beyond Five Years
Reserve Quantities [Line Items]
Revisions of previous estimates			(4.6)
Permian Basin unproved leasehold properties
Reserve Quantities [Line Items]
Revisions of previous estimates	(5.5)	(77.3)	1.2
Extensions and discoveries		128.6	34.4
Number of well locations | well_location		361	262
Permian Basin unproved leasehold properties | Price Related Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates			0.4
Permian Basin unproved leasehold properties | Higher Operating Costs
Reserve Quantities [Line Items]
Revisions of previous estimates		(5.4)
Permian Basin unproved leasehold properties | Interference Caused by Welbore Placement Geometry [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	(5.0)
Permian Basin unproved leasehold properties | Reclassifying as Unproved
Reserve Quantities [Line Items]
Revisions of previous estimates		(53.4)
Permian Basin unproved leasehold properties | Well Performance Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates		(13.3)
Permian Basin unproved leasehold properties | No Longer Expected to be Drilled
Reserve Quantities [Line Items]
Revisions of previous estimates			(0.7)
Permian Basin unproved leasehold properties | Change in Year-End Pricing Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates		(0.5)
North Louisiana/East Texas oil and natural gas properties
Reserve Quantities [Line Items]
Sales		3.7
Black Warrior Basin
Reserve Quantities [Line Items]
Sales			14.8

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Oil and Natural Gas Operations (Unaudited) (Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future gross revenues					$ 11,714,729	$ 20,971,672	$ 19,509,305
Future production costs					4,353,974	7,532,273	6,136,709
Future development costs					1,961,661	1,784,738	1,896,602
Future income tax expense					1,065,887	3,440,582	3,209,697
Future net cash flows					4,333,207	8,214,079	8,266,297
Discount at 10% per annum					2,299,859	3,994,423	4,248,456
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves		$ 4,219,656	$ 4,017,841	$ 3,699,319	$ 2,033,348	$ 4,219,656	$ 4,017,841
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at beginning of year		4,219,656	4,017,841	3,699,319
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs		(2,861,591)	(1,147,028)	566,838
Net changes due to revisions in quantity estimates		(404,708)	(1,285,394)	(81,762)
Development costs incurred, previously estimated		350,560	337,198	299,432
Accretion of discount		421,966	401,784	369,932
Changes in timing and other	[1]	(903,975)	987,652	(179,502)
Total revisions		(3,397,748)	(705,788)	974,938
New field discoveries and extensions, net of future production and development costs		776,315	2,321,028	376,326
Sales of oil and gas produced, net of production costs		(514,380)	(1,054,553)	(1,014,593)
Purchases		8	4,241	4,690
Sales		(372,039)	(21,092)	(24,876)
Net change in income taxes		1,321,536	(342,021)	2,037
Net change in standardized measure of discounted future net cash flows		(2,186,308)	201,815	318,522
Balance at end of year		$ 2,033,348	$ 4,219,656	$ 4,017,841

[1] Amount represents changes in production timing and other. In 2015, the production timing is significantly affected by changes related to the delay of the drilling program. For 2014, the production timing is significantly affected by changes related to the acceleration of the horizontal drilling program and the delay of the vertical drilling program.