ENERGEN CORP (Form: 10-K, Received: 03/02/2015 13:59:32)

Percentage Change in Proved Oil & Natural Gas Reserves From Reported Reserves

as of December 31, 2014

(dollars in thousands)

Estimated increase in DD&A expense for the

year ended December 31, 2015, net of tax

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, 2014


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 and 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 Exchange Act). YES o NO x

Aggregate market value of the voting stock held by non-affiliates of the registrant as of June 30, 2014: $6,440,598,008

Number of shares outstanding of the registrant’s common stock as of February 16, 2015: 72,991,974 shares

DOCUMENTS INCORPORATED BY REFERENCE

Energen Corporation Proxy Statement to be filed on or about March 18, 2015 (Part III, Item 10-14)



	ENERGEN CORPORATION 2014 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	12
Item 1B.	Unresolved Staff Comments	18
Item 2.	Properties	19
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	22

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
	Purchases of Equity Securities	23
Item 6.	Selected Financial Data	25
Item 7.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	27
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	36
Item 8.	Financial Statements and Supplementary Data	38
Item 9.	Changes in and Disagreements with Accountants on Accounting and
	Financial Disclosure	86
Item 9A.	Controls and Procedures	86

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	87
Item 11.	Executive Compensation	87
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	87
Item 13.	Certain Relationships and Related Transactions, and Director Independence	87
Item 14.	Principal Accountant Fees and Services	87

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	87
Signatures		90



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.

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.

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.

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 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.

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.

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.

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.

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 timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, 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 and Colorado;


•	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 and other legal requirements;


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


•	financial strength of the purchasers of our oil 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;


•	the availability, capacity and cost of oilfield equipment, pipeline and transportation facilities, gathering and processing facilities, supplies and services;


•	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;


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


•	the costs and effects of litigation; and


•	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.

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 and natural gas liquids-rich properties and natural gas in the Permian Basin in west Texas and the San Juan Basin in New Mexico and Colorado. Headquartered in Birmingham, Alabama, our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources).

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 15, 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 The Laclede Group.

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 2014, Energen’s proved reserves totaled 372.7 MMBOE. Substantially all of these proved reserves are located in the Permian Basin in west Texas and the San Juan Basin in New Mexico and Colorado. Approximately 71 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 14 years. Oil, natural gas liquids and natural gas represent approximately 49 percent, 20 percent and 31 percent, respectively, of Energen’s proved reserves.

Property Acquisitions and Dispositions: In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). 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. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. 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 February 2015, Energen entered into a purchase and sale agreement to sell the majority of its natural gas assets in the San Juan Basin in New Mexico and Colorado for approximately $395 million . This sale is expected to close March 31, 2015, and have an effective date of January 1, 2015. During the third and fourth quarters of 2014, non-cash impairment writedowns of $147.9 million pre-tax and $88.1 million pre-tax, 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. These non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement. At December 31, 2014, proved reserves associated with these San Juan Basin properties totaled 69,043 MBOE.

Growth Strategy: Energen is focused on increasing its oil, natural gas liquids and natural gas production and proved reserves largely through the drill bit. The Company engages in active development and/or exploratory programs in the Permian and San Juan basins and seeks to expand its footprint in its areas of existing operation primarily through tuck acquisitions of proved properties and unproved leasehold. Energen operated approximately 95 percent of its proved reserves at December 31, 2014.

Since the end of fiscal year 1995, Energen has invested approximately $1.9 billion to acquire proved and unproved reserves, $4.7 billion in related development and $2.8 billion in exploration. Energen’s capital spending plans for 2015 target a total investment of approximately $1.0 billion, the bulk of which will focus on drilling and development activities on its existing properties, with approximately 92 percent targeting the liquids-rich Permian Basin and the remainder primarily targeting the Mancos shale oil formation in the San Juan 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, 2014, Energen’s development and exploratory efforts have added 224 MMBOE of proved reserves from the drilling of 1,127 gross development, exploratory and service wells (including 3 sidetrack wells) and 251 well recompletions and pay-adds. In 2014, Energen’s successful development and exploratory wells and other activities added approximately 130 MMBOE of proved reserves; Energen drilled 346 gross development, exploratory and service wells (no sidetrack wells were drilled), performed some 48 well recompletions and pay-adds, and conducted other operational enhancements. Energen’s production from continuing operations totaled 25.7 MMBOE in 2014 and in 2015 is estimated to range from 21.4 MMBOE to 22.4 MMBOE, with a midpoint of 21.9 MMBOE, including approximately 18.4 MMBOE of estimated production from proved reserves owned at December 31, 2014. Energen’s 2015 production estimate excludes volumes from the San Juan Basin assets held for sale at December 31, 2014. Such assets produced an estimated 6.6 MMBOE in 2014.

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



Years ended December 31,	2014	2013	2012
Development:
Productive	80.2	169.5	239.9
Dry	—	—	—
Total	80.2	169.5	239.9
Exploratory:
Productive	109.4	89.1	74.1
Dry	1.0	0.9	1.1
Total	110.4	90.0	75.2

As of December 31, 2014, Energen was participating in the drilling of 3 gross (2.9 net) development and 20 gross (14.1 net) exploratory wells. In addition to the development wells drilled, Energen drilled 22.5, 9.8 and 47.8 net service wells during 2014, 2013 and 2012, respectively. As of December 31, 2014, Energen was participating in the drilling of 1 gross (1 net) service well.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2014, and developed and undeveloped acreage as of the latest practicable date prior to year end:



	Gross	Net
Oil wells	5,252	3,440
Gas wells	2,663	1,420
Developed acreage	677,503	500,744
Undeveloped acreage	217,579	157,224

There were 6 wells with multiple completions in 2014. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Texas, New Mexico and Colorado.

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 HollyFrontier Corporation (HollyFrontier), accounted for approximately 39 percent and 15 percent, respectively, of Energen’s accounts receivable for commodity sales as of December 31, 2014 . Energen’s other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2014 . During the year ended December 31, 2014 , Plains and HollyFrontier accounted for approximately 37 percent and 13 percent , respectively, of total revenues. All other oil and natural gas purchasers each accounted for less than 10 percent of total revenues for the year ended December 31, 2014 .

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 fractures in the target formation through which the natural gas 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.

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. We estimate that the cleanup, remediation and related costs will approximate $2.5 million of which $1.9 million has been incurred.

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 550 employees. Energen believes that its relations with employees are good.

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 additional risks and uncertainties we currently deem to be immaterial or risks that are currently not known or have yet to be identified by us. 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. In such a case, the trading price of our shares could decline; and shareholders could lose part or all of their investment.

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

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

We have more oil proved reserves than natural gas proved reserves, so oil prices are more likely to have an impact on our business than natural gas prices. Approximately 49 percent of our December 31, 2014 proved reserves are oil. 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:


•	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 oil and natural gas inventory levels;


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


•	worldwide 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.

Substantial reductions in oil, natural gas liquids and natural gas prices would reduce our revenue and cash flows and 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.

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.

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 and natural gas liquids.

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 2015 and future years.

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

At December 31, 2014, approximately 75 percent and 24 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 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 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 to refinance 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 and other 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. The borrowing base of our credit facility is subject to periodic redetermination and is based in part on oil and natural gas prices. A lowering of our borrowing base because of lower oil and natural gas prices or for other reasons could require us to repay indebtedness in excess of the borrowing base, or we might need to further secure the lenders with additional collateral.

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.

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 is receiving increasing attention from many parties including legislators and governmental agencies. Debate over whether the climate is changing, possible causes and other possible impacts has been ongoing for several years.

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 are considering 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 are increasing; and local land use restrictions, such as county and city ordinances, may 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 is experiencing severe drought conditions that have persisted for the last several years. Several local water districts may begin restricting the use of water subject to their jurisdiction for drilling and

hydraulic fracturing in order to protect the local water supply during the 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.

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 quantity of potential reserves 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 are exposed to counterparty credit risk as a result of our concentrated customer base.

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 affect our overall exposure to credit risk, either positively or negatively, 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.

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 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.

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.

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.

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 becoming more 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. Furthermore, some experts claim that cybersecurity attacks have become a weapon of war and espionage. 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

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 20, 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. In February 2015, Energen entered into a purchase and sale agreement to sell the majority of its natural gas assets in the San Juan Basin in New Mexico and Colorado.

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



	Year ended
	December 31, 2014	December 31, 2014	December 31, 2014
	Production Volumes (MBOE)	Proved Reserves (MBOE)	Proved Reserves-to-Production Ratio
Permian Basin	17,298	280,788	16.23 years
San Juan Basin*	8,327	90,871	10.91 years
Other	224	1,019	4.55 years
Total	25,849	372,678	14.42 years

* Certain San Juan Basin assets were classified as held-for-sale as of December 31, 2014.

The following table sets forth proved reserves by area as of December 31, 2014:



	Oil MBbl	NGL MBbl	Natural Gas MMcf	Total MBOE
Permian Basin	179,466	55,075	277,484	280,788
San Juan Basin*	1,475	18,384	426,071	90,871
Other	286	4	4,371	1,019
Total	181,227	73,463	707,926	372,678

* Certain San Juan Basin assets were classified as held-for-sale as of December 31, 2014.

See Note 20, Oil and Natural Gas Operations (Unaudited), in the Notes to Financial Statements for the changes to proved reserves during the years ended December 31, 2014, 2013 and 2012 of oil, natural gas liquids and natural gas.

The following table sets forth proved developed reserves by area as of December 31, 2014:



	Oil MBbl	NGL MBbl	Natural Gas MMcf	Total MBOE
Permian Basin	117,014	29,234	158,640	172,688
San Juan Basin*	1,475	18,384	426,071	90,871
Other	208	3	4,363	939
Total	118,697	47,621	589,074	264,498

* Certain San Juan Basin assets were classified as held-for-sale as of December 31, 2014.

The following table sets forth proved undeveloped reserves by area as of December 31, 2014:



	Oil MBbl	NGL MBbl	Natural Gas MMcf	Total MBOE
Permian Basin	62,452	25,841	118,844	108,100
Other	78	1	8	80
Total	62,530	25,842	118,852	108,180

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



Year ended December 31, 2014	Total MMBOE
Balance at beginning of period	88.0
Undeveloped reserves transferred to developed reserves	(11.9)
Revisions	(59.3)
Extensions and discoveries	91.3
Acquisitions	0.1
Balance at end of period	108.2

Proved undeveloped reserves transferred to proved developed reserves reflect capital expenditures of approximately $246 million during the year ended December 31, 2014 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. Revisions largely relate to a reduction in proved undeveloped reserves of 53.4 MMBOE associated with changes in our development plans and revisions from decreased well performance in the Permian Basin of approximately 13.3 MMBOE.

Estimated proved reserves as of December 31, 2014 are based upon studies for each of our properties prepared by Company engineers and audited by Ryder Scott Company, L.P. (Ryder Scott) and T. Scott Hickman and Associates, Inc. (T. Scott Hickman),

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 an employee of Ryder Scott since 1982 and also serves as chief technical advisor of unconventional reserves evaluation. A Petroleum Consultant at T. Scott Hickman 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 T. Scott Hickman since 1983. The 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 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 2014, 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
Colorado		14.73 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, 2014 , 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	5,234	3,418	213,458	88,756
San Juan Basin*	2,590	1,434	276,411	38,812
Other	91	8	10,875	29,656
Total	7,915	4,860	500,744	157,224

* Certain San Juan Basin assets were classified as held-for-sale as of December 31, 2014.

The following table sets forth expiration dates for gross and net undeveloped acreage at year end as of December 31, 2014 :



	Years ending December 31,
	2015		2016		2017		Thereafter
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian	50,461	37,945	22,862	20,864	24,468	22,963	14,017	6,983
San Juan/other*	18,749	13,738	13,699	4,969	12,518	6,322	60,805	43,440
Total	69,210	51,683	36,561	25,833	36,986	29,285	74,822	50,423

*Other includes acreage principally located in Alabama, Wyoming, Oklahoma, Arkansas, Kentucky, Louisiana, Montana and North Dakota, 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.

Energen has 46.4 MMBOE of proved undeveloped reserves on leased acreage which is not held by production and is expected to be developed after the primary term of the leases. Drilling associated with these reserves is expected to occur under the continuous development provisions of the leases. The amount represents approximately 43 percent of the 108.2 MMBOE total proved undeveloped reserves and approximately 12 percent of the 372.7 MMBOE total proved reserves at December 31, 2014.

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 10.8 Bcf (net) of natural gas through March 2016. We expect to fulfill delivery commitments through production of existing proved reserves.



	Natural Gas MMcf
San Juan Basin	10,835

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 11, Commitments and Contingencies, in the Notes to Financial Statements for further discussion with respect to legal proceedings.

ITEM 4. MINE SAFETY DISCLOSURES

None

EXECUTIVE OFFICERS OF THE REGISTRANT



Name	Age	Position (1)
James T. McManus, II	56	Chairman, Chief Executive Officer and President of Energen (2)
Charles W. Porter, Jr.	50	Vice President, Chief Financial Officer and Treasurer of Energen (3)
John S. Richardson	57	President and Chief Operating Officer of Energen Resources (4)
J. David Woodruff, Jr.	58	Vice President, General Counsel and Secretary of Energen (5)
David A. Godsey	60	Senior Vice President – Exploration and Geology of Energen Resources (6)
David J. Minor	63	Senior Vice President – Operations of Energen Resources (7)
D. Paul Sparks, Jr.	52	Senior Vice President – Resource Development and Technology of Energen Resources(8)
Russell E. Lynch, Jr.	41	Vice President and Controller of Energen (9)

Notes :

(1) All executive officers of Energen have been employed by Energen or a subsidiary for the past five years except for Mr. Godsey and Mr. Minor. 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. Minor was employed by the Company in December 2012 as Senior Vice President – Operations of Energen Resources. He owned and operated Firebird Energy LLC, an energy consulting firm, from 2009 to 2012. As owner of the consulting firm he served in various positions including Executive Director of Operations for Far East Energy Corporation and President and General Manager of Walter Black Warrior Basin LLC. He served from December 2006 to December 2008 as Senior Vice President of Technology for CDX Gas LLC.

(8) Mr. Sparks has been employed by the Company in various capacities since 1989. He was elected Senior Vice President – Operations of Energen Resources in January 2006. He was elected Senior Vice President – Resource Development and Technology of Energen Resources effective November 1, 2012.

(9) 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.

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, 2013	$52.13	$44.46	$52.01	$0.145
June 30, 2013	$56.65	$45.11	$52.26	$0.145
September 30, 2013	$77.50	$52.42	$76.39	$0.145
December 31, 2013	$89.92	$65.74	$70.75	$0.145
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

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On February 13, 2015, there were 4,043 holders of record of Energen common stock. We expect to pay annual cash dividends of $0.08 per share on Energen common stock in 2015. 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, 2014 - October 31, 2014	545	*	$	55.83	—	3,600,000
November 1, 2014 - November 30, 2014	6,279	*	67.60		—	3,600,000
	226,839	**	65.77		226,839	3,373,161
December 1, 2014 - December 31, 2014	981	*	56.35		—	3,373,161
Total	234,644		$	65.76	226,839	3,373,161

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

**Energen had 226,839 shares repurchased and retired pursuant to its 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, replacing and superseding its prior stock repurchase authorizations. 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.

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, 2009, in the Company and each of the indices. Total shareholder return includes reinvested dividends.



As of December 31,	2009		2010		2011		2012		2013		2014
S&P 500	$	100	$	115	$	117	$	136	$	180	$	205
Energen	$	100	$	104	$	109	$	100	$	158	$	143
S15OILP	$	100	$	114	$	105	$	107	$	138	$	120

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)	2014		2013		2012		2011		2010
INCOME STATEMENT
Total revenues	$	1,679,213	$	1,206,293	$	1,090,948	$	834,700	$	804,693
Income from continuing operations	$	99,643	$	141,881	$	204,621	$	174,686	$	184,049
Net income	$	568,032	$	204,554	$	253,562	$	259,624	$	290,807
Diluted earnings per average common share from continuing operations	$	1.36	$	1.96	$	2.83	$	2.42	$	2.55
Diluted earnings per average common share	$	7.75	$	2.82	$	3.51	$	3.59	$	4.04
BALANCE SHEET
Total property, plant and equipment, net	$	5,199,137	$	5,118,088	$	4,698,951	$	3,807,305	$	2,936,562
Total assets	$	6,138,258	$	6,622,212	$	6,175,890	$	5,237,416	$	4,363,560
Long-term debt	$	1,038,563	$	1,093,541	$	903,500	$	904,454	$	204,461
Total shareholders’ equity	$	3,414,604	$	2,858,019	$	2,676,690	$	2,432,163	$	2,154,043
COMMON STOCK DATA
Cash dividends paid per common share	$	0.47	$	0.58	$	0.56	$	0.54	$	0.52
Diluted average common shares outstanding (000)	73,275		72,471		72,316		72,332		72,051
Price range:
High	$	90.66	$	89.92	$	58.24	$	65.44	$	49.94
Low	$	53.78	$	44.46	$	40.13	$	37.22	$	40.25
Close	$	63.76	$	70.75	$	45.09	$	50.00	$	48.26

*We expect to pay annual cash dividends of $0.08 per share on Energen common stock in 2015.

SELECTED BUSINESS DATA



Years ended December 31, (dollars in thousands, except per unit data)	2014		2013			2012			2011			2010
Oil, natural gas liquids and natural gas sales from continuing operations
Oil	$	988,868	$	961,055		$	766,105		$	570,413		$	383,541
Natural gas liquids	110,918		91,407			81,313			101,818			68,216
Natural gas	244,408		203,855			159,377			210,813			214,426
Total	$	1,344,194	$	1,256,317		$	1,006,795		$	883,044		$	666,183
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	271,200	$	(43,261	)	$	58,786		$	(37,473	)	$	(3	)
Natural gas liquids	287		(652		)	479			(114		)	—
Natural gas	43,958		(3,919		)	(515		)	—			—
Total	$	315,445	$	(47,832	)	$	58,750		$	(37,587	)	$	(3	)
Closed gains (losses) on derivative instruments
Oil	$	4,377	$	(52,694	)	$	(35,954	)	$	(67,205	)	$	19,501
Natural gas liquids	6,218		10,795			4,146			(14,240		)	(3,055		)
Natural gas	8,979		39,707			57,211			70,688			122,067
Total	$	19,574	$	(2,192	)	$	25,403		$	(10,757	)	$	138,513
Total revenues	$	1,679,213	$	1,206,293		$	1,090,948		$	834,700		$	804,693
Production volumes from continuing operations
Oil (MBbl)	11,814		10,364			8,749			6,300			5,109
Natural gas liquids (MMgal)	172.3		135.8			108.1			91.4			79.0
Natural gas (MMcf)	58,602		58,104			59,166			54,132			51,778
Production volumes from continuing operations (MBOE)	25,684		23,281			21,183			17,499			15,619
Total production volumes (MBOE)	25,849		25,362			24,066			20,448			18,832
Proved reserves
Oil (MBbl)	181,227		164,870			155,348			129,578			103,262
Natural gas liquids (MBbl)	73,463		63,011			56,155			53,957			40,601
Natural gas (MMcf))	707,926		719,725			809,128			957,368			954,387
Total (MBOE)	372,678		347,835			346,359			343,099			302,928
Costs per BOE from continuing operations
Oil, natural gas liquids and natural gas production expenses	$	10.68	$	11.06		$	9.55		$	9.11		$	9.09
Production and ad valorem taxes	$	3.97	$	4.04		$	3.58		$	3.82		$	3.33
Depreciation, depletion and amortization	$	21.36	$	19.45		$	16.17		$	12.19		$	10.72
Exploration expense	$	1.09	$	0.60		$	0.62		$	0.74		$	4.13
General and administrative expense	$	4.75	$	4.89		$	3.71		$	4.41		$	4.12
Net capital expenditures	$	1,372,510	$	1,104,745		$	1,291,211		$	1,115,452		$	717,782


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 and natural gas liquids-rich properties and natural gas in the Permian Basin in west Texas and the San Juan Basin in New Mexico and Colorado. Our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources).

Energen is focused on increasing its oil and natural gas liquids production and proved reserves largely through development well drilling, exploration, and acquisitions of proved and unproved properties in and around our existing assets. 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.

FINANCIAL AND OPERATING PERFORMANCE

Overview of Year-to-Date 2014 Results and Activities

During the year ended December 31, 2014 as compared to the same period in the prior year, we:


•	increased production volumes from continuing operations by 10.3 percent;


•	increased proved reserves at December 31, 2014 to a record 372.7 MMBOE;


•	expanded our activities in the Permian Basin, increasing production by 22 percent or 3,111 MBOE;


•	recognized non-cash impairments on certain held for sale gas properties in the San Juan Basin in the third and fourth quarters of $147.9 million pre-tax and $88.1 million pre-tax, respectively (see Note 14, Acquisition and Disposition of Properties, in the Notes to Financial Statements);


•	recognized non-cash impairments on certain Permian Basin oil properties in the third and fourth quarters of 2014 of $31.2 million pre-tax and $94.5 million pre-tax, respectively;


•	recognized unproved leasehold writedowns primarily on Permian Basin oil properties of $55.1 million pre-tax and


•	completed the transaction to sell Alabama Gas Corporation (Alagasco) to The Laclede Group, Inc. (Laclede) on September 2, 2014.

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

Energen’s net income for the year ended December 31, 2014 totaled $568.0 million ( $7.75 per diluted share) compared to the year ended December 31, 2013 net income of $204.6 million ( $2.82 per diluted share). 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 the current year was $468.4 million ( $6.39 per diluted share) as compared with income of $62.7 million ( $0.86 per diluted share) from the prior year 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 $142.1 million after-tax);


•	non-cash impairments on certain oil properties in the Permian Basin (approximately $80.1 million after-tax);


•	unproved leasehold writedowns primarily on Permian Basin oil properties (approximately $35.1 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).

Year ended December 31, 2013 vs year ended December 31, 2012

For the year ended December 31, 2013, Energen’s net income totaled $204.6 million ( $2.82 per diluted share) as compared to net income of $253.6 million ( $3.51 per diluted share) in 2012. Energen’s income from continuing operations totaled $141.9 million ( $1.96 per diluted) in 2013 as compared with $204.6 million ( $2.83 per diluted) in 2012. Income from discontinued operations for 2013 was $62.7 million ( $0.86 per diluted share) as compared with income of $48.9 million ( $0.68 per diluted share) from 2012. Income from discontinued operations in 2013 included earnings from Alagasco and an after-tax gain of $22.5 million on the sale of the Black Warrior Basin coalbed methane properties partially offset by the non-cash impairment writedown on North Louisiana/East Texas primarily natural gas properties of $18.9 million after-tax. Income from discontinued operations in 2012 included earnings from Alagasco partially offset by a non-cash impairment on certain properties in East Texas of approximately $13.4 million after-tax. This decrease in income from continuing operations was primarily the result of:


•	higher depreciation, depletion and amortization (DD&A) expense (approximately $73 million after-tax);


•	year-over-year after-tax $67.8 million loss on open derivatives (resulting from an after-tax $30.6 million non-cash loss on open derivatives for 2013 and an after-tax $37.2 million non-cash gain on open derivatives for 2012);


•	higher oil, natural gas liquids and natural gas production expense (approximately $36 million after-tax);


•	increased general and administrative expense (approximately $23 million after-tax);


•	loss on closed derivatives (approximately $18 million after-tax);


•	higher production and ad valorem taxes (approximately $12 million after-tax);


•	lower realized natural gas liquids commodity prices (approximately $7 million after-tax);


•	decreased natural gas production volumes (approximately $2 million after-tax) and


•	higher exploration expense (approximately $1 million after-tax)

partially offset by:


•	higher oil and natural gas liquids production volumes (approximately $107 million after-tax);


•	higher realized oil and natural gas commodity prices (approximately $67 million after-tax) and


•	decreased interest expense (approximately $5 million after-tax).

Operating Income

Consolidated operating income in 2014, 2013 and 2012 totaled $177.0 million , $252.1 million and $364.1 million , respectively. 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. Reduced operating income for 2013 is primarily due to higher DD&A expense, higher oil, natural gas liquids and natural gas production expense and the non-cash mark-to-market decrease in open and closed derivatives partially offset by increased oil and natural gas liquids production and higher natural gas and oil commodity prices.

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)	2014		2013			2012
Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
Oil	$	988,868	$	961,055		$	766,105
Natural gas liquids	110,918		91,407			81,313
Natural gas	244,408		203,855			159,377
Total	$	1,344,194	$	1,256,317		$	1,006,795
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	271,200	$	(43,261	)	$	58,786
Natural gas liquids	287		(652		)	479
Natural gas	43,958		(3,919		)	(515		)
Total	$	315,445	$	(47,832	)	$	58,750



Closed gains (losses) on derivative instruments
Oil	$	4,377	$	(52,694	)	$	(35,954	)
Natural gas liquids	6,218		10,795			4,146
Natural gas	8,979		39,707			57,211
Total	$	19,574	$	(2,192	)	$	25,403
Total revenues	$	1,679,213	$	1,206,293		$	1,090,948
Production volumes
Oil (MBbl)	11,814		10,364			8,749
Natural gas liquids (MMgal)	172.3		135.8			108.1
Natural gas (MMcf)	58,602		58,104			59,166
Total production volumes (MBOE)	25,684		23,281			21,183
Average daily production volumes
Oil (MBbl)	32.4		28.4			24.0
Natural gas liquids (MMgal)	0.5		0.4			0.3
Natural gas (MMcf)	160.6		159.2			162.1
Total average daily production volumes (MBOE/d)	70.4		63.8			58.0
Permian Basin - Spraberry (Trend Area) Field production volumes (included in production volumes above)**
Oil (MBbl)	2,463		2,822			2,134
Natural gas liquids (MMgal)	44.5		38.5			25.8
Natural gas (MMcf)	5,729		4,836			3,592
Total production volumes (MBOE)	4,477		4,544			3,347
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)	$	84.07	$	87.65		$	83.46
Natural gas liquids (per gallon)	$	0.68	$	0.75		$	0.79
Natural gas (per Mcf)	$	4.32	$	4.19		$	3.66
Average realized prices excluding effects of all derivative instruments
Oil (per barrel)	$	83.70	$	92.73		$	87.56
Natural gas liquids (per gallon)	$	0.64	$	0.67		$	0.75
Natural gas (per Mcf)	$	4.17	$	3.51		$	2.69
Costs per BOE
Oil, natural gas liquids and natural gas production expenses	$	10.68	$	11.06		$	9.55
Production and ad valorem taxes	$	3.97	$	4.04		$	3.58
Depreciation, depletion and amortization	$	21.36	$	19.45		$	16.17
Exploration expense	$	1.09	$	0.60		$	0.62
General and administrative	$	4.75	$	4.89		$	3.71

** The Spraberry (Trend Area) Field in the Permian Basin contained 15 percent or more of Energen’s total proved reserves as of December 31, 2014.

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. In 2014, commodity sales increased $87.9 million or 7 percent from the same period of 2013. In the current year, commodity sales revenues from continuing operations increased largely as a result of higher production volumes and higher natural gas commodity prices partially offset by lower oil and natural gas liquids commodity prices. Particular factors impacting commodity sales for 2014 include the following:


•	Oil volumes in 2014 increased 14 percent to 11,814 MBbl 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 fell 9.7 percent to $83.70 per barrel during 2014 and included the impact of wider oil basis differentials.


•	Natural gas liquids production for 2014 rose 26.9 percent to 172.3 MMgal 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 decreased 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 rose 18.8 percent to $4.17 per Mcf during 2014.


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

For the year ended December 31, 2013, oil, natural gas liquids and natural gas sales increased $249.5 million or 24.8 percent from the same period of 2012. Commodity sales revenues from continuing operations increased in 2013 largely as a result of significantly higher oil and natural gas liquids production volumes and higher realized oil and natural gas commodity prices partially offset by lower natural gas liquids commodity prices and decreased natural gas production volumes. Particular factors impacting commodity sales for 2013 include the following:


•	Oil volumes rose 18.5 percent to 10,364 MBbl during 2013.


•	Average realized oil prices in 2013 rose 6 percent to $92.73 per barrel.


•	Production of natural gas liquids increased 25.6 percent to 135.8 MMgal in 2013.


•	Average realized natural gas liquids prices fell 10.7 percent to an average price of $0.67 per gallon during 2013.


•	Natural gas production decreased 1.8 percent to 58.1 Bcf in 2013.


•	Average realized natural gas prices in 2013 rose 30.5 percent to $3.51 per Mcf.


•	Production from continuing operations rose 9.9 percent to 23.3 MMBOE during 2013.

Realized prices exclude the effects of derivative instruments.

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)	2014		2013		2012
Lease operating expenses	$	140,413	$	129,326	$	106,029
Workover and repair costs	91,629		84,102		56,520
Marketing and transportation	42,390		44,010		39,737
Total oil, natural gas liquids and natural gas production expense	$	274,432	$	257,438	$	202,286
Oil, natural gas liquids and natural gas production expense per BOE	$	10.68	$	11.06	$	9.55

Energen had oil, natural gas liquids and natural gas production expense of $274.4 million , $257.4 million and $202.3 million during the years ended December 31, 2014, 2013 and 2012, respectively. Lease operating expense generally reflects year-over-year increases in the number of active wells resulting from Energen’s ongoing development and exploratory activities. 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). During 2013, lease operating expense increased $23.3 million largely due to increased equipment

rental expense (approximately $4.5 million), higher gathering costs (approximately $4.2 million), higher labor costs (approximately $3.6 million), increased environmental compliance costs (approximately $3.1 million), additional electrical costs (approximately $2.8 million), increased chemical usage (approximately $2.4 million) and increased nonoperated costs (approximately $1 million). On a per unit basis, the average lease operating expense for 2014, 2013 and 2012 was $5.46 per barrel of oil equivalent (BOE), $5.56 per BOE and $5.01 per BOE, respectively.

Workover and repair costs increased approximately $7.5 million and $27.6 million in 2014 and 2013, respectively. 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. The increase in workover and repair costs from 2012 to 2013 primarily resulted from increased base load due to our ongoing drilling program, well cleanouts resulting from offset well drilling and fracturing interference, and remedial work related to production interruption from two severe winter weather events.

In the years ended December 31, 2014 and 2013, marketing and transportation costs decreased $1.6 million and rose $4.3 million, respectively.

Production and ad valorem taxes: Production and ad valorem taxes were $102.1 million ( $3.97 per BOE), $94.1 million ( $4.04 per BOE) and $75.9 million ( $3.58 per BOE), respectively, during the years ended December 31, 2014, 2013 and 2012. 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. In 2013, production-related taxes were $13.8 million higher as a result of higher oil and natural gas commodity market prices and the impact of increased oil and natural gas liquids production volumes which contributed approximately $8.5 million and $5.3 million to the increase in production taxes, respectively. Commodity market prices exclude the effects of derivative instruments for purposes of determining production taxes. Increased ad valorem taxes in 2014 and 2013 were primarily driven by the increase in the number of active wells.

Depreciation, depletion and amortization: DD&A expense increased $95.7 million in 2014 and $110.3 million in 2013. The average DD&A rates were $21.36 per BOE in 2014, $19.45 per BOE in 2013 and $16.17 per BOE in 2012. The increase in the 2014 and 2013 per unit DD&A rates, which contributed approximately $47.5 million and $76.6 million, respectively, to the increase in DD&A expense, was primarily due to higher rates resulting from an increase in development costs. Increased production volumes also contributed approximately $46.4 million and $33.6 million to the increase in DD&A expense in 2014 and 2013, respectively.

Asset impairment: In February 2015, Energen entered into a purchase and sale agreement to sell the majority of its natural gas assets in the San Juan Basin in New Mexico and Colorado for approximately $395 million . This sale is expected to close March 31, 2015, and have an effective date of January 1, 2015. During the third and fourth quarters of 2014, non-cash impairment writedowns of $147.9 million pre-tax and $88.1 million pre-tax, respectively, were recognized by Energen on certain 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. These non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement. At December 31, 2014, proved reserves associated with Energen’s San Juan Basin held for sale properties totaled 69,043 MBOE.

During the third and fourth quarters of 2014, Energen recognized non-cash impairment writedowns on certain properties in the Permian Basin of $31.2 million pre-tax and $94.5 million pre-tax, respectively, to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. These non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement.

Energen recognized unproved leasehold writedowns primarily on Permian Basin oil properties of $55.1 million pre-tax during the fourth quarter of 2014. These non-cash writedowns are reflected in asset impairment on the consolidated income statement.

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



Years ended December 31, (in thousands, except per unit data)	2014		2013		2012
Geological and geophysical	$	8,800	$	3,141	$	2,461
Dry hole costs	9,325		2,101		10,453
Delay rentals and other	9,965		8,794		138
Total exploration expense	$	28,090	$	14,036	$	13,052
Total exploration expense per BOE	$	1.09	$	0.60	$	0.62

Exploration expense rose $14.1 million during 2014 primarily due to higher dry hole costs, increased seismic costs and additional delay rentals. Exploration expense increased $1 million in 2013 primarily due to increased delay rentals largely offset by lower dry hole costs.

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)	2014		2013		2012
General and administrative	$	27,781	$	25,310	$	20,617
Benefit and performance-based compensation costs	43,740		45,954		23,031
Labor costs	50,531		42,557		34,979
Total general and administrative expense	$	122,052	$	113,821	$	78,627
Total general and administrative expense per BOE	$	4.75	$	4.89	$	3.71

Total G&A expense rose $8.2 million in 2014 largely due to increased labor costs (approximately $8 million), higher professional services (approximately $2.4 million) and increased recruiting expenses (approximately $1.5 million) partially offset by decreased costs from Energen’s benefit and performance-based compensation plans (approximately $2.2 million) and decreased legal expenses (approximately $1.7 million). In 2013, total G&A expense rose $35.2 million primarily due to increased costs related to Energen’s benefit and performance-based compensation plans (approximately $22.9 million), higher labor costs (approximately $7.6 million), increased legal expenses (approximately $3 million) and higher professional services (approximately $1.1 million).

Interest expense: 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. In 2013, interest expense declined $7.8 million largely due to expense incurred under our credit facility borrowings prior to October 2012, the October 2013 repayment of $50 million of 5 percent Notes and the December 2013 repayment of the Senior Term Loans of $300 million. The interest expense associated with the $600 million Senior Term Loans and the October 2012 syndicated credit facilities are reflected in discontinued operations for all years presented. 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 $482.2 million in 2014. The average daily outstanding balance under credit facilities was $772.0 million in 2013 as compared to $309.9 million in 2012.

Income tax expense: Income tax expense decreased in 2014 and 2013 largely due to lower pre-tax income. In addition, Energen recognized an $8.4 million income tax benefit as a result of re-measuring its state deferred tax liabilities during the fourth quarter of 2014. This re-measurement reflected the state apportionment changes related to certain San Juan Basin properties designated as held for sale as of December 31, 2014.

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 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, 2013 and 2012 and our financial position as of December 31, 2014 and 2013 presented in our consolidated financial statements and these notes reflect Alagasco as discontinued operations.

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 in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. 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 (subject to closing adjustments). 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.

During the first quarter of 2012, Energen recorded a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss from discontinued operations for the year ended December 31, 2012. The impairment was caused by the impact of lower future natural gas prices. This impairment writedown is classified as Level 3 fair value.

See Note 15, 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 overall 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.

Net cash provided by operating activities: Energen’s net cash from operating activities totaled $705.5 million , $927.4 million and $735.7 million in 2014, 2013 and 2012, respectively and included discontinued operations associated with cash flows from Alagasco of $91.5 million , $109.3 million and $85.1 million , respectively. 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. Net income decreased during 2012 largely due to lower realized natural gas and natural gas liquids commodity prices partially offset by increased production volumes and higher oil commodity prices. 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 $38.9 million during 2014. 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 the sale of Alagasco and other assets 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. During 2012, the Company made net investments of $1,322.2 million . Energen invested $139.6 million in property acquisitions including approximately $58.6 million of unproved leaseholds; $692.4 million for development costs (includes the reversal of approximately $46.8 million of accrued development cost) including approximately $560 million to drill 288 net development and service wells; and $416.7 million for exploration including approximately $376.6 million to drill 75 net exploratory wells. In February 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million adding approximately 8.2 MMBOE of proved reserves. Energen had cash proceeds in 2012 of $2.6 million primarily from the sale of certain Black Warrior Basin properties.

During 2014, Energen added 130 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 37 MMBOE and 69 MMBOE of proved reserves in 2013 and 2012, respectively.

Net cash provided by (used in) financing activities: 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. In 2012, the Company provided $586.6 million from net financing activities largely from an increase in short-term borrowings used to fund development activity at Energen and discontinued operations. For each of the years, net cash used in financing activities also reflected dividends paid to common shareholders which were partially offset by 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)	2014		2013		2012
Property acquisitions	$	71,096	$	31,481	$	138,496
Development	406,597		654,222		748,251
Exploration	953,409		423,698		416,678
Other	20,849		11,352		4,543
Total	1,451,951		1,120,753		1,307,968
Less exploration expenditures charged to income	79,441		16,008		16,757
Net capital expenditures	$	1,372,510	$	1,104,745	$	1,291,211

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.

Commodity hedges in place for 2015 will help mitigate some of the commodity price volatility and recent declines. We currently have approximately 8,280 MBbl of oil and 31 Bcf of natural gas hedged for 2015. We are fully exposed to commodity price volatility beginning in 2016. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for a full detail of our hedged volumes.

Energen plans to continue to implement its growth strategy with capital spending in 2015. Production in 2015 is estimated to range from 21.4 MMBOE to 22.4 MMBOE, with a midpoint of 21.9 MMBOE, including approximately 18.4 MMBOE of estimated production from proved reserves owned at December 31, 2014. Energen’s 2015 production estimate excludes volumes from the San Juan Basin assets held for sale at December 31, 2014. Such assets produced an estimated 6.6 MMBOE in 2014. Production estimates do not include amounts for 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.

Production volumes by area are expected to be as follows:



Year ended December 31, (MMBOE)	2015
Permian Basin	19.9
San Juan Basin/other	2.0
Total (midpoint of range)	21.9

Production volumes by commodity are expected to be as follows:



Year ended December 31, (MMBOE)	2015
Oil	14.0
Natural gas liquids	3.7
Natural gas	4.2
Total (midpoint of range)	21.9

During 2015, Energen expects an annualized decline rate of approximately16.4 percent for its proved developed producing properties owned at December 31, 2014 , excluding production from San Juan Basin properties held for sale at December 31, 2014. During the same period, total production from proved properties is expected to decrease approximately 3.8 percent and total production is expected to increase approximately 14.5 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, 2014 , excluding production from San Juan Basin properties held for sale at December 31, 2014, for the 5 year period 2014 to 2019, for the 10 year period 2014 to 2024 and for the 20 year period 2014 to 2034 of approximately 15.8 percent, 13.3 percent and 10.3 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 significant capital in oil and natural gas production operations. For 2015, we expect our oil and natural gas capital spending to total approximately $1 billion, including $347 million for existing properties and $613 million for exploration. Included in this $347 million is approximately $288 million for the development of previously identified proved undeveloped reserves.

Capital expenditures by area and targeted formation during 2015 are planned as follows:



Year ended December 31, (in thousands)	2015
Permian
Midland Basin
Wolfcamp	$	515,000
Spraberry	68,000
Wolfberry	27,000
SWD/Facilities	45,000
Non-operated/Other	10,000
Delaware Basin
Bone Spring	10,000
Wolfcamp	85,000
Wolfbone	13,000
Lease extensions	37,000
SWD/Facilities	39,000
Non-operated/Other	3,000
Other Permian	12,000
San Juan Basin/Non-Operated/Other	73,000
Net Carry-in/Carry Out	63,000
Total	$	1,000,000

Energen anticipates having the following drilling rigs and net wells by area during 2015. The drilling rigs presented below are operated while the net wells include operated and non-operated wells.



	Drilling Rigs	Net Wells
Permian Basin	8-11	116

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.

To finance capital spending, Energen expects to use internally generated cash flow supplemented by our existing $2.0 billion five-year syndicated credit facility. We also will use the $395 million of proceeds expected from the sale of certain San Juan Basin properties. Energen also 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. While we expect to have ongoing access to our credit facility and long-term capital markets, continued access could be adversely affected by current and future economic and business conditions and possible credit rating downgrades.

Credit Facility and Working Capital

On September 2, 2014, Energen entered into a $1.5 billion five-year syndicated secured credit facility with domestic and foreign lenders. The credit facility was amended to $2.0 billion on November 17, 2014. The credit facility has an initial borrowing base of $2.1 billion . This credit facility refinances and replaces the $1.25 billion five-year syndicated unsecured credit facility entered into on October 30, 2012. Energen’s obligations under the $2.0 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. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes. The Company was in compliance with the terms of the syndicated credit facility at December 31, 2014 .

At close of the sale of certain San Juan properties, our borrowing base and corresponding bank commitments will be reduced by $220 million reflecting the sold proved reserves. In addition, our borrowing base is subject to redetermination semi-annually and for event-driven unscheduled redeterminations. Each redetermination includes updating the borrowing base for new drilling and production and for any changes to the specific lending criteria of our bank group, including commodity price outlook. Given the recent decrease in commodity prices and based on the recent strip prices, we anticipate a further reduction of $150 million to $250 million to our borrowing base. However, we believe that after reflecting these reductions to our borrowing base and related bank commitments we will have adequate liquidity to execute our planned capital spending.

At December 31, 2014, Energen reported unadjusted working capital of $359.0 million arising from current assets of $919.4 million exceeding current liabilities of $560.3 million . Working capital at Energen is influenced by the fair value of derivative financial instruments associated with future production. Energen has $322.3 million in current assets and $1.0 million in current liabilities, respectively, associated with its derivative financial instruments at December 31, 2014. Energen relies upon cash flows from operations supplemented by our credit facility to fund working capital needs.

Credit Ratings

On September 3, 2014, following the sale of Alagasco, Standard & Poor’s (S&P) lowered its credit ratings for Energen from BBB- to BB with a stable outlook. On April 8, 2014, Moody’s Investors Service lowered Energen’s senior unsecured credit rating from Baa3 to Ba1 with a negative outlook.

Dividends

Dividends for the first, second and third quarter of 2014 were $0.15 per share on Energen common stock and $0.02 per share for the fourth quarter of 2014. Subsequent to the sale of Alagasco, Energen substantially reduced the amount of its dividend payments with a focus on further development and exploration of its oil and natural gas properties. 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’s credit facility prohibits payment of 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.

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 closes the plan to new entrants, effective November 1, 2014, and freezes benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015. We anticipate distributing benefits under the plan in late 2015 or early 2016 pending receipt of a determination letter from the Internal Revenue Service and completion of certain administrative actions.

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 will be made in each of the first quarters of 2015 and 2016. In connection with the termination of these plans, Energen has also reclassified approximately $11.0 million as of December 31, 2014 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 fund the estimated payments in the first quarter of 2015.

In October 2014, Energen’s Board of Directors amended and restated the Employee Saving 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.

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, 2013 and 2012 . As of December 31, 2014 , 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, 2014 , 2013 and 2012 , Energen acquired 32,768 shares, 14,766 shares and 12,867 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, 2014 :



	Payments Due Before December 31,
(in thousands)	Total		2015		2016-2017		2018-2019		2020 and Thereafter
Long-term debt ⁽¹⁾	$	1,039,000	$	—	$	19,000	$	485,000	$	535,000
Interest payments on debt	283,382		37,689		74,791		69,888		101,014
Operating leases	12,597		2,698		5,144		4,755		—
Asset retirement obligations ⁽²⁾	742,007		3,282		4,825		4,816		729,084
Nonqualified supplemental retirement plans	26,461		10,959		14,714		217		571
Total contractual cash obligations	$	2,103,447	$	54,628	$	118,474	$	564,676	$	1,365,669

(1) Long-term debt obligations include approximately $0.4 million of unamortized debt discounts as of December 31, 2014 .

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

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 5.4 MMBOE through August 2017 .

During 2015, Energen anticipates an additional contribution of $13.7 million in order to complete the distribution of plan assets related to the plan termination. The contractual obligations reported above exclude any payments Energen expects to make to postretirement benefit program assets.

The contractual obligations reported above exclude Energen’s liability of $17.5 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 Order in 2011 and in July 2012, on a motion from ONRR, the Order was remanded. In August 2014, ONRR issued its Revised Order that is now under appeal. In the Revised Order, ONRR has ordered that Energen pay additional royalties on production from certain federal leases in the amount of $129,700 . Energen estimates that application of the Revised Order to all of the Company’s federal leases would result in ONRR claims up to approximately $24 million , plus interest and penalties from 2004 forward. ONRR began implementing its unbundling initiative in 2010, but seeks to implement its revisions retroactively, despite the fact that they conflict with previous audits, allowances and industry practice. Energen continues to vigorously contest the Revised Order and the findings. Management is unable, at this time, to determine a range of reasonably possible losses, and no amount has been accrued as of December 31, 2014 .

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 thirteen of our active counterparties and in a net loss position with the remaining one at December 31, 2014 . 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, 2014 , Energen was in a net gain position of $321.3 million for derivative contracts and estimates that a 10 percent increase or decrease in the commodities prices would have resulted in an approximate $54 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, 2014 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 $6.7 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 and requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate implementing rules and regulations. These rules and regulations will cover, among other 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 margin and exchange clearing requirements pursuant to final regulations adopted by the CFTC and SEC and published in the Federal Register on July 19, 2012. 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 which have not yet been finally 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 the new rules and regulations, 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 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, 2014 . 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 2015 depreciation, depletion and amortization expense associated with an assumed downward revision in the reported oil and natural gas reserve amounts at December 31, 2014 :

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. 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, substantial 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. 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.

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.

Employee Benefit Plans: An employer is required to recognize the net funded status of defined benefit pensions and other postretirement benefit plans as an asset or liability in its statement of financial position and to recognize changes in the funded status through comprehensive income in the year in which the changes occur. For other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation, a measurement of earned postretirement benefit obligations expected to be paid to employees upon retirement. As Energen has frozen and plans to terminate the defined benefit pension plan, the projected pension benefit obligation as of December 31, 2014 represents the present value of the estimated cost of settling the benefit obligation of the plan.

Actuarial assumptions attempt to anticipate future events and are used in calculating the expenses and liabilities related to these plans. The calculation of the liability related to Energen’s benefit plans includes assumptions regarding the market interest rates at which pension benefits will be settled, appropriate weighted average discount rates, the expected long-term rate of return on the plans’ assets and the anticipated life span of employees. The key assumptions used in determining these calculations are disclosed in Note 5, Employee Benefit Plans, in the Notes to Financial Statements.

In selecting each discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments Energen expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate for each plan 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 weighted average discount rate used to determine net periodic benefit costs was 3.66 percent for the pension plans and 4.88 percent for the other postretirement plans for the year ended December 31, 2014 . The assumed rate of return on assets is the weighted average of expected long-term asset assumptions; the return on assets used to determine net periodic benefit cost was 7 percent for each of the applicable plans for the year ended December 31, 2014 . The estimated weighted average rate of increase in the compensation level for pay related plans was 3.63 percent for the year ended December 31, 2014 .

The selection and use of actuarial assumptions affects the amount of benefit expense recorded in Energen’s financial statements. The table below reflects a hypothetical 25 basis point change in assumed actuarial assumptions to pre-tax benefit expense for the year ended December 31, 2014 :



(in thousands)	Postretirement Expense
Discount rate change	$	10
Return on assets	$	25

The weighted average discount rate and return on plan assets used in the 2015 actuarial assumptions for other postretirement plans are 4.25 percent and 7.00 percent, respectively.

The pension plan obligations anticipated the plan will be settled during late 2015. Should the settlement not occur until 2016, the obligations may vary based on market rates and the time of settlement. A 25 basis point increase in market rates would reduce the cost of settling the pension obligations by approximately $2.7 million.

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

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.

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, 2014 , Energen entered into the following transactions for 2015 and subsequent years:



Production Period	Total Hedged Volumes		Average Contract Price	Description	Fair Value (in thousands)
Oil
2015	8,280	MBbl	$89.30 Bbl	NYMEX Swaps	$	268,550
Oil Basis Differential
2015	2,160	MBbl	$(4.30) Bbl	WTS/WTI Basis Swaps*	(3,836		)
2015	6,840	MBbl	$(4.82) Bbl	WTI/WTI Basis Swaps**	(14,419		)
Natural Gas
2015	23.0	Bcf	$4.13 Mcf	Basin Specific Swaps - San Juan	28,597
2015	8.0	Bcf	$4.25 Mcf	Basin Specific Swaps - Permian	10,927
December 2014 contracts (closed but not cash settled)					31,530
Total					$	321,349
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/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 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, 2014 primarily relates to our syndicated credit facility with variable interest rates. At December 31, 2014 , we had interest rate swap agreements with a notional of $133 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 $0.8 million liability at December 31, 2014 . The weighted average interest rate for amounts outstanding at December 31, 2014 was 1.67 percent . All long-term debt obligations, other than our credit facility, were at fixed rates at December 31, 2014.


ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ENERGEN CORPORATION

INDEX TO FINANCIAL STATEMENTS



		Page
1.	Financial Statements

	Report of Independent Registered Public Accounting Firm	39

	Consolidated Statements of Income for the years ended December 31, 2014, 2013 and 2012	42

	Consolidated Statements of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012	43

	Consolidated Balance Sheets as of December 31, 2014 and 2013	40

	Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2014, 2013 and 2012	44

	Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012	45

	Notes to Financial Statements	46

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.

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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014 , 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 Reporting appearing 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

March 2, 2015

ENERGEN CORPORATION

CONSOLIDATED BALANCE SHEETS



(in thousands)	December 31, 2014		December 31, 2013

ASSETS
Current Assets
Cash and cash equivalents	$	1,852	$	2,523
Accounts receivable, net of allowance for doubtful accounts of $688 and $696 at December 31, 2014 and 2013, respectively	157,678		136,334
Inventories	14,251		11,130
Assets held for sale	395,797		1,242,872
Deferred income taxes	—		21,250
Derivative instruments	322,337		17,463
Prepayments and other	27,445		9,989
Total current assets	919,360		1,441,561
Property, Plant and Equipment
Oil and gas properties, successful efforts method
Proved properties	6,903,514		6,695,400
Unproved properties	142,340		168,975
Less accumulated depreciation, depletion and amortization	1,893,106		1,776,802
Oil and gas properties, net	5,152,748		5,087,573
Other property and equipment, net	46,389		30,515
Total property, plant and equipment, net	5,199,137		5,118,088
Other postretirement assets	—		8,894
Noncurrent derivative instruments	—		5,439
Other assets	19,761		48,230
TOTAL ASSETS	$	6,138,258	$	6,622,212

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

ENERGEN CORPORATION

CONSOLIDATED BALANCE SHEETS



(in thousands, except share data)	December 31, 2014			December 31, 2013

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	—		$	60,000
Notes payable to banks	—			489,000
Accounts payable	101,453			78,178
Accrued taxes	5,530			8,201
Accrued wages and benefits	46,162			27,036
Accrued capital costs	207,461			93,623
Revenue and royalty payable	72,047			51,519
Liabilities related to assets held for sale	24,230			831,570
Deferred income taxes	79,164			—
Derivative instruments	988			30,302
Other	23,288			21,796
Total current liabilities	560,323			1,691,225
Long-term debt	1,038,563			1,093,541
Asset retirement obligations	94,060			108,533
Pension and other postretirement liabilities	15,935			47,484
Deferred income taxes	1,000,486			807,614
Noncurrent derivative instruments	—			398
Other	14,287			15,398
Total liabilities	2,723,654			3,764,193
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; 75,875,711 shares issued at December 31, 2014 and 75,574,156 shares issued at December 31, 2013	759			756
Premium on capital stock	564,438			523,711
Retained earnings	2,997,821			2,476,616
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	—			13,362
Pension and postretirement plans	(22,870		)	(32,245		)
Interest rate swap	—			(1,184		)
Deferred compensation plan	2,862			3,259
Treasury stock, at cost; 2,980,598 shares and 2,967,999 shares at December 31, 2014 and 2013, respectively	(128,406		)	(126,256		)
Total shareholders’ equity	3,414,604			2,858,019
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,138,258		$	6,622,212

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

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF INCOME



Years ended December 31, (in thousands, except share data)	2014			2013			2012

Revenues
Oil, natural gas liquids and natural gas sales	$	1,344,194		$	1,256,317		$	1,006,795
Gain (loss) on derivative instruments, net	335,019			(50,024		)	84,153
Total revenues	1,679,213			1,206,293			1,090,948
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production	274,432			257,438			202,286
Production and ad valorem taxes	102,063			94,103			75,907
Depreciation, depletion and amortization	548,564			452,876			342,611
Asset impairment	416,801			13,906			6,304
Exploration	28,090			14,036			13,052
General and administrative	122,052			113,821			78,627
Accretion of discount on asset retirement obligations	7,608			6,995			6,339
Loss on sale of assets and other, net	2,642			981			1,718
Total operating costs and expenses	1,502,252			954,156			726,844
Operating Income	176,961			252,137			364,104
Other Income (Expense)
Interest expense	(37,771		)	(39,736		)	(47,565		)
Other income	1,181			3,803			1,645
Total other expense	(36,590		)	(35,933		)	(45,920		)
Income From Continuing Operations Before Income Taxes	140,371			216,204			318,184
Income tax expense	40,728			74,323			113,563
Income From Continuing Operations	99,643			141,881			204,621
Discontinued Operations, net of tax
Income from discontinued operations	29,292			59,079			48,941
Gain on disposal of discontinued operations, net	439,097			3,594			—
Income From Discontinued Operations	468,389			62,673			48,941
Net Income	$	568,032		$	204,554		$	253,562

Diluted Earnings Per Average Common Share
Continuing operations	$	1.36		$	1.96		$	2.83
Discontinued operations	6.39			0.86			0.68
Net Income	$	7.75		$	2.82		$	3.51
Basic Earnings Per Average Common Share
Continuing operations	$	1.37		$	1.96		$	2.84
Discontinued operations	6.42			0.87			0.68
Net Income	$	7.79		$	2.83		$	3.52

Diluted Average Common Shares Outstanding	73,274,631			72,470,622			72,316,214
Basic Average Common Shares Outstanding	72,896,579			72,317,865			72,119,021

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

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



Years ended December 31, (in thousands)	2014			2013			2012

Net Income	$	568,032		$	204,554		$	253,562
Other comprehensive income (loss):
Cash flow hedges:
Current period change in fair value of derivative commodity instruments, net of tax of $23, ($6,660) and $40,720, respectively	37			(10,866		)	66,438
Reclassification adjustment for derivative commodity instruments, net of tax of ($8,212), ($13,560) and ($17,994), respectively	(13,399		)	(22,124		)	(29,359		)
Current period change in fair value of interest rate swap, net of tax of ($160), ($80) and ($1,228), respectively	(298		)	(148		)	(2,281		)
Reclassification adjustment for interest rate swap, net of tax of $798, $603 and $574, respectively	1,482			1,120			1,066
Total cash flow hedges	(12,178		)	(32,018		)	35,864
Pension and postretirement plans:
Amortization of net benefit obligation at transition, net of tax of $8, $112 and $100, respectively	14			207			186
Amortization of prior service cost, net of tax of $87, $90 and $119, respectively	161			167			221
Amortization of net loss, net of tax of $7,676, $4,472 and $1,676, respectively	14,256			8,306			3,113
Current period change in fair value of pension and postretirement plans, net of tax of ($2,722), $6,237, and ($9,393), respectively	(5,056		)	11,582			(17,443		)
Total pension and postretirement plans	9,375			20,262			(13,923		)
Comprehensive Income	$	565,229		$	192,798		$	275,503

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

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, 2011	75,007,412		$	750		$	485,720		$	2,100,885		$	(30,252	)	$	3,511		$	(128,451	)	$	2,432,163
Net income									253,562												253,562
Other comprehensive income												21,941									21,941
Purchase of treasury shares, net (5,459 shares)																		(277		)	(277		)
Shares issued for employee benefit plans	60,348		1			2,060															2,061
Deferred compensation obligation															(737		)	737			—
Stock-based compensation						6,580												502			7,082
Tax benefit from employee stock plans						550															550
Cash dividends - $0.56 per share									(40,392		)										(40,392		)
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 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

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

ENERGEN CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS



Years ended December 31, (in thousands)	2014			2013			2012

Operating Activities
Net income	$	568,032		$	204,554		$	253,562
Income from discontinued operations	(468,389		)	(62,673		)	(48,941		)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	548,564			452,876			342,611
Asset impairment	416,801			13,906			6,304
Accretion of discount on asset retirement obligations	7,608			6,995			6,339
Deferred income taxes	302,890			118,600			128,171
Change in derivative fair value	(346,646		)	48,029			(41,819		)
(Gain) loss on sale of assets	55			(89		)	(529		)
Stock-based compensation expense	11,332			13,621			5,318
Exploration, including dry holes	9,325			2,102			10,453
Discontinued operations	91,510			109,318			85,065
Other, net	4,166			12,284			(714		)
Net change in:
Accounts receivable	4,812			23,785			4,111
Inventories	(3,121		)	10,817			(561		)
Accounts payable	18,695			(52,946		)	(14,038		)
Accrued taxes/income tax receivable	(487,787		)	2,139			(6,679		)
Pension and other postretirement benefit contributions	(12,483		)	(5,677		)	(3,271		)
Other current assets and liabilities	40,119			29,736			10,355
Net cash provided by operating activities	705,483			927,377			735,737
Investing Activities
Additions to oil and natural gas properties	(1,264,059		)	(1,109,365		)	(1,107,911		)
Acquisitions, net of cash acquired	(70,730		)	(31,331		)	(139,563		)
Proceeds from sale of Alabama Gas Corporation and other assets	1,347,725			160,986			2,562
Purchase of short-term investments	(473,000		)	(310,000		)	—
Sale of short-term investments	473,000			310,000			—
Discontinued operations	(51,850		)	(73,341		)	(76,740		)
Other, net	—			(559		)	(530		)
Net cash used in investing activities	(38,914		)	(1,053,610		)	(1,322,182		)
Financing Activities
Payment of dividends on common stock	(34,304		)	(41,993		)	(40,392		)
Issuance of common stock	23,053			17,780			1,224
Purchase and retirement of shares	(14,913		)	—			—
Issuance of long-term debt	—			600,000			—
Reduction of long-term debt	(600,000		)	(350,000		)	(1,000		)
Payment of debt issuance costs	(10,901		)	(2,740		)	—
Net change in credit facility	(4,000		)	(77,000		)	566,000
Tax benefit on stock compensation	5,906			3,142			550
Discontinued operations	(35,113		)	(27,105		)	61,744
Other	—			—			(1,518		)
Net cash provided by (used in) financing activities	(670,272		)	122,084			586,608
Net change in cash and cash equivalents	(3,703		)	(4,149		)	163
Cash and cash equivalents at beginning of period	5,555			9,704			9,541
Cash and cash equivalents at end of period	1,852			5,555			9,704
Less cash and cash equivalents of discontinued operations at end of period	—			(3,032		)	(5,559		)
Cash and cash equivalents of continuing operations at end of period	$	1,852		$	2,523		$	4,145

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

ENERGEN CORPORATION

NOTES TO FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

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 when the sale results in the elimination of operations and cash flows from company operations and when there will be no significant continuing involvement in the operations and cash flows of the sold component. The results of operations of these properties are reclassified and reported as discontinued operations for prior periods.

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. In addition, and in connection with the sale of Alagasco, we have chosen to reformat our financial statements to reflect a presentation more closely aligned with our peers in the oil and natural gas industry. As part of the financial statement reformatting, certain reclassifications were made to conform prior periods’ financial statements to the current-year presentation. These reclassifications primarily included further detail under operating costs and expenses. We further reclassified all commodity hedges from oil and natural gas operating revenues to gain (loss) on derivative instruments, net, as follows:



Years ended December 31, (in thousands)	2014		2013			2012
Open non-cash mark-to-market gains (losses) on derivative instruments	$	315,445	$	(47,832	)	$	58,750
Closed gains (losses) on derivative instruments	19,574		(2,192		)	25,403
Gain (loss) on derivative instruments, net	$	335,019	$	(50,024	)	$	84,153

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 (G&A) 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			2012
Alagasco net income	$	40,646		$	57,399		$	49,402
Depreciation, depletion and amortization	(408		)	(598		)	(572		)
General and administrative	3,337			5,894			5,166
Interest expense	(17,306		)	(13,815		)	(1,693		)
Other income	(347		)	(1,342		)	(977		)
Income tax expense (benefit)	5,567			3,728			(727		)
Alagasco income from discontinued operations	31,489			51,266			50,599
Energen income (loss) from discontinued operations	(2,197		)	7,813			(1,658		)
Income from discontinued operations	$	29,292		$	59,079		$	48,941

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 unproved 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, 2014 and 2013 .

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.

Energen’s current policy is to not enter into agreements that require the posting of collateral. 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.

Prior to June 30, 2013, Energen used cash flow hedge accounting, where applicable, for its derivative transactions. The effective portion of the gain or loss on the derivative instrument was recognized in accumulated other comprehensive income as a component of shareholders’ equity and subsequently reclassified as gain (loss) on derivative instruments, net when the forecasted

transaction affects earnings. The ineffective portion of a derivative’s change in fair value was required to be recognized immediately in gain (loss) on derivative instruments, net. All other derivative transactions not designated as cash flow hedge accounting 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.

Effective March 31, 2013 and June 30, 2013, Energen dedesignated from cash flow hedge accounting 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various NYMEX oil contracts with the Permian Basin due to lack of correlation. Gains and losses from inception of the hedge to the dedesignation date were frozen in accumulated other comprehensive income until the forecasted transactions actually occurred. Subsequent gains or losses are accounted for as mark-to-market transactions and recognized immediately through gain (loss) on derivative instruments, net.

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 .

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.

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 when the sale results in the elimination of operations and cash flows from company operations and when there will be no significant continuing involvement in the operations and cash flows of the sold component. 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 G&A 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. Level 3 fair values used unobservable market prices primarily associated with certain alternative investments and a limited partnership in 2013 and 2012.

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.

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, 2014 and 2013, 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 measures all share-based compensation awards at fair value at the date of grant and expenses the awards over the requisite vesting 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, 2014 , 2013 and 2012, we recognized an excess tax benefit of $5.9 million , $3.1 million and $0.6 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

Energen has a defined benefit non-contributory qualified pension plan which covers substantially all employees. Pension benefits are based on years of service and final earnings. Energen also has nonqualified supplemental pension plans covering certain officers of Energen. In addition to providing pension benefits, 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.

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.

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 closes the plan to new entrants, effective November 1, 2014, and freezes benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015. We anticipate distributing benefits under the plan in late 2015 or early 2016 pending receipt of a determination letter from the IRS and completion of certain administrative actions.

Energen’s non-qualified supplemental retirement plans have also been amended to terminate effective December 31, 2014. Distributions under the plan are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants will be made in each of the first quarters of 2015 and 2016.

Measurement: For retirement plans and 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 defined benefit pension plan and other postretirement benefit plans on an actuarial basis and the net funded status of benefit plans is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. For the pension plan, the benefit obligation is the projected benefit obligation calculated on a plan termination basis assuming a distribution in one year; for other postretirement plans, 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.

Discount Rate: For our defined benefit pension plan, we discounted the estimated termination liability using the one year spot rate of 0.70 percent . 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 for the postretirement plan 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.

Long-Term Rate of Return: 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.

Other Significant Assumptions: The estimated weighted average rate of increase in the compensation level for pay related plans is another assumption used in calculation of the net periodic pension cost.

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 AND NOTES PAYABLE

Long-term debt consisted of the following:



(in thousands)	December 31, 2014		December 31, 2013
Credit facility	$	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
Senior Term Loans, (floating rate interest LIBOR plus 1.625%)	—		600,000
Total	1,039,000		1,154,000
Less amounts due within one year	—		60,000
Less unamortized debt discount	437		459
Total	$	1,038,563	$	1,093,541

The aggregate maturities of Energen’s long-term debt as of December 31, 2014 are as follows:



Years ending December 31, (in thousands)
2015	2016	2017	2018	2019	Thereafter
$—	$—	$19,000	$—	$485,000	$535,000

In December 2013, the Company issued $600 million in Senior Term Loans with a floating interest rate due March 31, 2014 through December 17, 2017. In conjunction with the sale of Alagasco, the $600 million Senior Term Loans were repaid in September 2014.

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 $1.5 billion five -year syndicated secured credit facility with domestic and foreign lenders. The credit facility was amended to $2.0 billion on November 17, 2014. The credit facility has an initial borrowing base of $2.1 billion . This credit facility refinances and replaces the $1.25 billion five -year syndicated unsecured credit facility entered into on October 30, 2012. Energen’s obligations under the $2.0 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, 2015.

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, 2014 .

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



(in thousands)	December 31, 2014			December 31, 2013
Notes payable to banks	$	485,000		$	489,000
Available for borrowings	1,515,000			761,000
Total	$	2,000,000		$	1,250,000
Maximum amount outstanding at any month-end	$	750,000		$	859,000
Average daily amount outstanding	$	482,166		$	772,012
Weighted average interest rates based on:
Average daily amount outstanding	1.46		%	1.39		%
Amount outstanding at year-end	1.67		%	1.40		%

Energen’s total interest expense was $37.8 million , $39.7 million and $47.6 million for the years ended December 31, 2014 , 2013 and 2012 , respectively. Energen’s total interest expense for the years ended December 31, 2014, 2013 and 2012 included amortization of debt issuance costs of $5.7 million , $2.0 million and $2.4 million , respectively. In addition, Energen’s total interest expense for the years ended December 31, 2014, 2013 and 2012 included capitalized interest expense of $0.2 million , $0.2 million and $0.5 million , respectively. At December 31, 2014, Energen paid commitment fees on the unused portion of available credit facilities at a current annual rate of 30 basis points per annum. See Note 2, Summary of Significant Accounting Policies, for further information regarding interest on debt required to be extinguished, associated with the sale of Alagasco, which was classified to discontinued operations.

4. INCOME TAXES

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



Years ended December 31, (in thousands)	2014			2013			2012
Taxes estimated to be payable currently:
Federal	$	161,576		$	23,342		$	16,295
State	72,379			2,516			3,125
Total current	233,955			25,858			19,420
Taxes deferred:
Federal	144,645			85,950			119,053
State	(34,447		)	(2,300		)	5,346
Total deferred	110,198			83,650			124,399
Total income tax expense	$	344,153		$	109,508		$	143,819

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



Years ended December 31, (in thousands)	2014		2013		2012
Income tax expense from continuing operations	$	40,728	$	74,323	$	113,563
Income tax expense from discontinued operations	17,928		33,174		30,256
Income tax expense from gain on disposal of discontinued operations	285,497		2,011		—
Total income tax expense	$	344,153	$	109,508	$	143,819

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



(in thousands)	December 31, 2014						December 31, 2013
	Current			Noncurrent			Current			Noncurrent
Deferred tax assets:
Minimum tax credit	$	—		$	46,338		$	—		$	—
Allowance for doubtful accounts	244			—			251			—
Insurance and other accruals	2,537			—			3,082			—
Compensation accruals	11,355			—			12,925			—
Pension and other costs	—			7,009			—			3,652
Other comprehensive income	10,732			1,581			—			15,350
Derivative instruments	—			—			10,769			—
State net operating losses and other carryforwards	—			15,392			—			4,577
Other	665			—			235			—
Total deferred tax assets	25,533			70,320			27,262			23,579
Valuation allowance	(1,122		)	(2,467		)	(299		)	(2,674		)
Total deferred tax assets	24,411			67,853			26,963			20,905



Deferred tax liabilities:
Depreciation and basis differences	—			1,057,430			—		821,425
Derivative instruments	102,691			—			—		2,048
Other comprehensive income	—			—			5,540		—
Other	884			10,909			173		5,046
Total deferred tax liabilities	103,575			1,068,339			5,713		828,519
Net deferred tax assets (liabilities)	$	(79,164	)	$	(1,000,486	)	$	21,250	$	(807,614	)

Energen files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2014, the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $46.3 million . Energen has a noncurrent deferred tax asset of $11.8 million relating to Energen Resources’ $254.6 million state net operating loss carryforward which will expire beginning in 2027. Energen Resources anticipates generating adequate future taxable income to fully realize this benefit. Energen has a full valuation allowance recorded against a noncurrent deferred tax asset of $3.6 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 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)	2014			2013			2012
Income tax expense at statutory federal income tax rate	$	49,130		$	75,671		$	111,364
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	93			1,461			2,423
Impact of state law changes	(121		)	(1,966		)	—
Impact of state deferred tax revaluation on San Juan properties	(8,382		)	—			—
401(k) stock dividend deduction	(232		)	(449		)	(514		)
Other, net	240			(394		)	290
Total income tax expense	$	40,728		$	74,323		$	113,563
Effective income tax rate (%)	29.01			34.38			35.69

Energen recognized an $8.4 million income tax benefit as a result of re-measuring its state deferred tax liabilities during the fourth quarter of 2014. This re-measurement reflected the state apportionment changes related to certain San Juan Basin properties designated as held for sale as of December 31, 2014.

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



(in thousands)
Balance as of December 31, 2011	$	10,593
Additions based on tax positions related to the current year	3,731
Additions for tax positions of prior years	269
Reductions for tax positions of prior years	(446		)
Lapse of statute of limitations	(1,592		)
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

The amount of unrecognized tax benefits at December 31, 2014 that would favorably impact Energen’s effective tax rate, if recognized, is $7.6 million . Energen recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2014 , 2013 , and 2012 , Energen recognized approximately $27,000 of expense, $15,000 of expense and $25,000 of income 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, 2014 and 2013 , respectively.

Energen’s tax returns for years 2011-2013 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: 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.

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 closes the plan to new entrants, effective November 1, 2014, and freezes benefit accruals effective December 31, 2014. Energen terminated the plan on January 31, 2015. We anticipate distributing benefits under the plan in late 2015 or early 2016 pending receipt of a determination letter from the IRS and completion of certain administrative actions.

Energen’s non-qualified supplemental retirement plans were amended to terminate 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 will be made in each of the first quarters of 2015 and 2016. In connection with the termination of these plans, Energen has also reclassified approximately $11.0 million as of December 31, 2014 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 fund the estimated payments in the first quarter of 2015.

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 Energen has frozen and plans to terminate the defined benefit pension plan, the projected pension benefit obligation as of December 31, 2014 represents the present value of the estimated cost of settling the plans benefit obligation. The amounts in the table below as of December, 31 2013 include both Energen and Alagasco, except for Alagasco plans which contain certain labor union agreements:



As of December 31, (in thousands)	2014			2013			2014			2013
	Pension						Postretirement Benefits
Accumulated benefit obligation	$	107,669		$	225,969
Benefit obligation:
Balance at beginning of period	$	266,294		$	293,075		$	33,224		$	46,901
Service cost	8,329			13,293			262			1,125
Interest cost	5,325			10,161			716			1,931
Actuarial (gain) loss	9,078			(26,909		)	6,385			(13,311		)
Curtailment gain	(8,496		)	(4,223		)	—			(1,255		)
Transfer in connection with the sale of Alagasco	(124,783		)	—			(28,648		)	—
Termination benefit charge	2,477			—			—			—
Retiree drug subsidy program	—			—			48			124
Benefits paid	(50,555		)	(19,103		)	(860		)	(2,291		)
Balance at end of period	$	107,669		$	266,294		$	11,127		$	33,224
Plan assets:
Fair value of plan assets at beginning of period	$	193,457		$	182,796		$	55,459		$	48,194
Actual return (loss) on plan assets	5,359			19,595			(331		)	8,072
Employer contributions	19,164			10,169			21			1,484
Transfer in connection with the sale of Alagasco	(99,883		)	—			(43,596		)	—
Benefits paid	(50,555		)	(19,103		)	(860		)	(2,291		)
Fair value of plan assets at end of period	$	67,542		$	193,457		$	10,693		$	55,459

Funded status of plans	$	(40,127	)	$	(72,837	)	$	(434	)	$	22,235



Noncurrent assets	$	—		$	—		$	—		$	8,894
Noncurrent assets in assets held for sale	—			—			—			13,341
Current liabilities	(24,626		)	(6,145		)	—			—
Noncurrent liabilities	(15,501		)	(47,485		)	(434		)	—
Noncurrent liabilities in liabilities related to assets held for sale	—			(19,207		)	—			—
Net asset (liability) recognized	$	(40,127	)	$	(72,837	)	$	(434	)	$	22,235
Amounts recognized to accumulated other comprehensive income:
Prior service costs, net of taxes	$	—		$	323		$	—		$	—
Net actuarial (gain) loss, net of taxes	22,246			37,479			624			(5,584		)
Transition obligation, net of taxes	—			—			—			27
Total accumulated other comprehensive income (loss)	$	22,246		$	37,802		$	624		$	(5,557	)

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



	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



	December 31, 2013
(in thousands)	Level 1		Level 2		Total
Insurance contracts	$	—	$	14,805	$	14,805
United States equities	5,579		—		5,579
Global equities	2,338		—		2,338
Fixed income	—		11,039		11,039
Total	$	7,917	$	25,844	$	33,761

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 following is a reconciliation of insurance contracts in Level 3 of the fair value hierarchy:



Years ended December 31, (in thousands)	2013			2012
Balance at beginning of period	$	5,600		$	5,332
Unrealized gains relating to instruments held at the reporting date	—			268
Transfer out of Level 3	(5,600		)	—
Balance at end of period	$	—		$	5,600

Transfer of Insurance Contracts: For the year ended December 31, 2014, there were no significant transfers in or out of Levels 1, 2, or 3. During 2013, Energen determined that its insurance contracts meet the requirements to be categorized as a Level 2 fair value measurement. The insurance contracts consist of multiple contracts with two insurance companies and are accounted for at fair value at the contracts’ cash surrender values.

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



Years ended December 31, (in thousands)	2014			2013			2012
Pension Plans
Components of net periodic benefit cost:
Service cost	$	6,808		$	5,196		$	4,023
Interest cost	4,498			4,496			4,296
Expected long-term return on assets	(4,386		)	(5,225		)	(5,134		)
Prior service cost amortization	202			246			209
Actuarial loss amortization	4,995			6,919			3,945
Termination benefit charge	2,477			—			—
Settlement charge	4,082			161			—
Curtailment expense (gain)	254			(4		)	—
Net periodic expense	$	18,930		$	11,789		$	7,339
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	253		$	386		$	454
Interest cost	661			645			810
Expected long-term return on assets	(1,122		)	(787		)	(741		)
Actuarial gain amortization	(653		)	(28		)	—
Transition obligation amortization	44			229			248
Net periodic (income) expense	$	(817	)	$	445		$	771

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



Years ended December 31, (in thousands)	2014			2013			2012
Pension Plans
Net actuarial (gain) loss experienced during the year	$	10,495		$	(14,138	)	$	28,748
Net actuarial loss recognized as expense	(25,433		)	(8,934		)	(4,908		)
Prior service cost recognized as expense	(246		)	(311		)	(340		)
Curtailment loss	(8,749		)	—			—
Total recognized in other comprehensive income (loss)	(23,933		)	(23,383		)	23,500
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	7,649		$	(8,057	)	$	(1,787	)
Net actuarial gain recognized as expense	1,908			550			—
Transition obligation recognized as expense	(48		)	(283		)	(294		)
Total recognized in other comprehensive income (loss)	$	9,509		$	(7,790	)	$	(2,081	)

In the first quarter of 2014, Energen incurred settlement charges of $6.9 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 in the first quarter of 2014, Energen incurred a settlement charge of $0.4 million for the payment of lump sums from the non-qualified supplemental retirement plans. In the second quarter of 2014, Energen incurred settlement charges of $0.4 million for the payment of lump sums from the qualified defined benefit pension plans. In the third quarter of 2014, Energen incurred a settlement charge of $26,000 for the payment of lump sums from the non-qualified supplemental retirement plans. Also in the third quarter of 2014, Energen incurred settlement charges of $0.3 million for the payment of lump sums from the qualified defined benefit pension plan. 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. Also in the fourth quarter of 2014, Energen incurred settlement

charges of $39,000 for the payment of lump sums from the qualified defined benefit pension plan. 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.

In the first quarter of 2013, Energen incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a regulatory asset at Alagasco. In the third quarter of 2013, Energen incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 was expensed and $46,000 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 from accumulated other comprehensive income into pension cost during 2015 are included in the table below. In addition, the Company anticipates recognizing the remaining amounts from accumulated other comprehensive income on the date of distribution of pension plan benefits.



(in thousands)
Amortization of net actuarial loss	$	841

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, 2014 , 2013 and 2012 .

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



Years ended December 31,	2014		2013		2012
Pension Plans
Discount rate	3.66	%	3.63	%	4.52	%
Expected long-term return on plan assets	7.00	%	7.00	%	7.00	%
Rate of compensation increase for pay-related plans	3.63	%	3.71	%	3.59	%
Postretirement Benefit Plans
Discount rate	4.88	%	4.36	%	4.95	%
Expected long-term return on plan assets	7.00	%	7.00	%	7.00	%
Rate of compensation increase	3.60	%	3.70	%	3.55	%

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 . The discount rate shown below represents the weighted average for both the defined qualified and nonqualified supplemental benefit plans. 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,	2014		2013
Pension Plans
Discount rate	0.96	%	4.29	%
Rate of compensation increase for pay-related plans	—	%	3.63	%
Postretirement Benefit Plans
Discount rate	4.25	%	4.95	%
Rate of compensation increase for pay-related plans	—	%	3.60	%

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,	2014		2013
Health care cost trend rate assumed for next year	7.25	%	6.50	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2021		2020

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: Due to the plan termination of our defined benefit plans, we have transitioned our investment strategy to reduce risk. We liquidated our equity and debt securities and have invested fully in cash and cash equivalents at year-end. We expect to hold these funds along with any additional contributions in cash until the benefits are fully distributed.

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		2014		2013		Target		2014		2013
Asset category:
Equity securities	—	%	—	%	34	%	60	%	60	%	61	%
Debt securities	—	%	—	%	28	%	40	%	40	%	39	%
Other	100	%	100	%	38	%	—	%	—	%	—	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

Equity securities for pension and 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, 2014
(in thousands)	Level 1		Level 2		Total
Cash and cash equivalents	$	67,542	$	—	$	67,542
Total	$	67,542	$	—	$	67,542



	December 31, 2013
(in thousands)	Level 1		Level 2		Total
United States equities	$	34,117	$	—	$	34,117
Global equities	20,144		8,636		28,780
Fixed income	—		50,777		50,777
Alternative investments	—		37,292		37,292
Cash and cash equivalents	5,970		36,521		42,491
Total	$	60,231	$	133,226	$	193,457

Pension plan assets at December 31, 2013 include the assets of Alagasco. Energen had no Level 3 pension plan assets. United States equities consist of mutual and commingled funds with varying strategies. Such strategies include stock investments across market capitalizations and investment styles. Global equities consist of mutual funds and a limited partnership that invest in United States and non-United States securities broadly diversified across mostly developed markets but with some tactical exposure to emerging markets. Fixed income securities consist of mutual funds and separate accounts. Fixed income securities are well diversified with allocations to investment grade and non-investment grade issues and issues that provide both intermediate and longer duration exposure. Alternative investments consist of limited partnerships and commingled and mutual funds with varying investment strategies. Alternative investments are meant to serve as a risk reducer at the total portfolio level as they provide asset class exposures not found elsewhere in the portfolio.

The following is a reconciliation of plan assets in Level 3 of the fair value hierarchy:



Years ended December 31, (in thousands)	2013			2012
Balance at beginning of period	$	14,500		$	17,399
Unrealized gains (losses)	—			992
Unrealized gains relating to instruments held at the reporting date	—			242
Settlements	—			(4,948		)
Purchases	—			815
Transfer out of Level 3	(14,500		)	—
Balance at end of period	$	—		$	14,500

Transfer of Alternative Investments: For the year ended December 31, 2014 there were no significant transfers in or out of Levels 1, 2, or 3. During 2013, Energen determined that its alternative investments meet the requirements to be categorized as Level 2 fair value measurement. The alternative investments consist of three investments that are measured at net asset value. Net asset value per share serves as an estimate for the fair value of an investment as long as certain requirements are met.

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



	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



	December 31, 2013
(in thousands)	Level 1		Level 2		Total
United States equities	$	24,152	$	—	$	24,152
Global equities	9,563		—		9,563
Fixed income	—		21,744		21,744
Total	$	33,715	$	21,744	$	55,459

Postretirement benefit plan assets at December 31, 2013 include the assets of Alagasco. 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: During 2015, Energen anticipates an additional contribution of $13.7 million in order to complete the distribution of plan assets related to the plan termination. The Company expects to make benefit payments, which will be funded by the Rabbi Trust, of approximately $11.0 million during 2015 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
2015	$92,711	$324
2016	$14,601	$397
2017	$113	$472
2018	$110	$541
2019	$107	$583
2020-2024	$484	$3,266

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 $3.7 million , $3.7 million and $3.3 million for the years ended December 31, 2014 , 2013 and 2012 , respectively.

Stock Incentive Plan: The Stock Incentive Plan provided for the grant of incentive stock options and non-qualified stock options to officers and key employees. The Stock Incentive Plan also provided for the grant of performance share awards and restricted stock units. Energen has typically funded options, restricted stock obligations and performance share obligations through original issue shares and restricted stock through treasury shares. Under the Stock Incentive Plan, 8,600,000 shares of Energen common stock were reserved for issuance with 2,635,544 remaining for issuance as of December 31, 2014 .

Performance Share Awards: The Stock Incentive Plan provided for the grant of performance share awards, with each unit equal to the market value of one share of common stock, 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.

No performance share awards were granted in 2012 . A summary of performance share award activity as of December 31, 2014 , and transactions during the years ended December 31, 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

Energen recorded expense of $6.2 million and $3.8 million for the years ended December 31, 2014 and 2013, respectively, for performance share awards with a related deferred income tax benefit of $2.3 million and $1.4 million . During the year ended December 31, 2012, Energen recorded no expense for performance share awards. As of December 31, 2014, there was $5.6 million of total unrecognized compensation cost related to performance share awards. These awards have a remaining weighted average requisite service period of 1.45 years.

Stock Options: The Stock Incentive Plan provided for the grant of incentive stock options, non-qualified 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, 2014 , and transactions during the years ended December 31, 2014 , 2013 and 2012 are presented below:



	Stock Incentive Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2011	1,338,241		$	44.77
Granted	371,040		54.11
Exercised	(58,471	)	24.55
Forfeited	(2,335	)	46.45
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
Exercisable at December 31, 2012	987,733		$	43.75
Exercisable at December 31, 2013	713,445		$	49.80
Exercisable at December 31, 2014	454,938		$	51.88
Remaining reserved for issuance at December 31, 2014	2,635,544		—

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		1/25/2012
Awards granted	2,439	107,868	3,686	134,076		371,040
Fair market value of stock option at grant	$32.22	$27.57	$30.53	$16.66		$18.79
Expected life of award	5.8 years	5.8 years	5.8 years	5.8 years		5.8 years
Risk-free interest rate	1.93%	2.06%	1.79%	1.01	%	1.07	%
Annualized volatility rate	40.7%	40.7%	40.6%	40.3	%	39.6	%
Dividend yield	0.2%	0.8%	0.7%	1.2	%	1.0	%

Energen recorded stock option expense of $2.9 million , $3.4 million and $6.2 million during the years ended December 31, 2014 , 2013 and 2012 , respectively, with a related deferred tax benefit of $1.1 million , $1.3 million and $2.3 million , respectively.

The total intrinsic value of stock options exercised during the year ended December 31, 2014 , was $18.5 million . During the year ended December 31, 2014 , Energen received cash of $23.1 million from the exercise of stock options. Total intrinsic value for outstanding options as of December 31, 2014 , was $7.8 million and $5.4 million for exercisable options. The fair value of options vested for the year ended December 31, 2014 was $5.0 million . As of December 31, 2014 , there was $0.5 million of unrecognized compensation cost related to outstanding nonvested stock options.

The following table summarizes options outstanding as of December 31, 2014 :



Stock Incentive Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
$46.45	25,470	2.00 years
$60.56	48,560	3.00 years
$29.79	35,161	4.00 years
$46.69	26,481	5.00 years
$54.99	111,487	6.00 years
$54.11	271,848	7.00 years
$48.36	124,071	8.00 years
$80.48	3,686	8.79 years
$72.39	107,868	9.00 years
$79.63	2,439	9.00 years
$29.79-$80.48	757,071	6.68 years

The weighted average remaining contractual life of currently exercisable stock options is 5.79 years as of December 31, 2014 .

Restricted Stock: In addition, the Stock Incentive Plan provided for the grant of restricted stock units which have been valued based on the quoted market price of Energen’s common stock at the date of grant. Restricted stock units vest within three years from grant date. A summary of restricted stock unit activity as of December 31, 2014 , and transactions during the years ended December 31, 2014 , 2013 and 2012 is presented below:



	Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2011	9,275		$	42.99
Granted	11,115		45.24
Vested	(9,275	)	42.97
Nonvested at December 31, 2012	11,115		45.24
Granted	52,650		52.34
Forfeited	(1,247	)	48.36
Nonvested at December 31, 2013	62,518		51.16
Granted	48,904		71.91
Vested	(11,848	)	65.94
Nonvested at December 31, 2014	99,574		$	59.60

Energen recorded expense of $3.2 million , $1.9 million and $0.1 million for the years ended December 31, 2014 , 2013 and 2012 , respectively, related to restricted stock units, with a related deferred income tax benefit of $1.2 million , $0.7 million and $23,000 , respectively. As of December 31, 2014 , there was $1.3 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 1.46 years.

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, 2014 , and transactions during the years ended December 31, 2014 , 2013 and 2012 are presented below:



	Stock Appreciation Rights Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2011	777,218		$	42.00
Exercised/forfeited	(124,188	)	30.90
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

Energen issued the following awards with stock appreciation rights. Energen uses the Black-Scholes pricing model to calculate the fair values of the options 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, 2014 :



Grant date	1/22/2014	1/24/2013	1/24/2013	1/26/2011	1/26/2011
			(modified)		(modified)
Awards granted	62,749	87,069	931	182,199	7,785
Fair market value of award	$18.63	$25.93	$20.14	$19.15	$16.27
Expected life of award	5.56 years	4.57 years	2.0 years	3.04 years	2.0 years
Risk-free interest rate	1.77%	1.57%	0.65%	1.12%	0.65%
Annualized volatility rate	33.4%	33.4%	33.4%	33.4%	33.4%
Dividend yield	0.13%	0.13%	0.13%	0.13%	0.13%



Grant date	1/27/2010	2/13-16/2009	1/28/2009	2/4/2008	2/1/2007
Awards granted	171,749	3,292	305,257	67,093	85,906
Fair market value of award	$22.50	$33.23	$34.66	$10.57	$19.25
Expected life of award	2.54 years	2.04 years	2.04 years	1.55 years	1.04 years
Risk-free interest rate	0.90%	0.67%	0.67%	0.45%	0.26%
Annualized volatility rate	33.4%	33.4%	33.4%	33.4%	33.4%
Dividend yield	0.13%	0.13%	0.13%	0.13%	0.13%

Income associated with stock appreciation rights of $0.4 million and $0.9 million was recorded for the years ended December 31, 2014 and 2012. Expense associated with stock appreciation rights of $9.9 million was recorded for the year ended 2013. During the year ended December 31, 2014 , the total intrinsic value of stock appreciation rights exercised was $4.4 million . During the year ended December 31, 2014 , Energen paid $3.0 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, 2014 , and transactions during the years ended December 31, 2014 , 2013 and 2012 are presented below:



	Petrotech Incentive Plan
	Shares
Outstanding at December 31, 2011	11,061
Granted (three-year vesting period)	102,349
Granted (two-year vesting period)	3,768
Granted (18 month vesting period)	40,822
Paid	(3,281	)
Forfeited	(13,476	)
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

None of the awards issued included a market condition. Energen Resources recognized expense of $4.5 million , $6.2 million and $2.6 million during 2014 , 2013 and 2012 , 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, 2014 there were 691,222 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, 10,360 shares, 13,500 shares and 11,120 shares were awarded during the years ended December 31, 2014 , 2013 and 2012 , respectively, leaving 127,924 shares reserved for issuance as of December 31, 2014 .

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, replacing and superseding its prior stock repurchase authorizations. 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, 2013 and 2012 . As of December 31, 2014 , 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, 2014 , 2013 and 2012 , Energen acquired 32,768 shares, 14,766 shares and 5,459 shares, respectively, in connection with its stock compensation plans.

7. DERIVATIVE COMMODITY INSTRUMENTS

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, 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
Noncurrent derivative instruments	—		—			—		—		—		—
Total derivative assets	339,977		(17,640		)	322,337		—		—		322,337
Liabilities
Derivative instruments	18,628		(17,640		)	988		—		—		988
Noncurrent derivative instruments	—		—			—		—		—		—
Total derivative liabilities	18,628		(17,640		)	988		—		—		988
Total derivatives	$	321,349	$	—		$	321,349	$	—	$	—	$	321,349



(in thousands)	December 31, 2013
										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	$	36,223		$	(18,760	)	$	17,463		$	—	$	—	$	17,463
Noncurrent derivative instruments	7,992			(2,553		)	5,439			—		—		5,439
Total derivative assets	44,215			(21,313		)	22,902			—		—		22,902
Liabilities
Derivative instruments	49,062			(18,760		)	30,302			—		—		30,302
Noncurrent derivative instruments	2,553			(2,553		)	—			—		—		—
Total derivative liabilities	51,615			(21,313		)	30,302			—		—		30,302
Total derivatives	$	(7,400	)	$	—		$	(7,400	)	$	—	$	—	$	(7,400	)

Energen had a net $8.2 million deferred tax liability included in current deferred income taxes on the balance sheets related to derivative items included in accumulated other comprehensive income as of December 31, 2013.

gain position with thirteen of our active counterparties and in a net loss position with the remaining one at December 31, 2014 . The largest counterparty net gain positions at December 31, 2014 , J.P. Morgan Ventures Energy Corporation, Merrill Lynch Commodities, Inc., Barclays Bank PLC, Morgan Stanley Capital Group Inc., Canadian Imperial Bank of Commerce and Bank of Montreal, constituted approximately $58.5 million , $46.3 million , $39.0 million , $35.2 million , $34.9 million and $34.3 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			2012
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $23, ($6,660) and $40,720	—	$	37	$	(10,866	)	$	66,438
Gain reclassified from accumulated other comprehensive income into income (effective portion)	Gain (loss) on derivative instruments, net	$	21,612	$	34,293		$	52,694
Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Gain (loss) on derivative instruments, net	$	—	$	835		$	(5,340	)

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	2014		2013			2012
Gain (loss) recognized in income on derivative	Gain (loss) on derivative instruments, net	$	313,408	$	(73,980	)	$	61,841

During 2013, we had a discontinuance of hedge accounting when Energen determined it was probable certain forecasted volumes would not occur due to certain properties being sold. This discontinuance of hedge accounting resulted in $1.5 million of after-tax losses being recognized into gain (loss) on derivative instruments, net during the year ended December 31, 2014.

As of December 31, 2014, Energen entered into the following transactions for 2015 and subsequent years:



Production Period	Total Hedged Volumes		Average Contract Price	Description
Oil
2015	8,280	MBbl	$89.30 Bbl	NYMEX Swaps
Oil Basis Differential
2015	2,160	MBbl	$(4.30) Bbl	WTS/WTI Basis Swaps*
2015	6,840	MBbl	$(4.82) Bbl	WTI/WTI Basis Swaps**
Natural Gas
2015	23.0	Bcf	$4.13 Mcf	Basin Specific Swaps - San Juan
2015	8.0	Bcf	$4.25 Mcf	Basin Specific Swaps - Permian
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

As of December 31, 2014 , the maximum term over which Energen has hedged exposures to the variability of cash flows is through December 31, 2015.

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



	December 31, 2013
(in thousands)	Level 2			Level 3			Total
Assets
Derivative instruments	$	(1,658	)	$	19,121		$	17,463
Noncurrent derivative instruments	4,383			1,056			5,439
Total assets	2,725			20,177			22,902
Liabilities
Derivative instruments	(28,414		)	(1,888		)	(30,302		)
Total liabilities	(28,414		)	(1,888		)	(30,302		)
Net derivative asset (liability)	$	(25,689	)	$	18,289		$	(7,400	)

At December 31, 2014, Energen had interest rate swap agreements with a notional of $133 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 $0.8 million and a $1.8 million liability at December 31, 2014 and 2013, 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 $6.7 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)	2014			2013			2012
Balance at beginning of period	$	18,289		$	89,019		$	65,801
Realized gains	22,208			55,210			63,720
Unrealized gains (losses) relating to instruments held at the reporting date*	2,981			(71,367		)	22,160
Settlements during period	(19,042		)	(54,573		)	(62,662		)
Balance at end of period**	$	24,436		$	18,289		$	89,019

*Includes $20.2 million in mark-to-market gains, $7.6 million in mark-to-market losses and $19.9 million in mark-to-market gains for the years ended December 31, 2014, 2013 and 2012, respectively.

**Included in the Level 3 fair value at December 31, 2014 are gains of $3.2 million from natural gas liquids and Gas Daily contracts which were closed at December 31, 2014 but not cash settled.

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, 2014			Valuation Technique*	Unobservable Input*	Range
Oil Basis - WTS/WTI
2015	$	(3,836	)	Discounted Cash Flow	Forward Basis	($2.55 - $2.66) Bbl
Oil Basis - WTI/WTI
2015	$	(14,419	)	Discounted Cash Flow	Forward Basis	($2.72 - $2.82) Bbl
Natural Gas Basis - San Juan
2015	$	28,597		Discounted Cash Flow	Forward Basis	($0.13- $0.14) Mcf
Natural Gas Basis - Permian
2015	$	10,927		Discounted Cash Flow	Forward Basis	($0.15) Mcf

*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 12, Asset Retirement Obligations, for further discussion related to these ARO’s. These assumptions are classified as Level 3 fair value.

Asset Impairments: Energen monitors 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, substantial 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 13, Asset Impairment, for impairments recognized by Energen during the years ended December 31, 2014, 2013 and 2012

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. The fair value of Energen’s long-term debt, including

the current portion and notes payable to banks, approximates $993.7 million and $1,650.9 million and has a carrying value of $1,039.0 million and $1,643.0 million at December 31, 2014 and 2013, respectively. The fair values were based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

Concentration of Credit Risk

Revenues and related accounts receivable from oil and natural gas operations primarily are generated from the sale of produced oil and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect Energen’s overall exposure to credit risk, either positively or negatively, in that our oil and natural gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen considers the credit quality of its purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The two largest purchasers of Energen’s oil and natural gas, Plains Marketing, LP (Plains) and HollyFrontier Corporation (HollyFrontier), accounted for approximately 39 percent and 15 percent, respectively, of Energen’s accounts receivable for commodity sales as of December 31, 2014 . Energen’s other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2014 . During the year ended December 31, 2014 , Plains and HollyFrontier accounted for approximately 37 percent and 13 percent , respectively, of total revenues. All other oil and natural gas purchasers each accounted for less than 10 percent of total revenues for the year ended December 31, 2014 .

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)	2014			2013			2012
Capitalized exploratory well costs at beginning of period	$	57,600		$	79,791		$	70,437
Additions pending determination of proved reserves	946,751			421,599			406,226
Reclassifications due to determination of proved reserves	(882,254		)	(442,909		)	(396,872		)
Exploratory well costs charged to expense	(2,658		)	(881		)	—
Capitalized exploratory well costs at end of period	$	119,439		$	57,600		$	79,791

The following table sets forth capitalized exploratory wells costs and includes amounts capitalized for a period greater than one year:



(in thousands)	December 31, 2014		December 31, 2013
Exploratory wells in progress	$	18,781	$	14,794
Capitalized exploratory well costs for a period of one year or less	100,658		42,481
Capitalized exploratory well costs for a period greater than one year	—		1,206
Total capitalized exploratory well costs	$	119,439	$	58,481

At December 31, 2014, Energen had 38 gross exploratory wells either drilling or waiting on results from completion and testing. These wells are primarily located in the Permian Basin.

10. RECONCILIATION OF EARNINGS PER SHARE



Years ended December 31,
(in thousands, except per share amounts)			2014					2013					2012
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	568,032	72,897	$	7.79	$	204,554	72,318	$	2.83	$	253,562	72,119	$	3.52
Effect of dilutive securities
Stock options			216					112					196
Non-vested restricted stock			58					20					1
Performance share awards			104					21					—
Diluted EPS	$	568,032	73,275	$	7.75	$	204,554	72,471	$	2.82	$	253,562	72,316	$	3.51

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

11. 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 5.4 MMBOE through August 2017 .

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.

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, Energen Resources is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. We estimate that the cleanup, remediation and related costs will approximate $2.5 million of which $1.9 million has been incurred.

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.

Energen Resources previously disclosed an adverse judgment relating to the ownership of the Company operated Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. Upon a Motion to Reconsider, the adverse judgment was vacated by the District Court in Ward County, Texas and a Summary Judgment Order has been entered confirming Energen Resources’ superior title to the Cadenhead Well and its associated oil and gas leases.

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.

Lease Obligations: Energen’s total lease payments included as operating lease expense were $24.1 million , $25.0 million and $20.9 million for the years ended December 31, 2014 , 2013 and 2012 , respectively. Minimum future rental payments required after 2014 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:



Years Ending December 31, (in thousands)
2015	2016	2017	2018	2019	2020 and thereafter
$2,698	$2,676	$2,468	$2,429	$2,326	$—

12. 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, 2011	$	107,340
Liabilities incurred	3,994
Liabilities settled	(845		)
Accretion expense (including discontinued operations of $1,195)	7,534
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

*Asset retirement obligation associated with North Louisiana/East Texas properties are included as liabilities related to assets held for sale in current liabilities on the balance sheet.

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

13. ASSET IMPAIRMENT

Impairments recognized by Energen during the years ended December 31, 2014, 2013 and 2012 are presented below:



Years ended December 31, (in thousands)	2014		2013		2012
Continuing operations
Permian Basin oil properties	$	125,693	$	—	$	—
Permian Basin unproved leasehold properties	55,063		13,906		6,304
San Juan Basin natural gas properties	236,045		—		—
Total asset impairments from continuing operations	416,801		13,906		6,304
Discontinued operations
North Louisiana/East Texas oil and natural gas properties	1,936		29,794		—
East Texas oil and natural gas properties	—		—		21,545
Total asset impairments from discontinued operations	1,936		29,794		21,545
Total asset impairments	$	418,737	$	43,700	$	27,849

During the third and fourth quarters of 2014, non-cash impairment writedowns of $147.9 million pre-tax and $88.1 million pre-tax, 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. These non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement. At December 31, 2014, proved reserves associated with Energen’s San Juan Basin properties totaled 69,043 MBOE.

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 in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. 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.

In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). 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.

During the first quarter of 2012, Energen recognized a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in income from discontinued operations for the year ended December 31, 2012. The impairment was caused by the impact of lower future natural gas prices. This impairment writedown is classified as Level 3 fair value.

14. ACQUISITION AND DISPOSITION OF PROPERTIES

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.

On February 21, 2012, Energen Resources entered into a definitive agreement with BHP Billiton (BHP) to buy a 50 percent undivided interest in three existing wells in Reeves County, Texas, from Energen Resources for approximately $18 million . Following the purchase of the wells, BHP completed two of the wells and earned a 50 percent undivided interest in 4,829 net acres. The agreement also included the option for BHP to purchase from Energen Resources a 50 percent undivided interest in 51,720 net acres in the Permian Basin. On May 1, 2012, BHP elected not to exercise the option.

On February 14, 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million . This purchase had an effective date of December 1, 2011. Energen acquired total proved reserves of approximately 8.2 MMBOE. Of the proved reserves acquired, an estimated 81 percent are undeveloped. Approximately 64 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of February 14, 2012 (including the effects of closing adjustments).



(in thousands)
Consideration given
Cash (net)	$	67,615
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	65,581
Unproved leasehold properties	911
Accounts receivable	1,358
Accounts payable	(25		)
Asset retirement obligation	(210		)
Total identifiable net assets	$	67,615

Included in the Company’s consolidated results of operations for the year ended December 31, 2012, were $11.7 million of operating revenues and $3.1 million in operating income resulting from the operation of the properties acquired above.

In December 2012, Energen completed the purchase of liquids-rich properties in the Permian Basin for a cash purchase price of approximately $18.7 million . During 2012, Energen also completed a total of approximately $18 million in various purchases of unproved leasehold properties.

15. DISCONTINUED OPERATIONS AND HELD FOR SALE PROPERTIES

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, 2013 and 2012 and our financial position as of December 31, 2014 and 2013 presented in our consolidated financial statements and these notes reflect Alagasco as discontinued operations.

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 in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. 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.

As discussed in Note 14, Acquisition and Disposition of Properties, and above, the following tables detail held for sale properties by major classes of assets and liabilities:



(in thousands)	December 31, 2014
		San Juan Basin*
Oil and natural gas properties		$	1,166,124
Less accumulated depreciation, depletion and amortization		(770,327		)
Total assets held for sale		395,797
Other long-term liabilities		(24,230		)
Total liabilities held for sale		(24,230		)
Total net assets held for sale		$	371,567

*The San Juan Basin natural gas assets which are held for sale as of December 31, 2014, do not qualify for discontinued operations as we will have ongoing operations in the San Juan Basin.



(in thousands)	December 31, 2013
	Alabama Gas Corporation			Black Warrior Basin			North Louisiana/East Texas			Total
Cash	$	3,032		$	—		$	—		$	3,032
Accounts receivable*	103,748			2,829			1,272			107,849
Inventories	41,200			—			68			41,268
Oil and natural gas properties	—			—			348,379			348,379
Less accumulated depreciation, depletion and amortization	—						(301,609		)	(301,609		)
Utility plant	1,491,433			—			—			1,491,433
Less accumulated depreciation	(605,924		)	—			—			(605,924		)
Other property, net	41			—			165			206
Other current assets*	29,458			—			—			29,458
Other long-term assets	128,780			—			—			128,780
Total assets held for sale	1,191,768			2,829			48,275			1,242,872
Accounts payable	(48,653		)	(1,732		)	(11		)	(50,396		)
Royalty payable	—			(550		)	(869		)	(1,419		)
Accrued taxes	(28,027		)	—			—			(28,027		)
Notes payable to banks	(50,000		)	—			—			(50,000		)
Other current liabilities*	(105,013		)	(379		)	(21		)	(105,413		)
Other long-term liabilities	(331,409		)	—			(14,983		)	(346,392		)
Long-term debt	(249,923		)	—			—			(249,923		)
Total liabilities held for sale	(813,025		)	(2,661		)	(15,884		)	(831,570		)
Total net assets held for sale	$	378,743		$	168		$	32,391		$	411,302

*At December 31, 2013, Alagasco’s accounts receivable included a consolidating adjustment of $4.7 million to adjust for affiliated companies receivables. Certain other current assets and other current liabilities at Alagasco of $1.6 million and $0.5 million , respectively, were reclassified to continuing operations at Energen.

We recognized interest on debt required to be extinguished in connection with the sale of Alagasco as discontinued operations. On September 2, 2014, Energen entered into a $1.5 billion five -year syndicated secured credit facility with domestic and foreign lenders. The credit facility was amended to $2.0 billion on November 17, 2014. This credit facility refinances and replaces the $1.25 billion five -year syndicated unsecured credit facility entered into on October 30, 2012. The interest associated with the October 2012 five-year syndicated unsecured credit facilities was classified as discontinued operations. See Note 2, Summary of Significant Accounting Policies, for further information regarding adjustments associated with the sale of Alagasco.



Years ended December 31, (in thousands, except per share data)	2014		2013		2012
Natural gas distribution revenues	$	397,648	$	533,338	$	451,589
Oil and natural gas revenues	5,199		60,191		76,350
Total revenues	$	402,847	$	593,529	$	527,939
Pretax income from discontinued operations	$	47,220	$	92,253	$	79,197
Income tax expense	17,928		33,174		30,256
Income From Discontinued Operations	$	29,292	$	59,079	$	48,941
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	$	48,941
Diluted Earnings Per Average Common Share
Income from discontinued operations	$	0.40	$	0.81	$	0.68
Gain on disposal of discontinued operations, net	5.99		0.05		—
Total Income From Discontinued Operations	$	6.39	$	0.86	$	0.68
Basic Earnings Per Average Common Share
Income from discontinued operations	$	0.40	$	0.82	$	0.68
Gain on disposal of discontinued operations, net	6.02		0.05		—
Total Income From Discontinued Operations	$	6.42	$	0.87	$	0.68

16. SUPPLEMENTAL CASH FLOW INFORMATION

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



Years ended December 31, (in thousands)	2014		2013		2012
Interest paid, net of amount capitalized	$	32,172	$	38,255	$	46,224
Income taxes paid	$	219,505	$	22,781	$	18,023
Noncash investing activities:
Accrued development, exploration costs and other capital	$	207,461	$	93,623	$	116,488
Capitalized asset retirement obligations costs	$	2,958	$	2,772	$	3,994
Capital lease obligations	$	—	$	—	$	5,072
Receivable from sale of Alabama Gas Corporation	$	8,247	$	—	$	—
Noncash financing activities:
Issuance of common stock for employee benefit plans	$	2,448	$	1,015	$	838
Treasury stock acquired in connection with tax withholdings	$	2,547	$	977	$	277

17. 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)	Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2013	$	12,178		$	(32,245	)	$	(20,067	)
Other comprehensive loss before reclassifications	(261		)	(5,056		)	(5,317		)
Amounts reclassified from accumulated other comprehensive income (loss)	(11,917		)	14,431			2,514
Change in accumulated other comprehensive income (loss)	(12,178		)	9,375			(2,803		)
Balance as of December 31, 2014	$	—		$	(22,870	)	$	(22,870	)

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



Years ended December 31, (in thousands)	2014			2013
(in thousands)	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*	(21,932		)	(12,357		)	General and administrative
Actuarial losses on settlement charges*	—			(421		)	Assets held for sale
Total pension and postretirement plans	(22,202		)	(13,354		)
Income tax benefit	7,771			4,674
Net of tax	(14,431		)	(8,680		)
Total reclassifications for the period	$	(2,514	)	$	12,324

*In the first quarter of 2013, Energen incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 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. In the third quarter of 2013, Energen incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 was recognized in actuarial losses above and $46,000 was recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

18. RECENTLY ISSUED ACCOUNTING STANDARDS

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (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 is effective for all annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. Energen does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

19. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

The following data summarizes quarterly operating results.



	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		)	—			—		—
Adjusted revenues	$	297,278		$	270,097		$	497,761	$	611,435
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



	Year ended December 31, 2013
(in thousands, except per share amounts)	First			Second			Third			Fourth
Revenues as originally reported	$	492,679		$	490,057		$	320,406		$	472,733
Discontinued operations*	(256,348		)	(123,076		)	(48,368		)	(142,771		)
Adjusted revenues	$	236,331		$	366,981		$	272,038		$	329,962
Operating income as originally reported	$	105,336		$	146,304		$	(4,052	)	$	110,630
Discontinued operations*	(84,146		)	(7,667		)	21,487			(35,755		)
Adjusted operating income	$	21,190		$	138,637		$	17,435		$	74,875
Income from continuing operations	$	8,419		$	82,422		$	5,407		$	45,633
Net income (loss)	$	56,692		$	83,067		$	(19,298	)	$	84,093
Diluted earnings per average common share
Continuing operations	$	0.12		$	1.14		$	0.07		$	0.62
Net income (loss)	$	0.78		$	1.15		$	(0.27	)	$	1.15
Basic earnings per average common share
Continuing operations	$	0.12		$	1.14		$	0.07		$	0.63
Net income (loss)	$	0.79		$	1.15		$	(0.27	)	$	1.16

*As discussed in Note 15, 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. During the fourth quarter of 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama. The property was classified as held for sale and reflected in discontinued operations during the third quarter of 2013. Also, during the third quarter of 2013, Energen classified its North Louisiana/East Texas natural gas and oil properties as held for sale and reflected the associated operating results in discontinued operations.

20. OIL AND NATURAL GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:



(in thousands)	December 31, 2014		December 31, 2013
Proved	$	8,069,638	$	7,043,779
Unproved	142,340		168,975
Total capitalized costs	8,211,978		7,212,754
Accumulated depreciation, depletion and amortization	2,663,434		2,078,411
Capitalized costs, net	$	5,548,544	$	5,134,343

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)	2014		2013		2012
Property acquisition:
Proved	$	2,582	$	4,661	$	79,862
Unproved	68,514		26,820		58,634
Exploration	972,164		435,636		419,284
Development	408,949		655,353		749,256
Total costs incurred	$	1,452,209	$	1,122,470	$	1,307,036

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)	2014		2013		2012
Gross revenues*	$	1,679,213	$	1,206,293	$	1,090,948
Production (lifting costs)	376,495		351,541		278,193
Exploration expense	28,090		14,036		13,052
Depreciation, depletion and amortization including asset impairments	960,539		463,606		345,873
Accretion expense	7,608		6,995		6,339
Income tax expense	99,469		128,773		160,551
Results of operations from producing activities	$	207,012	$	241,342	$	286,940

* The years ended December 31, 2014, 2013 and 2012 gross revenues include a pre-tax non-cash mark-to-market gain on derivatives of $315.4 million , a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million and a pre-tax non-cash mark-to-market gain on derivatives of $58.8 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, 2014 , 2013 and 2012 . 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 T. Scott Hickman and Associates, Inc. (T. Scott Hickman), 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, 2014 . Ryder Scott audited the proved reserve estimates for coalbed methane in the San Juan Basin and substantially all of the Permian Basin proved reserves. T. Scott Hickman 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, 2014	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	164,870		63,011		719,725		347.8
Revisions of previous estimates	(48,548	)	(15,165	)	(71,806	)	(75.7	)
Purchases	88		26		116		0.1
Extensions and discoveries	76,722		29,695		141,209		130.0
Production	(11,818	)	(4,104	)	(59,562	)	(25.8	)
Sales	(87	)	—		(21,756	)	(3.7	)
Proved reserves at end of period	181,227		73,463		707,926		372.7
Proved developed reserves at end of period	118,697		47,621		589,074		264.5
Proved undeveloped reserves at end of period	62,530		25,842		118,852		108.2



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



Year ended December 31, 2012	Oil MBbl		NGL MBbl		Natural Gas MMcf		Total MMBOE
Proved reserves at beginning of period	129,578		53,957		957,368		343.1
Revisions of previous estimates	(8,546	)	(9,557	)	(143,704	)	(42.1	)
Purchases	7,950		2,569		10,656		12.4
Extensions and discoveries	35,132		11,759		61,170		57.1
Production	(8,766	)	(2,573	)	(76,362	)	(24.1	)
Proved reserves at end of period	155,348		56,155		809,128		346.4
Proved developed reserves at end of period	105,976		36,440		708,657		260.5
Proved undeveloped reserves at end of period	49,372		19,715		100,471		85.9

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.

2012 Activities: Energen had downward reserve revisions during 2012 which totaled 42.1 MMBOE. The Black Warrior Basin had downward reserve revisions totaling 5.1 MMBOE of which approximately 5.9 MMBOE related to estimated negative price related revisions partially offset by better well performance. The San Juan Basin downward reserve revisions of 19.7 MMBOE included 22.5 MMBOE in negative price related revisions partially offset by better well performance, lower operating costs and lower fuel usage. Downward reserve revisions of 15.8 MMBOE in the Permian Basin were primarily due to lower than anticipated performance in certain development wells along with 1.0 MMBOE of estimated negative price related revisions.

Energen purchased 12.4 MMBOE of reserves during 2012 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2012, Energen had extensions and discoveries of 57.1 MMBOE of which 59 percent were proved undeveloped reserves and 41 percent were proved developed reserves. Extension drilling resulted in 45.6 MMBOE of discoveries with exploratory drilling providing 11.5 MMBOE of discoveries. The San Juan Basin added 0.9 MMBOE of reserves through the drilling or identification of 6 well locations. The Permian Basin added 56.1 MMBOE of reserves primarily through the drilling or identification of 422 well locations.

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. At December 31, 2014 , 2013 and 2012 , Energen had a deferred hedging gain of $315.4 million , a deferred hedging gain of $21.6 million and a deferred hedging gain of $74.8 million , respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.



Years ended December 31, (in thousands)	2014		2013		2012
Future gross revenues	$	20,971,672	$	19,509,305	$	17,735,363
Future production costs	7,532,273		6,136,709		5,715,248
Future development costs	1,784,738		1,896,602		1,892,600
Future income tax expense	3,440,582		3,209,697		2,809,411
Future net cash flows	8,214,079		8,266,297		7,318,104
Discount at 10% per annum	3,994,423		4,248,456		3,618,785
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

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



Years ended December 31, (in thousands)	2014			2013			2012
Balance at beginning of year	$	4,017,841		$	3,699,319		$	3,629,163
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(1,147,028		)	566,838			(922,792		)
Net changes due to revisions in quantity estimates	(1,285,394		)	(81,762		)	(383,755		)
Development costs incurred, previously estimated	337,198			299,432			472,603
Accretion of discount	401,784			369,932			362,916
Changes in timing and other*	987,652			(179,502		)	(317,244		)
Total revisions	(705,788		)	974,938			(788,272		)
New field discoveries and extensions, net of future production and development costs	2,321,028			376,326			1,025,419
Sales of oil and gas produced, net of production costs	(1,054,553		)	(1,014,593		)	(812,781		)
Purchases	4,241			4,690			189,755
Sales	(21,092		)	(24,876		)	—
Net change in income taxes	(342,021		)	2,037			456,035
Net change in standardized measure of discounted future net cash flows	201,815			318,522			70,156
Balance at end of year	$	4,219,656		$	4,017,841		$	3,699,319

*Amount represents changes in production timing and other. 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.


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 of Energen Corporation 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.

Management assessed the effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2014 . 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, 2014 , Energen Corporation maintained effective internal control over financial reporting. The effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2014 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 of Energen Corporation 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.

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 April 30, 2015 . The definitive proxy statement will be filed on or about March 18, 2015 .

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 April 30, 2015 .


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 April 30, 2015 .

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 April 30, 2015 .

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, 2014:



Plan Category	Number of Securities to be Issued for Outstanding Options and Performance Share Awards	Weighted Average Exercise Price		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders*	757,071	$	54.88	3,454,690
Equity compensation plans not approved by security holders	—	—		—
Total	757,071	$	54.88	3,454,690

*These plans include 2,635,544 shares associated with Energen’s Stock Incentive Plan, 127,924 shares associated with the 1992 Energen Corporation Directors Stock Plan and 691,222 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 April 30, 2015 .

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 April 30, 2015 .

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.

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(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

*10(d)	Form of Executive Retirement Supplement Agreement between Energen Corporation and its executive officers (as revised October 2000) which was filed as Exhibit 10(c) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2000

*10(e)	Form of Amendment to Executive Retirement Supplement Agreement between Energen Corporation and its executive officers, dated December 12, 2007, which was filed as Exhibit 10(o) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2013

*10(f)	Form of Amendment to Executive Retirement Supplement Agreement, which was filed as Exhibit 10.2 to Energen’s Current Report on Form 8-K filed October 20, 2014



*10(g)	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(h)	Energen Corporation Stock Incentive Plan (as amended effective January 1, 2015)

*10(i)	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(j)	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(k)	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(l)	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(m)	Energen Corporation 1997 Deferred Compensation Plan (as amended and restated) effective October 22, 2014

*10(n)	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(o)	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 (T. Scott Hickman 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 – T. Scott Hickman 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, 2014 are formatted in XBRL

*Incorporated by reference

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)



March 2, 2015	By	/s/ J.T. McManus, II
	J.T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation;

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.



March 2, 2015	By	/s/ J.T. McManus, II
	J.T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation

March 2, 2015	By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

March 2, 2015	By	/s/ Russell E. Lynch, Jr.
	Russell E. Lynch, Jr. Vice President and Controller of Energen Corporation

March 2, 2015	*
	Kenneth W. Dewey Director

March 2, 2015	*
	M. James Gorrie Director

March 2, 2015	*
	Jay Grinney Director

March 2, 2015	*
	Frances Powell Hawes Director

	*By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Attorney-in-Fact

Exhibit 10(h)

ENERGEN CORPORATION

STOCK INCENTIVE PLAN

(As Amended Effective January 1, 2015)

The purpose of this Plan is to provide a means whereby Energen Corporation may, through the use of stock and stock related compensation, attract and retain persons of ability as employees and motivate such employees to exert their best efforts on behalf of Energen Corporation and its subsidiaries.

1. Definitions. As used in the Plan, the following terms have meanings indicated:

(a) “Adjusted Option Expiration Date” means:


(1)	in the event of a Qualified Termination due to Retirement, the earlier of the Expiration Date or the fifth anniversary of the termination date;


(2)	in the event of a Change in Control Termination or a Qualified Termination not due to Retirement, the earlier of the Expiration Date or the third anniversary of the termination date;


(3)	in the event of a termination of employment for Cause, immediately upon termination; and


(4)	in the event of a termination of employment not described in the foregoing clauses, the earlier of the Expiration Date or the ninetieth day following termination.


(b)	“Award” means any grant under the Plan of Incentive Stock Options, Nonqualified Stock Options, Restricted Stock, Restricted Stock Units and/or Performance Shares.


(c)	“Award Period” means the 3-year period (Energen fiscal years) commencing with the first day of the fiscal year in which the applicable Performance Share Award is granted, except as otherwise determined by the Committee at the time of grant and subject to the other provisions of this Plan.


(d)	“Board” means the Board of Directors of Energen.


(e)	“Cause” means any of the following:

(1)

The willful and continued failure by a Participant to substantially perform such Participant’s duties with Energen or a Subsidiary (other than any such failure resulting from such Participant’s incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to the Participant specifically identifying the manner in which such Participant has not substantially performed such Participant’s duties.


(2)	The engaging by a Participant in willful, reckless or grossly negligent misconduct which is demonstrably injurious to Energen or a Subsidiary monetarily or otherwise; or


(3)	The conviction of a Participant of a felony.

(f) "Change in Control" means: the occurrence of any one or more of the following:

(1)

The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a “Person”) of beneficial ownership (within the meaning of Rule 13(d)-3 promulgated under the Exchange Act) of 30% or more of either (i) the then outstanding shares of common stock of Energen (the “Outstanding Common Stock”) or (ii) the combined voting power of the then outstanding voting securities of Energen entitled to vote generally in the election of directors (the “Outstanding Voting Securities”); provided, however, that for purposes of this subsection (1) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by Energen or any corporation controlled by Energen shall not constitute a Change in Control;

(2)

Individuals who, as of December 1, 2012, constitute the Board of Directors of Energen (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board of Directors of Energen (the “Board of Directors”); provided, however that any individual becoming a director subsequent to such date whose election, or nomination for election by Energen’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board of Directors;

(3)

Consummation of a reorganization, merger or consolidation, or sale or other disposition of all or substantially all of the assets, of Energen (a “Business Combination”), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Common Stock and Outstanding Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns Energen or all or substantially all of Energen’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Common Stock and Outstanding Voting Securities, as the case may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of Energen or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 30%

or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board of Directors, providing for such Business Combination;

(1)

In addition to the above described Changes in Control, a Subsidiary Transaction (defined below) will constitute a Change in Control to the extent specified below. A “Subsidiary Transaction” is a transaction that results in securities representing 80% or more of the voting interests in a Subsidiary or substantially all of a Subsidiary’s assets being transferred to an entity not controlled by or under common control with Energen.


(i)	A Subsidiary Transaction involving a disposition of Energen’s largest Subsidiary or the assets of Energen’s largest Subsidiary will constitute a Change in Control if immediately prior to such transaction the Participant was an officer or employee of Energen or Energen’s largest Subsidiary. The largest Subsidiary is determined by net book value of property, plant and equipment.


(ii)	A Subsidiary Transaction involving a disposition of Energen Resources Corporation or its assets will constitute a Change in Control with respect to each Participant who immediately prior to the transaction was an officer or employee of Energen Resources Corporation.


(iii)	A Subsidiary Transaction involving a disposition of Alabama Gas Corporation or its assets will constitute a Change in Control with respect to each Participant who immediately prior to the transaction was an officer or employee of Alabama Gas Corporation.


(g)	“Change in Control Termination” means termination of a Participant’s employment with Energen and all Subsidiaries under either of the following circumstances:


(1)	an involuntary termination (other than for Cause) after the occurrence of a Change in Control; or


(2)	a voluntary termination for good reason entitling the Participant to severance compensation under a written change in control severance compensation agreement between Energen and the Participant.


(h)	“Code” means the Internal Revenue Code of 1986, as amended from time to time.


(i)	“Committee” means the Officers Review Committee of the Board or such other Committee of two or more directors as may be determined by the Board.


(j)	“Energen” means Energen Corporation and any successor corporation by merger or other reorganization.


(k)	“Employee” means any employee of one or more of Energen and the Subsidiaries.


(l)	“Exchange Act” means the Securities Exchange Act of 1934, as amended.


(m)	“Exercise Date” means the date on which a notice of option exercise is delivered to Energen pursuant to Section 6.2(c) or a notice of option cancellation is delivered to Energen pursuant to Section 6.2(i).


(n)	“Expiration Date” means the last day of the option period specified at the time of grant pursuant to Section 6.2(a).

(o)

“Fair Market Value” means, with respect to a share of Stock, the closing price of the Stock on the New York Stock Exchange (or such other exchange or system on which the Stock then trades or is quoted) or, if there is no trading of the Stock on the relevant date, then the closing price on the most recent trading date preceding the relevant date. With respect to other consideration, the term Fair Market Value means fair market value as may be reasonably determined by the Committee; provided that any valuation subject to Code Section 409A shall be made in accordance with Code Section 409A and the regulations thereunder.


(p)	“Incentive Stock Options” means options granted under the Plan to purchase Stock which at the time of grant qualify as “incentive stock options” within the meaning of Section 422 of the Code.


(q)	“Nonqualified Stock Options” means options granted under the Plan to purchase Stock which are not Incentive Stock Options.


(r)	“Participant” means an Employee who is selected by the Committee to receive an Award.


(a)	“Performance Measures” has the meaning set forth in Section 10.


(t)	“Performance Share” means the value equivalent of one share of Stock.


(u)	“Plan” means this Energen Corporation Stock Incentive Plan, as amended from time to time.


(v)	“Qualified Termination” means termination of a Participant’s employment with Energen and all Subsidiaries under any one of the following circumstances:


(1)	A result of Participant’s Retirement.


(2)	A result of the Participant’s death or disability.


(3)	Expressly agreed in writing by Energen and/or a Subsidiary to constitute a Qualified Termination for purposes of this Plan.


(w)	“Restricted Award” means an Award of Restricted Stock or Restricted Stock Units.


(x)	“Restricted Stock” means Stock granted to a Participant under Section 7 with respect to which the applicable Restrictions have not lapsed or been removed.


(y)	“Restricted Stock Unit” means the right to receive one share of Stock upon the lapse or removal of the applicable Restrictions.


(z)	“Restrictions” means the prohibitions set forth in Section 7.2(a) against the sale, assignment, transfer, pledge, hypothecation and other encumbering or disposal of Restricted Stock and against the payment of Restricted Stock Units.


(aa)	“Retirement” shall mean termination of employment by a Participant (other than for Cause) who is at least 55 years old and has at least 10 years of service with the Company and its subsidiaries.


(bb)	“Stock” means the common stock, par value $.01 per share, of Energen as such stock may be reclassified, converted or exchanged by reorganization, merger or otherwise.


(cc)	“Subsidiary” means any corporation, the majority of the outstanding voting stock of which is owned, directly or indirectly by Energen Corporation.


(dd)	“Ten Percent Shareholder” means an individual who, at the time of grant, owns stock possessing more than ten (10) percent of the total combined voting power of all classes of stock of Energen.


1.	Share Limitations.

2.1 Shares Subject to the Plan. Subject to adjustment in accordance with Section 3, as of April 27, 2011, 3,794,326 shares of Stock were reserved and available for issuance under the Plan for future Awards. (reflecting the original 650,000-share authorization, the 1998 stock split adjustment, an additional 1,500,000 shares authorized at the January 2002 shareholder meeting, the 2005 stock split adjustment and 3,000,000 shares authorized at the April 2011 shareholder meeting; reduced by prior Awards). Shares of Stock allocable to an Award or portion of an Award that is canceled by forfeiture, expiration or for any other reason (excepting pursuant to a stock appreciation right election under Section 6.2(i)) shall again be available for additional Awards. If any option granted under the Plan shall be canceled as to any shares of Stock pursuant to Section 6.2(i) (stock appreciation rights), then such shares of Stock shall not be available for the grant of another Award. Shares of Stock not issued as the result of the net exercise of a stock appreciation right, shares tendered by the Participant or retained by Energen as full or partial payment to Energen for the purchase of an Award or to satisfy tax withholding obligations in connection with an Award, or shares repurchased on the open market with the proceeds from the payment of an exercise price of an option shall not again be available for issuance under the Plan.

2.2 Limitations . Subject to adjustment in accordance with Section 3, (i) the maximum aggregate number of shares of Stock represented by all Awards granted to any one Participant during any one Energen fiscal year shall not exceed 400,000 calculated assuming maximum payout of the Awards and with each Restricted Stock Unit and Performance Share representing one share of Stock; (ii) consistent with clause (i), the maximum number of shares of Stock represented by Awards of Stock Options granted to any one Participant during any one Energen fiscal year shall not exceed 400,000; (iii) the maximum number of shares of Stock represented by all Restricted Stock and Performance Share Awards granted on or after April 27, 2011, shall not exceed 1,500,000; and (iv) the maximum number of shares of stock represented by Incentive Stock Options granted on or after April 27, 2011 shall not exceed 3,794,326.

3. Adjustments in Event of Change in Common Stock. In the event of any change in the Stock by reason of any stock dividend, extraordinary cash dividend, recapitalization, reorganization, merger, consolidation, split-up, spin-off, combination or exchange of shares, or rights offering to purchase Stock at a price substantially below fair market value, or of any similar change affecting the Stock, the number and kind of shares which thereafter may be available for issuance under the Plan and the terms of outstanding Awards shall be appropriately adjusted consistent with such change in such manner as the Committee may deem equitable to prevent dilution or enlargement of the rights granted to, or available for, Participants in the Plan. If the adjustment would result in fractional shares with respect to an Award, then the Committee may make such further adjustment (including, without limitation, the use of consideration other than Stock or rounding to the nearest whole number of shares) as the Committee shall deem appropriate to avoid the issuance of fractional shares.

4. Administration of the Plan. The Plan shall be administered by the Committee. No member of the Committee shall be eligible to participate in the Plan while serving as a member of the Committee. Subject to the provisions of the Plan, the Committee shall have the exclusive authority to select the Employees who are to be Participants in the Plan, to determine the Award to be made to each Participant, and to determine the conditions subject to which Awards will become payable under the Plan. The Committee shall have full power to administer and interpret the Plan and to adopt such rules and regulations consistent with the terms of the Plan as the Committee deems necessary or advisable in order to carry out the provisions of the Plan. The Committee’s interpretation and construction of the Plan and of any conditions applicable to Awards shall be conclusive and binding on all persons, including Energen and all Participants. Any action which can be taken, or authority which can be exercised, by the Committee with respect to the Plan, may also be taken or authorized by the Board.

5. Participation. Participants in the Plan shall be selected by the Committee from those Employees who, in the judgment of the Committee, have significantly contributed or can be expected to significantly contribute to Energen’s success.

6. Options

6.1 Grant of Options. Subject to the provisions of the Plan, the Committee may (a) determine and designate from time to time those Participants to whom options are to be granted and the number of shares of Stock to be optioned to each employee; (b) authorize the granting of Incentive Stock Options, Nonqualified Stock Options, or combination of Incentive Stock Options and Nonqualified Stock Options; (c) determine the number of shares subject to each option; (d) determine the time or times when each Option shall become exercisable and the duration of the exercise period; and (e) determine whether and, if applicable, the manner in which each option shall contain stock appreciation rights; provided, however, that (i) no Incentive Stock Option shall be granted after the expiration of ten years from the ISO Effective Date as defined in Section 14 and (ii) the aggregate Fair Market Value (determined as of the date the option is granted) of the Stock with respect to which Incentive Stock Options are exercisable for the first time by any employee during any calendar year (under all plans of Energen and its Subsidiaries) shall not exceed $100,000.

6.2 Terms and Conditions of Options. Each option granted under the Plan shall be evidenced by a written agreement. Such agreement shall be subject to the following express terms and conditions and to such other terms and conditions as the Committee may deem appropriate:

(a)

Option Period. Each option agreement shall specify the period for which the option thereunder is granted and shall provide that the option shall expire at the end of such period. The Committee may extend such period provided that, in the case of an Incentive Stock Option, such extensions shall not in any way disqualify the option as an Incentive Stock Option. In no case shall such period for an Incentive Stock Option, including any such extensions, exceed ten years from the date of grant, provided, however that, in the case of an Incentive Stock Option granted to a Ten Percent Shareholder, such period, including extensions, shall not exceed five years from the date of grant.

(b)

Option Price, No Repricing. The option price per share shall be determined by the Committee at the time any option is granted, and shall be not less than (i) the Fair Market Value, or (ii) in the case of an Incentive Stock Option granted to a Ten Percent Shareholder, 110 percent of the Fair Market Value, (but in no event less than the par value) of one share of Stock on the date the option is granted, as determined by the Committee. Except as otherwise permitted by Section 3, the terms of outstanding Awards may not be amended to reduce the exercise price of outstanding options or stock appreciation rights or cancel outstanding options or stock appreciation rights in exchange for cash, other awards or options with an exercise price that is less than the exercise price of the original options or stock appreciation rights without shareholder approval.

(c)

Exercise of Option. No part of any option may be exercised until the optionee shall have remained in the employ of Energen or of a Subsidiary for such period, if any, as the Committee may specify in the option agreement, and the option agreement may provide for exercisability in installments. The Committee shall have full authority to accelerate for any reason it deems appropriate the vesting schedule of all or any part of any option issued under the Plan. Each option shall be exercisable in whole or part on such date or dates and during such period and for such number of shares as shall be set forth in the applicable option agreement. An optionee electing to exercise an option shall give written notice to Energen of such election and of the number of shares the optionee has elected to purchase and shall at the time of exercise tender the full purchase price of the shares the optionee has elected to purchase plus any required withholding taxes in accordance with Sections 6.2(d) and 9.

(d)

Payment of Purchase Price upon Exercise. The purchase price of the shares as to which an option shall be exercised shall be paid to Energen at the time of exercise (i) in cash, (ii) in Stock already owned by the optionee having a total Fair Market Value equal to the purchase price and not subject to any lien, encumbrance or restriction on transfer other than pursuant to federal or state securities laws, (iii) by election to have Energen withhold (from the Stock to be delivered to the optionee upon such exercise) shares of Stock having a Fair Market Value equal to the purchase price or (iv) by any combination of such consideration having a total Fair Market Value equal to the purchase price; provided that the use of consideration described in clauses (ii), (iii) and (iv) shall be subject to approval by the Committee. In addition the Committee in its discretion may accept such other consideration or combination of consideration as the Committee shall deem to be appropriate and to have a total Fair Market Value equal to the purchase price. In each case, Fair Market Value shall be determined as of the Exercise Date.


(e)	Exercise in the Event of Termination of Employment.


(1)	Cause. If an optionee’s employment by Energen and all Subsidiaries shall terminate for Cause, then all options held by the terminated Employee shall immediately expire.


(2)	Qualified Termination . In the event of a Qualified Termination, then all options held by the optionee with a grant date at least ten months prior to the date of termination shall be immediately and fully vested and options with a grant date less than ten months prior to the date of termination shall immediately expire.


(3)	Change in Control Termination . In the event of a Change in Control Termination, all options held by the optionee which were granted prior to the Change in Control shall be immediately and fully vested.


(4)	Other Termination . In the event that an optionee’s employment by Energen and all Subsidiaries terminates for reason other than Cause, Qualified Termination or Change in Control Termination, then all of the optionee’s unvested options shall immediately expire.


(5)	Adjusted Option Expiration Date . Following a termination of employment any vested options held by the terminated employee will expire on the applicable Adjusted Option Expiration Date.

(6)

Committee Authority . The foregoing provisions of this Section 6.2(e) notwithstanding, the Committee shall have full authority to accelerate the vesting schedule of all or any part of any option issued under the Plan and held by an employee who plans to terminate his or her employment, such that a terminated employee, his heirs or personal representatives may exercise (at such time or times on or prior to the applicable Expiration Dates as may be specified by the Committee) any part or all of any unvested option under the Plan held by such employee at the date of his or her termination of employment. Furthermore, the Committee may at the time of grant provide for different or supplemental terms and conditions with respect to termination of employment and any such terms and conditions expressly provided in the written option agreement shall be controlling with respect to that option.


(7)	Options Granted Prior to January 31, 2012 . The other provisions of this Section 6.2(e) notwithstanding, the provisions of Section 6.2(e) of the Energen Corporation Stock Incentive Plan as Amended effective April 27, 2011, continue to control the manner in which options granted prior to January 31, 2012, will be treated upon a termination of employment.

(f)

Nontransferability . Except as may otherwise be provided in this Section 6.2(f), no option granted under the Plan shall be transferable other than by will or by the laws of descent and distribution and, during the lifetime of the optionee, an option shall be exercisable only by the optionee. The foregoing notwithstanding, the optionee may transfer Nonqualified Stock Options to (i) the optionee’s spouse or natural, adopted or step-children or grandchildren (including the optionee, “Immediate Family Members”), (ii) a trust for the benefit of one or more of the Immediate Family Members, (iii) a family charitable trust established by one or more of the Immediate Family Members, or (iv) a partnership in which the only partners are (and, except as may be otherwise agreed by

the Committee, will remain during the option period) one or more of the Immediate Family Members. Any options so transferred shall not be further transferable except in accordance with the terms of this Plan, shall remain subject to all terms and conditions of the Plan and the applicable option agreement, and may be exercised by the transferee only to the extent that the optionee would have been entitled to exercise the option had the option not been transferred.

(g)

Investment Representation. To the extent reasonably necessary to assure compliance with all applicable securities laws, upon demand by Energen for such a representation, the optionee shall deliver to Energen at the time of any exercise of an option or portion thereof or settlement of stock appreciation rights a written representation that the shares to be acquired upon such exercise are to be acquired for investment and not for resale or with a view to the distribution thereof. Upon such demand, delivery of such representation prior to the delivery of any shares issued upon exercise of an option and prior to the expiration of the option period shall be a condition precedent to the right of the optionee or such other person to purchase any shares.

(a)

Incentive Stock Options . Each option agreement which provides for the grant of an Incentive Stock Option to a participant shall contain such terms and provisions as the Committee may determine to be necessary or desirable in order to qualify such option as an “incentive stock option” within the meaning of Section 422 of the Code, or any amendment thereof or substitute therefor. As provided in Section 6.1, no Incentive Stock Option shall be granted after the expiration of ten years from the ISO Effective Date as defined in Section 14. Energen, in its discretion, may retain possession of any certificates for Stock delivered in connection with the exercise of an Incentive Stock Option or appropriately legend such certificates during the period that a disposition of such Stock would disqualify the exercised option from treatment as an incentive stock option under Section 422 of the Code (a “422 Option”). Subject to the other provisions of the Plan, Energen shall cooperate with the optionee should the optionee desire to make a disqualifying disposition. Any Incentive Stock Option which is disqualified from treatment as a 422 Option, for whatever reason, shall automatically become a Nonqualified Stock Option. No party has any obligation or responsibility to maintain an Incentive Stock Option’s status as a 422 Option. The optionee shall, however, immediately notify Energen of any disposition of Stock which would cause an Incentive Stock Option to be disqualified as a 422 Option.

(i)

Stock Appreciation Right . Each option agreement may provide that the optionee may from time to time elect, by written notice to Energen, to cancel all or any portion of the option then subject to exercise, in which event Energen's obligation in respect of such option shall be discharged by payment to the optionee of an amount in cash equal to the excess, if any, of the Fair Market Value as of the Exercise Date of the shares subject to the option or the portion thereof so canceled over the aggregate purchase price for such shares as set forth in the option agreement or, if mutually agreed by the Committee and the optionee, (i) the issuance or transfer to the optionee of shares of Stock with a Fair Market Value as of the Exercise Date equal to any such excess, or (ii) a combination of cash and shares of Stock with a combined value as of the Exercise Date equal to any such excess.


(j)	No Rights as Shareholder. No optionee shall have any rights as a shareholder with respect to any shares subject to the optionee’s option prior to the date of issuance to the optionee of a certificate or certificates for such shares.


(a)	Issuance of Shares. Subject to Section 6.2(h), as soon as reasonably practicable after receipt of an exercise notice and full payment, Energen shall issue to the optionee the appropriate number of shares of Stock.

7. Restricted Stock and Restricted Stock Units (Restricted Awards)

7.1 Grant of Restricted Awards. The Committee may make grants of Restricted Stock and/or Restricted Stock Units to Participants. Each Restricted Award shall be evidenced by a written agreement setting forth the number of shares of Restricted Stock or number of Restricted Stock Units granted and the terms and conditions to which the Restricted Award is subject. Restricted Awards may be granted by the Committee in its discretion with or without cash consideration.


7.2	Terms and Conditions of Restricted Stock.


(a)	Restrictions.


(1)	Restricted Stock . No shares of Restricted Stock may be sold, assigned, transferred, pledged, hypothecated, or otherwise encumbered or disposed of until the Restrictions on such shares have lapsed or been removed.


(2)	Restricted Stock Units. Restricted Stock Units will not be payable until the Restrictions on payment of such Restricted Stock Units have lapsed or been removed. Upon the lapse or removal of Restrictions on Restricted Stock Units the Restricted Stock Units shall be settled by delivering to the Participant the number of shares of Stock equal to the number of Restricted Stock Units being settled.


(b)	Lapse. The Committee shall establish as to each Restricted Award the terms and conditions upon which the Restrictions shall lapse, which terms and conditions may include, without limitation, a required period of service, Performance Measures, or any other individual or corporate performance conditions.

(c)

Termination of Employment. In the event of a Qualified Termination, then all Restrictions on the Participant's outstanding Restricted Awards with a grant date at least ten months prior to the date of termination shall immediately lapse and Restricted Awards with a grant date less than ten months prior to the date of termination shall be forfeited and returned to Energen. In the event of a Change in Control Termination, all Restrictions on the Participant’s outstanding Restricted Awards shall immediately lapse. Should a Participant’s employment with Energen and all Subsidiaries terminate for any reason other than a Qualified Termination or a Change in Control Termination, all Restricted Awards which remain subject to Restrictions, shall be forfeited and returned to Energen. The foregoing notwithstanding, the Committee may at the time of grant provide for different or supplemental terms and conditions with respect to termination of employment and any such terms and conditions expressly provided in the written Restricted Award agreement shall be controlling with respect to that Restricted Award.

NOTE: early lapse of Restrictions on Restricted Stock Units may have Section 409A implications; see Section 17.

(d)

Lapse at Discretion of Committee. The Committee may at any time, in its sole discretion, accelerate the time at which any or all Restrictions on a Restricted Award will lapse or remove any and all such Restrictions; provided that the Committee may not accelerate the lapse of or remove Restrictions which require the attainment of a Performance Measure except as may be permitted by the performance-based exception to Section 162(m) of the Code.

(e)

Rights with respect to Restricted Stock. Upon the acceptance by a Participant of an Award of Restricted Stock, such Participant shall, subject to the Restrictions, have all the rights of a shareholder with respect to such shares of Restricted Stock, including, but not limited to, the right to vote such shares of Restricted Stock and the right to receive all dividends and other distributions paid thereon. Certificates representing Restricted Stock may be held by Energen until the restrictions lapse and shall bear such restrictive legends as Energen shall deem appropriate.


(a)	No shareholder rights with respect to Restricted Units. A Participant shall have no rights of a shareholder, including voting, dividend or other distribution rights, with respect to Restricted Stock Units prior to the date they are settled in shares of Stock.


(b)	No Section 83(b) Election. Unless otherwise expressly agreed in writing by Energen, a Participant shall not make an election under Section 83(b) of the Code with respect to a Restricted Stock Award and upon the making of any such election, all shares of Restricted Stock subject to the election shall be forfeited and returned to Energen.


1.	Performance Shares


8.1	Grant of Performance Shares


(a)	The Committee may from time to time select employees to receive Performance Shares under the Plan. An Employee may be granted more than one Performance Share Award under the Plan.

(b)

A Performance Share Award shall not entitle a Participant to receive any dividends or dividend equivalents on Performance Shares; no Participant shall be entitled to exercise any voting or other rights of a shareholder with respect to any Performance Share Award under the Plan; and no Participant shall have any interest in or rights to receive any shares of Stock prior to the time when the Committee authorizes payment of Performance Shares pursuant to Section 8.2.

(c)

Payment of a Performance Share Award to any Participant shall be made in accordance with Section 8.2 and shall be subject to such conditions for payment as the Committee may prescribe at the time the Performance Share Award is made. The Committee may prescribe conditions such that payment of a Performance Share Award may be made with respect to a number of shares of Stock greater than the number of Performance Shares awarded. The Committee may prescribe different conditions for different Participants.


(a)	Each Performance Share Award shall be made in writing and shall set forth or otherwise reference the terms and conditions set by the Committee for payment of such Performance Share Award.

8.2

Payment of Performance Share Awards. Each Participant granted a Performance Share Award shall be entitled to payment on account thereof as of the close of the applicable Award Period, but only if the Committee has determined that the conditions for payment of the Award set by the Committee have been satisfied. Payment of Awards shall be made by Energen promptly following the determination by the Committee that payment has been earned and by March 15 of the year following the year in which the Award is earned. Payment shall be made in the form of shares of Stock.


8.3	Termination of Employment. Except in the case of a Qualified Termination or a Change in Control Termination, if, prior to the close of the Award Period with respect to a Performance Share Award, a Participant's employment with Energen and all Subsidiaries terminates, then any unpaid portion of such Participant's Performance Share Award shall be forfeited.

In the case of a Qualified Termination, the Participant shall remain entitled to payout of any outstanding Performance Share Awards with a grant date at least ten months prior to the date of termination (subject to the reduction described below) at the end of the applicable Award Period in accordance with the terms of this Plan including without limitation applicable performance conditions. Each of such outstanding Performance Share Awards shall be reduced to equal the number of Performance Shares originally granted multiplied by a fraction the numerator of which is the number of months from the beginning of the applicable Award period to the termination date and the denominator of which is the number of months in the applicable Award Period.

In the event of a Change in Control Termination, a Participant shall within thirty days following termination receive payment of all outstanding Performance Share Awards measured at target performance.


8.4	Consulting, Non-Compete and Confidentiality. A Participant’s entitlement, if any, to payout of Performance Share Awards subsequent to termination of employment with Energen and all Subsidiaries shall continue so long as the Participant is in compliance with the following requirements. Failure to comply shall result in forfeiture of all then outstanding Performance Share Awards.

(a)

Consulting Services. For a period of three years following the termination of the Participant’s employment (“Date of Termination”), Participant will fully assist and cooperate with Energen, the Subsidiaries and their representatives (including outside auditors, counsel and consultants) with respect to any matters with which the Participant was involved during the course of employment, including being available upon reasonable notice for interviews, consultation, and litigation preparation. Except as otherwise agreed by Participant, Participant’s obligation under this Section 8.4(a) shall not exceed 80 hours during the first year and 20 hours during each of the following two years. Such services shall be provided upon request of Energen and the Subsidiaries but scheduled to accommodate Participant’s reasonable scheduling requirements. Participant shall receive no additional fee for such services but shall be reimbursed all reasonable out-of-pocket expenses.

(b)

Non-Compete. For a period of twelve months following the Date of Termination, unless otherwise expressly approved in writing by Energen, the Participant shall not Compete, (as defined below) or assist others in Competing with Energen and the Subsidiaries. For purposes of this Agreement, “Compete” means (i) solicit in competition with Alabama Gas Corporation (“Alagasco”) any person or entity which was a customer of Alagasco at the Date of Termination; (ii) offer to acquire any local gas distribution system in the State of Alabama; or (iii) offer to acquire any oil or gas mineral interest (A) within an oil or gas unit for which Energen Resources Corporation is the operator of record or (B) within an oil or gas unit contiguous to an oil or gas unit for which Energen Resources Corporation is the operator of record. Employment by, or an investment of less than one percent of equity capital in, a person or entity which Competes with Energen or the Subsidiaries does not constitute Competition by Participant so long as Participant does not directly participate in, assist or advise with respect to such Competition.

(a)

Confidentiality. Participant agrees that at all times following the Date of Termination, Participant will not, without the prior written consent of Energen, disclose to any person, firm or corporation any confidential information of Energen or the Subsidiaries which is now known to Participant or which hereafter may become known to Participant as a result of Participant’s employment, unless such disclosure is required under the terms of a valid and effective subpoena or order issued by a court or governmental body; provided, however, that the foregoing shall not apply to confidential information which becomes publicly disseminated by means other than a breach of this provision.

8.5

No Assignment of Interest. Except as provided in Section 6.2(f), the interest of any person in the Plan shall not be assignable, either by voluntary assignment or by operation of law, and any assignment of such interest, whether voluntary or by operation of law, shall render the Award void. Amounts payable under the Plan shall be transferable only by will or by the laws of descent and distribution.

9. Withholding . Each Participant shall, no later than the date as of which the value of an Award first becomes includable in the gross income of the Participant for Federal, state or local income tax purposes, pay to Energen and Subsidiaries, or make arrangements satisfactory to the Committee, in its sole discretion, regarding payment of any Federal, state, or local taxes of any kind required by law to be withheld with respect to the Award together with any Federal (including FICA and FUTA), state, or local employment taxes required to be withheld. The obligations of Energen under the Plan shall be conditional on such payment or arrangements. Energen and, where applicable, its Subsidiaries shall, to the extent permitted by law, have the right to deduct any such taxes owed hereunder by a Participant from any payment of any kind otherwise due to said Participant. The Committee may permit Participants to elect to satisfy their Federal, and where applicable, state and local tax withholding obligations with respect to all Awards by the reduction, in an amount necessary to pay all said withholding tax obligations, of the number of shares of Stock or amount of cash otherwise issuable or payable to said Participants in respect of an Award.

10. Performance Measures. At its discretion, the Committee may make the Awards subject to the attainment of one or more Performance Measures designed to qualify for the performance-based exceptions from Section 162(m) of the Code. Unless and until Energen’s shareholders approve a change in the Performance Measures set forth in this Section 10, the Performance Measures to be used for purposes of such Awards shall be chosen from among the following alternatives, as

measured with respect to Energen and/or any one or more of the Subsidiaries, with or without comparison to a peer group:


(a)	return on shareholder’s equity;


(b)	return on assets;


(c)	net income;


(d)	earnings per common share;


(e)	total shareholder return;


(f)	oil and/or gas reserve additions;


(g)	utility customer number, volume and/or revenue growth; and


(h)	such other criteria as may be established by the Committee in writing and which meets the requirements of the performance-based exception to Section 162(m) of the Code.

In the event that the performance-based exception to Section 162(m) of the Code or its successor is amended such that the performance-based exception permits the employer to alter the governing performance measures without obtaining shareholder approval of such changes, the Committee shall have discretion to make such changes without obtaining shareholder approval

11. No Rights to Continued Employment. The Plan and any Award granted under the Plan shall not confer upon any Participant any right with respect to continuance of employment by Energen or any Subsidiary or any right to further Awards under the Plan, nor shall they interfere in any way with the right of Energen or any Subsidiary by which a Participant is employed to terminate the Participant’s employment at any time.

12. Compliance with Other Laws and Regulations. The Plan, the grant and fulfillment of Awards thereunder, and the obligations of Energen to sell, issue, release and/or deliver shares of Stock shall be subject to all applicable federal and state laws, rules, and regulations and to such approvals by any government or regulatory agency as may be required. Energen shall not be required to issue or deliver any certificates for shares of Stock prior to (a) the listing of such shares on any stock exchange on which the Stock may then be listed and (b) the completion of any registration or qualification of such shares under any federal or state law, or any ruling or regulation of any government body which Energen shall, in its sole discretion, determine to be necessary or advisable.

13. Amendment and Discontinuance. The Board may from time to time amend, suspend or discontinue the Plan. Subject to Section 17, without the written consent of a Participant, no amendment or suspension of the Plan shall alter or impair any Award previously granted to a Participant under the Plan.

14. Effective Date of the Plan. The original effective date of the Plan was November 25, 1997, the date of its adoption by the Board, subject to approval by the shareholders of Energen holding not less than a majority of the shares present and voting at its January 1998 Annual Meeting. From time to time the Board has made amendments to the Plan that require shareholder approval for effectiveness and the shareholders of Energen have approved such amendments, each of which is deemed to be a re-adoption by the Board and re-approval by the shareholders of the Plan for the

purposes of Code Section 422(b)(2). The “ISO Effective Date” is the earlier of the dates of such re-adoption and re-approval of the most recent shareholder approved Plan amendment or restatement.

15. Name . The Plan shall be known as the “Energen Corporation Stock Incentive Plan.”

16. 1997 Deferred Compensation Plan. If and to the extent permitted under the Energen Corporation 1997 Deferred Compensation Plan (the “Deferred Compensation Plan”), a Participant may elect, pursuant to the Deferred Compensation Plan, to defer receipt of part or all of any shares of Stock or other consideration deliverable under an Award and upon such deferral shall have no further right with respect to such deferred Award other than as provided under the Deferred Compensation Plan. In the event of such a deferral election, certificates for such shares of Stock as would have otherwise been issued under the Plan but for the deferral election, may at the discretion of Energen be delivered to the Trustee under the Deferred Compensation Plan and registered in the name of the Trustee or such other person as the Trustee may direct. Regardless of whether such deferred shares of Stock are issued to the Trustee, they shall constitute “issued” shares for purposes of the Plan’s maximum number of shares limitation set forth in Section 2.

17. Effect of Code Section 409A. Payments and benefits under this Plan are intended to be exempt from the requirements under Code section 409A (“Code Section 409A”) and all provisions of the Plan shall be interpreted in accordance with the applicable exemptions; there are, however, potential circumstances under which Plan payments and benefits may not be exempt from Code Section 409A. To the extent any payment or benefit is subject to Code Section 409A, the Plan shall be interpreted in accordance with Code Section 409A and Department of Treasury regulations and other interpretive guidance issued thereunder, including without limitation any such regulations or other guidance that may be issued after the date hereof. Notwithstanding any provision of the Plan to the contrary, in the event that Energen determines that any payments or benefits may or do not comply with Code Section 409A, Energen may amend the Plan (without Participant consent) or take any other actions that Energen determines are necessary or appropriate to (i) exempt the payments or benefits hereunder from the application of Code Section 409A or preserve the intended tax treatment of the payments and benefits provided hereunder, or (ii) comply with the requirements of Code Section 409A. Without limiting the generality of the foregoing, if and to the extent that any payment or benefit under this Plan is determined by Energen to constitute “nonqualified deferred compensation” subject to Code Section 409A, this Plan shall be administered accordingly, and any such payment provided to an employee who is a “specified employee” (within the meaning of Code Section 409A and as determined pursuant to procedures established by Energen) must be delayed for six months from the date of employment termination to comply with section 409A(a)(2)(B)(i) of the Code. Energen shall set aside those payments or benefits that would have been made but for payment delay required by the preceding sentence, and such amounts will be paid at the end of the delay. Notwithstanding the foregoing, neither Energen nor the Committee shall have any liability to any person in the event Code Section 409A applies to any Award in a manner that results in adverse tax consequences for a Participant.

Exhibit 10(m)

ENERGEN CORPORATION

1997 DEFERRED COMPENSATION PLAN

Amended and Restated effective as of October 22, 2014

Energen Corporation, an Alabama corporation, has previously established the Energen Corporation 1997 Deferred Compensation Plan, effective as of April 25, 1997 (the “Plan”), in order to provide deferred compensation to directors and certain key employees of Energen Corporation and its affiliated companies. The purpose of the Energen Corporation Deferred Compensation Plan is to assist Energen Corporation and its affiliated companies in retaining directors and key employees, encouraging their long term commitment to the company’s success, and attracting new directors and key employees by offering them an opportunity to defer compensation and participate in the success of Energen Corporation and its affiliated companies, and allowing them to share in increases in the value of Energen Corporation.

Section 409A of the Internal Revenue Code became effective January 1, 2005. Regulations issued pursuant to Section 409A require the Plan to be in compliance with the provisions of Section 409A, in form and operation, as of January 1, 2008. Energen Corporation hereby amends and restates the Plan effective January 1, 2008 to comply with Section 409A.

ARTICLE I.

DEFINITIONS

Section 1.1 Definitions . When used in this document with initial capital letters, the following terms have the meanings indicated unless a different meaning is plainly required by the context:

(a) “ Account ” or “ Accounts ” means the account or accounts established and maintained for a Participant pursuant to Article IV of the Plan. A Participant’s Account shall consist of the Participant’s Investment Account and the Participant’s Company Stock Account.

(b) “ Alagasco ” means Alabama Gas Corporation, a former subsidiary of Energen Corporation. Alagasco withdrew as a Participating Employer effective August 31, 2014.

(c) “ Allocation Request Form ” means such form or forms as may be approved by Energen from time to time for use by a Participant to request (i) an allocation of certain deferred compensation and/or an allocation or reallocation of the Participant’s Investment Account among available investment options pursuant to Section 7.2(c) and/or (ii) that certain deferred compensation be allocated to the Participant’s Company Stock Account pursuant to Section 7.1(e).

(d) “ Annual Incentive Compensation Plan ” means the Energen Corporation Annual Incentive Compensation Plan, as amended, as applicable to each Participant.

(e) “ Basin ” means Basin Pipeline Corporation, a subsidiary of Energen Corporation.

(f) “ Board of Directors ” means the Board of Directors of Energen Corporation.

(g) " Change in Control " means: the occurrence of any one or more of the following:

(1) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a “Person”) of beneficial ownership (within the meaning of Rule 13(d)-3 promulgated under the Exchange Act) of 25% or more of either (i) the then outstanding shares of common stock of Energen (the “Outstanding Common Stock”) or (ii) the combined voting power of the then outstanding voting securities of Energen entitled to vote generally in the election of directors (the “Outstanding Voting Securities”); provided, however, that for purposes of this subsection (1) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by Energen or any corporation controlled by Energen shall not constitute a Change in Control;

(2) Individuals who, as of October 1, 1999, constitute the Board of Directors of Energen (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board of Directors of Energen (the “Board of Directors”); provided, however that any individual becoming a director subsequent to such date whose election, or nomination for election by Energen’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board of Directors;

(3) Consummation of a reorganization, merger or consolidation, or sale or other disposition of all or substantially all of the assets, of Energen (a “Business Combination”), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Common Stock and Outstanding Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns Energen or all or substantially all of Energen’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Common Stock and Outstanding Voting Securities, as the case may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of Energen or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 25% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of

such corporation except to the extent that such ownership existed prior to the Business Combination and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board of Directors, providing for such Business Combination;

(4) Any transaction or series of transactions which is expressly designated by resolution of the Board of Directors to constitute a Change in Control for purposes of this Plan.

(h) " Code " means the Internal Revenue Code of 1986, as amended.

(i) “ Common Stock " means the Common Stock, par value $0.01 per share, of Energen Corporation as such stock may be reclassified, converted or exchanged by reorganization, merger or otherwise.

(j) “ Company Stock Account ” means an account established and maintained for a Participant as a record of the Participant’s hypothetical investments in shares of Common Stock. A Participant shall have two sub-accounts of the Company Stock Account, a Post-2004 Company Stock Account and a Pre-2005 Company Stock Account.

[“Compensation Committee” see (aa) below]

(k) “ Post-2004 Company Stock Account ” means an account established and maintained for a Participant as record of the Participant’s hypothetical investments in shares of Common Stock with respect to amounts credited to a Participant’s Company Stock Account pursuant to Section 7.1 after December 31, 2004, other than earnings or losses with respect to the Participant’s Pre-2005 Company Stock Account.

(l) “ Pre-2005 Company Stock Account ” means an account established and maintained for a Participant as a record of the Participant’s hypothetical investments in shares of Common Stock with respect to amounts credited to a Participant’s Pre-2005 Company Stock Account pursuant to Section 7.1 prior to January 1, 2005 and hypothetical earnings or losses thereon.

(m) “ Deferral Election Form ” means such the form or forms as may be approved by Energen from time to time for use by a Participant to elect to defer compensation under the Plan.

(n) “ Director ” means a member of the board of directors of a Participating Employer.

(o) “ Director Fees ” means retainer, meeting, committee and other fees payable to a Director for service in such capacity.

(p) “ Directors Stock Plan ” means the Energen Corporation 1992 Directors Stock Plan, as amended.

(q) “ Disability ” means that (a) a Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months; or (b) a Participant is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of at least 3 months under a plan covering employees of the Company.

(r) “ Discretionary Amount ” means amounts credited to a Participant’s Account pursuant to Section 4.4.

(s) “ Distributable Event ” means an event identified as such in Section 6.1.

(t) “ EGN ” means EGN Services, Inc., a subsidiary of Energen Corporation.

(u) “ Energen ” means Energen Corporation, an Alabama corporation.

(v) “ ERISA ” means the Employee Retirement Income Security Act of 1974, as amended.

(w) “ Investment Account ” means an account established and maintained for a Participant as a record of the Participant’s hypothetical investments in available investment options. A Participant shall have two sub-accounts of the Investment Accounts, a Post-2004 Investment Account and a Pre-2005 Investment Account.

(x) “ Post-2004 Investment Account ” means an account established and maintained for a Participant as a record of the Participant’s hypothetical investments in available investment options with respect to amounts credited to a Participant’s Investment Account pursuant to Section 7.2 after December 31, 2004, other than earnings or losses with respect to the Participant’s Pre-2005 Investment Account.

(y) “ Pre-2005 Investment Account ” means an account established and maintained for a Participant as a record of the Participant’s hypothetical investments in available investment options with respect to amounts credited to a Participant’s Investment Account pursuant to Section 7.2 prior to January 1, 2005, and hypothetical earnings or losses thereon.

(z) “ Officer ” means an officer of a Participating Employer elected to such position by the board of directors of such Participating Employer.

(aa) “ Compensation Committee ” means the Compensation Committee (formerly named Officers Review Committee) of the Board of Directors or such other person or persons as may be designated by the Board of Directors to act on behalf of the Board of Directors in the administration of the Plan.

(bb) “ Participant ” means an individual identified as such under Article III of the Plan.

(cc) “ Participating Employer ” means any employer participating in the Plan pursuant to Article II of the Plan.

(dd) “ Plan ” means the Energen Corporation 1997 Deferred Compensation Plan, as amended, which is maintained by Energen and its affiliated companies primarily for the purpose of providing financial incentives for directors and certain key employees of Energen and its affiliated companies.

(ee) “ Resources ” means Energen Resources Corporation, a subsidiary of Energen.

(ff) “ Stock Incentive Plan ” means the Energen Corporation 1997 Stock Incentive Plan, as amended.

(gg) “ Trust ” means the trust described in Section 12.4. The Trust shall constitute an unfunded arrangement and shall not affect the status of the Plan as an unfunded plan. Participants and their beneficiaries shall have no beneficial ownership interest in any assets of any such Trust.

(hh) “ Trustee ” means the corporation or person or persons selected by Energen to serve as Trustee for the Trust.

(ii) “ Vested ” means an interest in the benefit described under the Plan which may be payable to or on behalf of the Participant in accordance with the terms of the Plan.

ARTICLE II.

PARTICIPATING EMPLOYERS

Section 2.1 Eligibility . To be eligible to adopt and participate in the Plan, an employer must be a member of the “controlled group” of corporations, within the meaning of Section 414 of the Code, that includes Energen and must be determined to be eligible to participate in the Plan by Energen. The corporations which are eligible to participate in this Plan as of January 1, 2008, are Energen, Alagasco, Resources, Basin, and EGN.

Section 2.2 Participation Reimbursements . Energen, the sponsor of the Plan, Alagasco, Resources, Basin, and EGN, are Participating Employers in the Plan effective as of January 1, 2008. Any other affiliated company that is or becomes eligible to adopt the Plan and become a Participating Employer pursuant to Section 2.1 of the Plan may, with the approval of the Board of Directors by resolution of the Board of Directors, adopt this Plan and become a Participating Employer in the Plan. The date on which such eligible company may become a Participating Employer in the Plan shall be stated in the resolutions of the Board of Directors. Each of the Participating Employers agree to make payments of their allocable portion of the benefits provided under the Plan to their respective employee and Director Participants. Energen hereby guarantees the performance by each of the other Participating Employers of their respective obligations under the Plan. Neither the respective benefit payment obligations of the Participating Employers nor Energen’s guarantee of performance is secured in any way. Such obligations and guarantee constitute no more than unfunded and unsecured promises of payment and performance. Each Participating Employer, other than Energen, shall reimburse Energen for its allocable share of costs and expenses paid by Energen in

connection with the operation and administration of the Plan, and shall reimburse Energen for any benefits paid by Energen under the Plan to Participants to the extent allocable to such Participating Employer and its Participants. Payments made to Participants by the Trust shall constitute payments by Energen and Energen shall be reimbursed for such payments by the appropriate Participating Employers.

Section 2.3 Recordkeeping and Reporting . Each Participating Employer, other than Energen, shall furnish to Energen the information with respect to each of its Participants necessary to enable Energen to maintain records sufficient to determine the benefits (and the compensation sources of such benefits) which may become payable to or with respect to such Participants and to give those Participants any reports which may be required under the terms of the Plan or by law.

Section 2.4 Termination of Participation . A Participating Employer, other than Energen, may withdraw from participation in the Plan at any time by providing Energen with 30 days advance written notice of such withdrawal from participation and the effective date of such Participating Employer’s withdrawal, which 30‑day notice period may be waived by Energen. In addition, Energen may terminate a Participating Employer’s participation in the Plan by providing such Participating Employer with 30 days advance written notice, which 30‑day notice period may be waived by the Participating Employer. A Participating Employer which terminates its participation in the Plan shall remain obligated under the Plan with respect to deferrals made prior to such termination by its Participants (including subsequent investment performance adjustments), unless otherwise expressly agreed by Energen with Energen fully assuming such obligations.

Section 2.5 Separate Accounting . Energen shall establish and maintain separate Accounts for each of the Participating Employers and their respective Participants. Such separate accounting is intended to comply with Section 404(a)(5) of the Code and Section 1.404(a) ‑ 12 of the Treasury Regulations (which provide that an employer can deduct the amounts contributed to a nonqualified plan in the taxable year in which an amount attributable to the contribution is includable in the gross income of employees participating in the plan, but, in the case of a plan in which more than one employee participates only if separate accounts are maintained for each employee).

ARTICLE III.

ELIGIBILITY AND PARTICIPATION

Section 3.1 Eligibility . Each Director and each Officer of a Participating Employer shall be eligible to participate in the Plan effective as of the later of the effective date of the Plan or the date on which such individual first becomes a Director or Officer. In addition, the Compensation Committee may by express action designate other management level or highly compensated employees of the Participating Employers as eligible to participate in the Plan. If the Compensation Committee designates a management level or highly compensated employee as eligible to become a Participant in the Plan, Energen shall inform the employee in writing of such designation and the date on which the employee shall become a Participant in the Plan.

Section 3.2 Participation . An individual eligible to participate in the Plan shall become a Participant upon the filing with Energen of a completed Deferral Election Form and acceptance of such form by Energen. The name of each individual eligible to participate in the Plan and the date

on which such individual becomes a Participant in the Plan, shall be recorded on Exhibit A, which exhibit is attached hereto and incorporated herein by reference and which shall be revised by Energen from time to time to reflect the operation of the Plan. Once an individual becomes a Participant in the Plan, the individual shall remain a Participant until the benefits which may be payable to the individual under the Plan have been distributed to or on behalf of the individual.

Section 3.3 Suspension of Eligibility . The Compensation Committee (or the Board of Directors if the affected Participant is a Director) may in its discretion determine that a Participant will no longer be eligible to participate in the Plan, and in such event, the Participant’s Section 4.1 compensation deferral election will immediately terminate as of the end of the calendar year in which such determination is made, and no additional elective deferrals shall be credited to his or her Accounts, other than with respect to compensation otherwise payable in such calendar year or any performance period including such calendar year, until such time as the individual is again determined to be eligible to participate in the Plan by the Compensation Committee (or Board of Directors as appropriate) and makes a new Section 4.1 election. However, the Account of such Participant shall continue to be adjusted by the other provisions of Sections 7.1 and 7.2 until fully distributed.

ARTICLE IV.

BENEFITS

Section 4.1 Deferred Compensation . A Participant may elect to defer receipt of part or all of any one or more of the following items of compensation:

(a) Base salary;

(b) Annual Incentive Compensation Plan awards;

(d) Director Fees;

(e) Annual and/or elective grants under the Directors Stock Plan; and

(f) Such other compensation as the Compensation Committee may from time to time authorize for deferral under the plan.

A Participant may defer an item of compensation only to the extent that the Participant is entitled to receive such item of compensation. Upon such deferral, the Participant will have no further right to such deferred compensation other than as provided under the Plan. Such deferred compensation shall be the record of the value of such deferred compensation credited to a Participant’s Account and shall be used solely for accounting purposes.

Section 4.2 Form and Effectiveness of Deferral Election . Elections to defer compensation under the Plan shall be made in writing on the Deferral Election Form and shall not become effective unless accepted by the Company in its discretion. An election to defer compensation described in Section 4.1(a), (b), (d) or (e) must be made prior to the beginning of the calendar year for which

such compensation is otherwise payable. An election to defer compensation consisting of grants of stock options or restricted stock pursuant to Section 4.1(c) must be made within thirty (30) days following the date of the grant pursuant to the Stock Incentive Plan; provided, however, no such deferral election may be made with respect to grants that vest less than twelve (12) months following the date of such election. An election to defer compensation consisting of grants of performance shares pursuant to Section 4.1(c) must be made not later than six (6) months prior to the end of the performance period with respect to such compensation. Notwithstanding the foregoing, with respect to a newly eligible Participant, an initial election to defer compensation described in Section 4.1(a), (b), (d) or (e) may be made within thirty (30) days of the date participation eligibility begins, and such election shall relate only to compensation earned after the date of such election. With respect to any other item of compensation permitted to be deferred pursuant to Section 4.1(f), an election to defer such compensation must be made in accordance with provisions of this Section 4.2 concerning elections to defer similar items of compensation (i.e., stock options, stock awards, performance based awards or cash compensation) and the provisions of Section 409A of the Code and the Treasury regulations thereunder. An election with respect to an item of compensation shall remain in effect for succeeding periods unless such election is changed for such succeeding periods during the time described above for initial election with respect to such item.

Section 4.3 Participant Accounts . A Pre-2005 Company Stock Account, a Post-2004 Company Stock Account, or Pre-2005 Investment Account and a Post-2004 Investment Account shall be established and maintained for each Participant. Except as otherwise directed by the Compensation Committee, the Company Stock Accounts shall be credited for deferred amounts attributable to (i) awards and grants under the Stock Incentive Plan, the Directors Stock Plan and other deferred stock compensation, (ii) Discretionary Amounts to the extent that the Board of Directors specifies that such amounts shall be credited to the Company Stock Account, and (iii) such amounts of base salary, Annual Incentive Compensation Plan awards and Director Fees as may be allocated to the Company Stock Account pursuant to Section 7.1(e). The Investment Accounts shall be credited for any deferred amounts which are not credited to the Company Stock Accounts pursuant to Section 7.1(e).

Section 4.4 Discretionary Amounts . In addition to amounts deferred by a Participant, the Board of Directors may from time to time, in its sole discretion, authorize a Participant’s Participating Employer to credit the Participant’s Account with additional amounts. Such additional amounts may be authorized for such purpose or purposes as the Board of Directors may deem appropriate. Except to the extent otherwise specified by the Board of Directors, Discretionary Amounts shall be credited to the Participant’s Investment Account.

ARTICLE V.

VESTING

Section 5.1 Vested Benefit . A Participant shall be considered to be 100% Vested in his or her Account.

Section 5.2 Limitation on Benefits . The benefits that may be payable to or on behalf of a Participant under the Plan shall be equal to a cash payment equal to the value of the amounts credited to the Participant’s Investment Accounts and a distribution of that number of Common Shares equal

to the number of shares credited to the Participant’s Company Stock Accounts (with any fractional share being rounded to a whole share).

ARTICLE VI.

DISTRIBUTIONS.

Section 6.1 Distributable Events . A Participant’s Distributable Event shall be the first to occur of the following events; provided, that events (b) - (e) shall be Distributable Events only if so elected by the Participant in the Deferral Election Form and further provided that event (h) is not applicable to deferrals that are subject to Distributable Event elections made prior to October 22, 2014:

(a) the Participant’s 70th birthday (i.e., the 70th anniversary of the Participant’s birth) or such earlier birthday as the Participant may specify in the Deferral Election Form;

(b) Disability (as defined in Section 1.1);

(d) the first date on which the Participant is neither an employee nor a Director of any Participating Employer;

(e) such other event as the Participant may specify in the Deferral Election Form (subject to approval of Energen, provided that such an event satisfies the requirements of Section 409A(a)(2) of the Code);

(f) the taking of action by the Board of Directors to terminate the Plan pursuant to Section 14.1, provided that payment may be made upon such termination in accordance with Section 409A and Treasury Regulation 409A-3(j)(4)(ix);

(g) termination for Cause subject to and in accordance with Section 6.7; or

(h) the first anniversary of the first date on which the Participant is neither an employee nor a Director of any Participating Employer.

A Participant’s Distributable Event elections must be made on the Participant’s initial Deferral Election Form and are irrevocable; provided, that Energen may in its sole discretion allow a Participant to make different Distributable Event elections with respect to subsequent deferral elections pursuant to Section 4.2 hereof or with respect to different items of compensation listed in Section 4.1 hereof.

Notwithstanding the foregoing, a Participant may revoke an existing Distributable Event election and make a new Distributable Event election prior to December 31, 2008; provided, however, that the effect of any such revocation and new election may not be to defer a distribution that would otherwise be made prior to January 1, 2009 to a date after December 31, 2008 or to accelerate a distribution that would be made after December 31, 2008 to a date prior to January 1, 2009.

Section 6.2 Distribution of Benefits .

(a) Distribution Commencement Date . Excepting withdrawals under Sections 6.3 and 6.4 which shall be distributed in accordance with those Sections and subject to Section 6.8 and to reasonable time for administrative direction and processing, distribution of a Participant’s Plan benefit shall commence as of the first day of the second calendar month immediately following the calendar month in which the Participant’s applicable Distributable Event occurs.

(b) Form of Distribution . Benefits attributable to the value of the Investment Account shall be delivered to the Participant in dollars. Benefits attributable to the Company Stock Account shall be delivered to the Participant in the form of shares of Common Stock. To the extent that the distribution is in the form of shares of Common Stock, such delivery shall be subject to all applicable securities laws and regulations and Energen shall have taken all steps, if any, including registration and listing, as may be necessary to make the shares immediately saleable by the Participant without further regulatory action or compliance on the part of the Participant (other than compliance with paragraphs (f) and (h) of Rule 144 under the Securities Act of 1933). The Participant shall reasonably cooperate with Energen, at Energen’s expense, to facilitate such compliance and related actions by Energen.

(c) Payment Options . In the event a Participant becomes eligible to receive a payment of benefits under the Plan, the benefits payable to the Participant or, in the event of the Participant’s death, to the Participant’s designated beneficiary under the Plan shall be paid in accordance with one of the payment options available under the Plan as elected by the Participant on the Participant’s Deferral Election Form. The Participant may elect separate payment options with respect to the Investment Account and the Company Stock Account. A Participant may change payment options with respect to the Participant’s Pre-2005 Company Stock and Pre-2005 Investment Account by electing another payment option available under the Plan on a subsequent Deferral Election Form, but such change in payment option will not be effective until twelve months following the date on which the change was elected. Participants were allowed to change payment options with respect to the Participant’s Post-2004 Company Stock Account and Post-2004 Investment Account as provided in the transition relief afforded under IRS Notice 2005-1 and Proposed Treasury Regulations issued pursuant to Section 409A of the Code. As of January 1, 2008, a Participant may change payment options with respect to the Participant’s Post-2004 Company Stock Account and Post-2004 Investment Account by electing another payment option available under the Plan on a subsequent Deferral Election Form, but such change in payment option shall not be effective until twelve months following the date on which such change is made. Except for payments on account of a participant’s Disability or death, any such change in payment option for the Participant’s Post-2004 Company Stock Account and Post-2004 Investment Account must defer such payment for a period of not less than five years from the date such payment would otherwise have been paid or commenced. Subject to the following provisions of this Section, the payment options include installment payments over a period certain, a lump sum payment, and such other payment method as may be specified by the Participant and accepted by Energen. The Compensation Committee may, in its sole discretion, reduce the payment period over which payments would have been made pursuant to the payment option elected by a Participant (including consolidation into a lump sum); provided, that in the event of a Change in Control, no reduction of a payment period may be made prior to the fifth anniversary of such Change in Control; and provided, further, that this sentence

shall not apply to a distribution with respect to a Participant’s Post-2004 Company Stock Account or Post-2004 Investment Account. Absent a payment option election, the Compensation Committee shall direct the payment of any benefits payable under the Plan to or on behalf of the Participant in a lump sum payment to the Participant, or in the event of the Participant’s death, to the Participant’s designated beneficiary under the Plan. The foregoing notwithstanding, installment payment options are not available with respect to Distributable Event elections made on or after October 22, 2014.

Section 6.3 Early Withdrawals . Notwithstanding any provision in this Plan to the contrary, a Participant may request, by providing a written request to the Compensation Committee, a withdrawal prior to the distribution date under the Plan of all or any portion of his or her benefits from any of his or her Pre-2005 Company Stock Account or Pre-2005 Investment Account under the Plan in increments of 25% (of aggregate Account value). If such a request is approved by the Compensation Committee, which decision by the Compensation Committee shall be made in its sole discretion on a case by case basis, a distribution of such benefits may be made to the Participant subject to a penalty for such an early withdrawal at any point equal to a one-year period during which no additional deferral elections may be made (but existing elections remain in effect for the compensation to which such existing elections relate). The nonparticipation period would begin as of the date on which the request made by the Participant is approved by the Compensation Committee. In addition, a penalty of 10% of the amount withdrawn will be imposed on any withdrawal made pursuant to this Section 6.3.

Section 6.4 Hardship Withdrawals . In addition to the other distribution and withdrawal provisions of this Article VI and notwithstanding any provision herein to the contrary, in the event a Participant incurs an unforeseeable emergency, the Participant may request, by providing a written request to the Compensation Committee, a hardship withdrawal of all or any portion of his or her benefits from his or her Accounts under the Plan. An unforeseeable emergency is a severe financial hardship to the Participant resulting from a sudden and unexpected illness or accident of the Participant or of a dependent (as defined in Section 152(a) of the Code) of the Participant, loss of the Participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant. If such a request is approved by the Compensation Committee, which decision by the Compensation Committee shall be made in its sole discretion on a case by case basis, a hardship withdrawal may be permitted under this Section 6.4. Withdrawals of amounts because of an unforeseeable emergency are only permitted to the extent reasonably needed to satisfy the emergency need. This provision shall be interpreted in a manner not inconsistent with Sections 1.409A-3(i)(3), 1.457‑2(h)(4) and 1.457‑2(h)(5) of the Treasury Regulations.

Section 6.5 Distributions as Result of Tax Determination . Notwithstanding any provision in this Plan to the contrary, if, at any time, a court or the Internal Revenue Service determines that any amounts or shares credited to a Participant’s Accounts under the Plan or Trust are includable in the gross income of the Participant and subject to tax pursuant to Section 409A of the Code, the Compensation Committee may, in its sole discretion, permit a lump sum distribution of an amount equal to the amounts or shares determined to be includable in the Participant’s gross income.

Section 6.6 Reserved.

Section 6.7 Distribution Upon Termination for Cause . In the event that a Participant is terminated for Cause (as defined below), the Company shall treat such termination as a Distributable Event. For purposes of this Plan, termination for Cause means termination based on any of the following:

(i) The willful and continued failure by the Participant to substantially perform Participant’s duties with a Participating Employer (other than any such failure resulting from Participant’s incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to Participant specifically identifying the manner in which Participant has not substantially performed Participant’s duties;

(ii) the engaging by Participant in willful misconduct which is demonstrably injurious to any one or more of the Participating Employers monetarily or otherwise; or

(iii) the conviction of Participant of a felony.

Section 6.8 Delay in Payments for Specified Employees . With respect to any payments from the Plan subject to the provisions of Section 409A(a)(2)(B)(i) of the Code, distribution of the amounts attributable to a Participant’s Post-2004 Company Stock Account and Post-2004 Investment Account shall be paid as promptly as practicable following the date that is six months following the Distributable Event giving rise to such payment.

ARTICLE VII.

VALUATION OF BENEFITS.

Section 7.1 Company Stock Accounts .

(a) Unit Accounting . Subject to the authority of the Compensation Committee to specify a different method of measurement and valuation, the Company Stock Accounts, including without limitation, contributions, withdrawals, earnings and other adjustments, shall be measured and valued based on the methods and processes consistent with those used to measure and value the Energen stock fund under the Energen Corporation Employee Savings Plan.

(b) Dividends . The Participant’s Company Stock Account shall be credited to reflect the hypothetical reinvestment of dividends paid on Common Stock.

(c) Stock Dividend, etc . The Company Stock Accounts shall be adjusted to reflect any change in the outstanding Common Stock by reason of any stock dividend or split, recapitalization, merger, consolidation, combination or exchange of shares or other similar corporate change.

(d) Transfer upon Change in Control . In the event of a Change in Control, effective as of the close of business on the date of the Change in Control, each Participant’s Investment Account shall be credited with an amount measured in dollars equal to the value of such Participant’s respective Company Stock Accounts based on the Fair Market Value Close on such date (or such other valuation method selected by the Section 1.1(g) Continuing Directors in their reasonable

discretion), and the Participant’s Company Stock Accounts shall be closed and the Participant shall have no further interest in the Company Stock Accounts.

(e) Allocation of Cash Compensation . A Participant may request that part or all of deferred compensation attributable to base salary, Annual Incentive Compensation Plan awards, Director Fees or other cash compensation be allocated to the Participant’s Company Stock Account. A Participant’s request to make such an allocation or change a previous allocation must be in writing on an Allocation Request Form. All such requests are subject to acceptance by Energen in its discretion. If accepted by Energen, the allocation request will be effective as of the allocation date specified by the request (as defined in Section 7.4).

Section 7.2 Investment Account .

(a) Interest . Subject to 7.2(b), as of the close of the last day of each calendar quarter, an additional amount shall be credited to each Participant’s Investment Accounts equal to the product of (i) the average daily balance in such Investment Account for the quarter, times (ii) one-fourth of the annual prime rate for corporate borrowers quoted at the beginning of the quarter by Regions Bank of Alabama, Birmingham, Alabama (or such other comparable interest rate as the Compensation Committee may designate from time to time).

(b) Investment Options . Energen may permit a Participant to allocate the Participant’s Investment Accounts among one or more investment options for purposes of measuring the value of the benefit. To the extent that the Investment Accounts are allocated to an investment option, such Accounts shall not be credited with interest under Section 7.2(a). That portion of the Investment Account allocated to an investment option shall be deemed to be invested in such investment option and shall be valued as if so invested, reflecting all earnings, losses and other distributions or charges and changes in value which would have been incurred through such an investment. The determination of which investment options, if any to make available, and the continued availability of selected investment options rests in Energen’s sole discretion; provided, that subsequent to a Change in Control, Energen shall maintain the availability of those investment options in place at the time of the Change in Control (or substantially equivalent investment options).

(c) Participant Allocation Request . A Participant’s request to allocate or reallocate among investment options must be in writing on an Allocation Request Form in such increments as Energen may require. All such requests are subject to acceptance by Energen at its discretion. If accepted by Energen, an allocation request will be effective as of the close of business on the allocation date (as defined in Section 7.4).

Section 7.3 Hypothetical Accounts . The Accounts established under this Plan shall be hypothetical in nature and shall be maintained for bookkeeping purposes only. Neither the Plan nor any of the Accounts (or subaccounts) shall hold or be required to hold any actual funds or assets.

Section 7.4 Allocation Date . Upon acceptance of an allocation request pursuant to Section 7.1(e) or 7.2(c), Energen will process the request as soon as reasonably administratively practicable and the request shall be implemented and reflected in the Participant’s account as of the close of

business on such date as may be determined by Energen in its reasonable discretion (the “allocation date”).

Section 7.5 Contribution Timing . Subject to the authority of the Compensation Committee to approve a different schedule, deferred amounts of compensation otherwise payable to a Participant during a calendar months shall be credited to the Participant’s account as of the last day of the months during which such amounts would have otherwise been payable.

ARTICLE VIII.

NONTRANSFERABILITY

Section 8.1 Anti‑Alienation of Benefits . Any benefits which may be credited to a Participant’s Accounts under the Plan, and any rights or privileges pertaining thereto, may not be anticipated, alienated, sold, transferred, assigned, pledged, encumbered, or subjected to any charge or legal process; and no interest or right to receive a benefit may be taken, either voluntarily or involuntarily, for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support, separate maintenance and claims in bankruptcy proceedings.

Section 8.2 Incompetent Participants . If any person who may be eligible to receive a payment under the Plan has been legally declared incompetent and a conservator or other person legally charged with the care of such person or of his or her estate has been appointed, any payment under the Plan to which the person is eligible to receive shall be paid to such conservator or other person legally charged with the care of the person or his or her estate. Any such payment shall be a payment for the account of such person and a complete discharge of any liability of the Participating Employers and the Plan therefor.

Section 8.3 Designated Beneficiary . In the event of a Participant’s death prior to the payment of all or a portion of any benefits which may be payable with respect to the Participant under the Plan, the payment of any benefits payable on behalf of the Participant under the Plan shall be made to the Participant’s beneficiary designated on a Deferral Election Form. If no such beneficiary has been designated, payment shall be made as required under the Participant’s will; or, in the event that there shall be no functioning will under applicable state law, then to such persons as, at the date of the Participant’s death, would be entitled to share in the distribution of such deceased Participant’s personal estate under the provisions of the applicable statute then in force governing the decedent’s intestate property, in the proportions specified in such statute.

ARTICLE IX.

WITHHOLDING

Section 9.1 Withholding . Each Participant shall, no later than the date as of which amounts payable under the Plan first become subject to taxation, pay to Energen, or make arrangements satisfactory to Energen, regarding payment of, any Federal, FICA, state, or local taxes of any kind required by law to be withheld with respect to the Award. The obligations of Energen and the Participating Employers under the Plan shall be conditional on such payment or arrangements. Energen and, where applicable, the Participating Employers shall, to the extent permitted by law,

have the right to deduct any such taxes owed hereunder by a Participant from any payment of any kind otherwise due to said Participant. The Compensation Committee may permit Participants to elect to satisfy their Federal, and where applicable, FICA, state and local tax withholding obligations with respect to amounts payable in the form of Common Stock by the reduction, in an amount necessary to pay all said withholding tax obligations, of the number of shares of Common Stock otherwise issuable to said Participants.

ARTICLE X.

VOTING OF STOCK

Section 10.1 Voting of Company Stock . No Participant shall be entitled to any voting rights with respect to any shares credited to his or her Company Stock Account.

ARTICLE XI.

ADMINISTRATION OF A PLAN

Section 11.1 Administrator . The administrator of the Plan shall be Energen. However, the Board of Directors shall act on behalf of Energen with respect to the administration of the Plan and may delegate authority with respect to the administration of the Plan to the Compensation Committee or such other committee, person or persons as it deems necessary or appropriate for the administration and operation of the Plan.

Section 11.2 Authority of Administrator . Energen shall have the authority, duty and power to interpret and construe the provisions of the Plan as it deems appropriate, to adopt, establish and revise rules, procedures and regulations relating to the Plan, to determine the conditions subject to which any benefits may be payable, to resolve all questions concerning the status and rights of Participants and others under the Plan, including, but not limited to, eligibility for benefits and to make any other determinations which it believes necessary or advisable for the administration of the Plan. Energen shall have the duty and responsibility of maintaining records, making the requisite calculations and disbursing payments hereunder. The determinations, interpretations, regulations and calculations of Energen shall be final and binding on all persons and parties concerned. The Secretary of Energen shall be the agent of the Plan for the service of legal process in accordance with Section 502 of the Employee Retirement Income Security Act of 1974, as amended.

Section 11.3 Operation of Plan and Claims Procedures . Energen shall be responsible for the general operation and administration of the Plan and for carrying out the provisions thereof. Energen shall be responsible for the expenses incurred in the administration of the Plan. Energen shall also be responsible for determining eligibility for payments and the amounts payable pursuant to the Plan. Energen shall be entitled to rely conclusively upon all tables, valuations, certificates, opinions and reports furnished by any actuary, accountant, controller, counsel or other person employed or engaged by Energen with respect to the Plan. The procedures for filing claims for payments under the Plan are described below. For claims procedures purposes, the “Claims Manager” shall be Energen.

(a) Claims Procedures . It is the intent of Energen to make payments under the Plan without the Participant having to complete or submit any claims forms. However, a Participant

who believes he or she is entitled to a payment under the Plan may submit a claim for payments in writing to Energen. Any claim for payments under the Plan must be made by the Participant or his or her beneficiary in writing and state the claimant’s name and the nature of benefits payable under the Plan on a form acceptable to Energen. The Claims Manager shall notify any person or entity that makes a claim against the Plan (the “Claimant”) in writing, within 60 days (30 days for a claim for benefits on account of Disability) of Claimant’s written application for benefits, or his or her eligibility or non-eligibility for benefits under the Plan. If the Claims Manager determines that the Claimant is not eligible for benefits or full benefits, the notice shall set forth (1) the specific reasons for such denial, (2) a specific reference to the provisions of the Plan on which the denial is based, (3) any internal protocols the Claims Manager relied upon in making its determination, (4) the right to review any documents created or received by the Claims Manager during the review process and documents relevant to the claim whether or not relied upon by the Claims Manager, (5) a description of any additional information or material necessary for the Claimant to perfect his or her claim and a description of why it is needed, and (6) an explanation of the Plan’s claims review procedure and other appropriate information as to the steps to be taken if the Claimant wishes to have the claim reviewed. If the Claims Manager determines that there are special circumstances requiring additional time to make a decision, the Claims Manager shall notify the Claimant of the special circumstances and the date by which a decision is expected to be made, and may extend the time for up to an additional 60 days.

(b) Review Procedure . If the Claimant is determined by the Claims Manager not to be eligible for benefits, or if the Claimant believes that he or she is entitled to greater or different benefits, the Claimant shall have the opportunity to have such claim reviewed by the Claims Manager by filing a petition for review with the Claims Manager within 60 (180 days for a claim for benefits on account of Disability), days after receipt of the notice issued by the Claims Manager. Said petition shall state the specific reasons that the Claimant believes entitle him or her to benefits or to greater or different benefits. Within 60 days (45 days for a claim for benefits on account of Disability) after receipt by the Claims Manager of the petition, the Claims Manager shall afford the Claimant (and counsel, if any) an opportunity to present his or her position to the Claims Manager verbally or in writing, and the Claimant (or counsel) shall have the right to review the pertinent documents. The Claims Manager shall notify the Claimant of its decision in writing within such period, stating specifically the basis of its decision, written in a manner to be understood by the Claimant and the specific provisions of the Plan on which the decision is based. If, because of the need for a hearing, the 60-day period is not sufficient, the decision may be deferred for up to another 30 days (15 days for a claim for benefits on account of Disability) at the election of the Claims Manager, but notice of this deferral shall be given to the Claimant.

Section 11.4 Participant’s Address . Each Participant shall keep Energen informed of his or her current address and the current address of his or her beneficiary. Energen shall not be obligated to search for any person. If the location of a Participant is not made known to Energen within three (3) years after the date on which payment of the Participant’s benefits payable under the Plan may be made, payment may be made as though the Participant had died at the end of the three-year period. If, within one (1) additional year after such three‑year period has elapsed, or, within three (3) years after the actual death of a Participant, Energen is unable to locate any designated beneficiary of the Participant, then Energen shall have no further obligation to pay any benefit hereunder to or

on behalf of such Participant or designated beneficiary and such benefits shall be irrevocably forfeited.

ARTICLE XII.

MISCELLANEOUS PROVISIONS

Section 12.1 No Employment Rights . Neither the Plan nor any action taken hereunder shall be construed as giving any Participant any right to be retained in the service or employ of any Participating Employer.

Section 12.2 Participants Should Consult Advisors . Neither any Participating Employer, nor their respective directors, officers, employees or agents makes any representation or warranty with respect to the state, federal or other tax, financial, estate planning, or the securities or other legal implications of participation in the Plan. Participants should consult with their own tax, financial and legal advisors with respect to their participation in the Plan.

Section 12.3 Unfunded and Unsecured . The Plan shall at all times be considered entirely unfunded both for tax purposes and for purposes of Title I of the Employee Retirement Income Security Act of 1974, as amended, and no provision shall at any time be made with respect to segregating assets of any Participating Employer for payment of any amounts hereunder. Any funds invested hereunder allocable to a Participating Employer shall continue for all purposes to be part of the respective general assets of such Participating Employer and available to the general creditors of such Participating Employer in the event of a bankruptcy (involvement in a pending proceeding under the Federal Bankruptcy Code) or insolvency (inability to pay debts as they mature) of such Participating Employer. Energen shall promptly notify the Trustee and the applicable Participants of such bankruptcy or insolvency of a Participating Employer. No Participant or any other person shall have any interests in any particular assets of any Participating Employer by reason of the right to receive a benefit under the Plan and to the extent the Participant or any other person acquires a right to receive benefits under the Plan, such right shall be no greater than the right of any general unsecured creditor of any Participating Employer. The Plan constitutes a mere promise by the Participating Employers to make payments to the Participants in the future. With respect to the guarantee of Energen under Section 2.2, Participants have rights only as general unsecured creditors of Energen. Nothing contained in the Plan shall constitute a guaranty by any Participating Employer or any other person or entity that any funds in any trust or the assets of any Participating Employer will be sufficient to pay any benefit hereunder. Furthermore, no Participant shall have any right to a benefit under the Plan except in accordance with the terms of the Plan.

Section 12.4 The Trust .

(a) Establishment of Trust . In order to provide assets from which to fulfill its obligations to the Participants and their beneficiaries under the Plan, Energen shall establish a Trust by a trust agreement with a third party, the Trustee, to which Energen may, in its discretion, contribute cash or other property, including securities issued by Energen, to provide for the benefit payments under the Plan. The Trustee will have the duty to invest the Trust assets and funds in accordance with the terms of the Trust. Energen shall be entitled at any time, and from time to time, in its sole discretion, to substitute assets of at least equal fair market value for any assets held in the Trust. All

rights associated with the assets of the Trust will be exercised by the Trustee or the person designated by the Trustee, and will in no event be exercisable by or rest with Participants or their beneficiaries. The Trust shall provide that in the event of the insolvency of Energen, the Trustee shall hold the assets for the benefit of the general creditors of Energen and its affiliated companies. The Trust shall be based on the model trust contained in Internal Revenue Service Revenue Procedure 92‑64 with such changes and modifications as may be approved by Energen.

(b) Contribution Upon Change in Control . If as of the close of business on the date of a Change in Control, the aggregate value of the Participant Accounts exceeds the value of the Trust assets, then within thirty days of such Change in Control, Energen shall contribute to the Trust assets having a value at least equal to the amount of such excess.

Section 12.5 Plan Provisions . Except when otherwise required by the context, any singular terminology shall include the plural.

Section 12.6 Severability . If a provision of the Plan shall be held to be illegal or invalid, the illegality or invalidity shall not affect the remaining parts of the Plan and the Plan shall be construed and enforced as if the illegal or invalid provision had not been included.

Section 12.7 Applicable Law . To the extent not preempted by the laws of the United States, the laws of the State of Alabama shall apply with respect to the Plan.

ARTICLE XIII.

AMENDMENTS

Section 13.1 Amendment of the Plan . Energen reserves the power to alter, amend or wholly revise the Plan at any time and from time to time by the action of the Board of Directors and the interest of each Participant is subject to the powers so reserved; provided, however, that no amendment made subsequent to a Change in Control shall be effective to the extent that it would have a materially adverse impact on a Participant’s reasonably expected economic benefit attributable to compensation deferred by the Participant prior to the Change in Control. An amendment shall be authorized by the Board of Directors and shall be stated in an instrument in writing signed in the name of Energen by a person or persons authorized by the Board of Directors. After the instrument has been so executed, the Plan shall be deemed to have been amended in the manner therein set forth, and all parties interested herein shall be bound thereby. No amendment to the Plan may alter, impair, or reduce the benefits credited to any Accounts prior to the effective date of such amendment without the written consent of any affected Participant.

ARTICLE XIV.

TERM OF PLAN

Section 14.1 Term of the Plan . Energen may at any time terminate the Plan by action of the Board of Directors with such termination being effective as of the date that all Participant Accounts have been distributed to Participants in accordance with and subject to the provisions of Article VI of the Plan including, without limitation, Section 6.6 of the Plan. Effective as of the date of such Board of Directors action (or such later date as may be specified therein) all Section 4.1

compensation deferral elections will terminate and no further amounts shall be credited to any Accounts of any Participant under Sections 7.1(a), (b), (c) and 7.2(a) after such date. However, the Participants’ Accounts shall continue to be adjusted by the other provisions of Sections 7.1 and 7.2 until all benefits are distributed to the Participants or to the Participants’ beneficiaries. Notwithstanding the foregoing, payments will not be made and deferral elections will not terminate hereunder to the extent that such payments or deferrals would violate the provisions of Section 409A of the Code.

Exhibit 10(o)

ENERGEN CORPORATION

ANNUAL INCENTIVE COMPENSATION PLAN

(As Amended Effective January 1, 2015)

1. PURPOSE.

The purposes of the Plan are to enable the Company and its subsidiaries to attract, retain, motivate and reward qualified executive officers and key employees by providing them with the opportunity to earn incentive compensation linked to the Company's performance. The Plan contains provisions intended to allow such incentives to be structured in a manner that qualifies for the performance-based exception to Section 162(m) of the Internal Revenue Code.

2. DEFINITIONS.

Unless the context requires otherwise, the following words as used in the Plan shall have the meanings ascribed to each below, it being understood that masculine, feminine and neuter pronouns are used interchangeably and that each comprehends the others.

(a) "Board" shall mean the Board of Directors of the Company.


(b)	" Cause " Termination of employment for "Cause" shall mean termination based on any of the following:

(1)

The willful and continued failure by the Participant to substantially perform the Participant’s duties (other than any such failure resulting from the Participant’s incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to the Participant specifically identifying the manner in which the Participant has not substantially performed the Participant’s duties;


(2)	The engaging by the Participant in willful misconduct which is demonstrably injurious to the Company monetarily or otherwise; or

(3) The conviction of the Participant of a felony.

(1)

generally in the election of directors (the “Outstanding Voting Securities”); provided, however, that for purposes of this subsection (1) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company shall not constitute a Change in Control;

(2)

Individuals who, as of January 1, 2013, constitute the Board of Directors of the Company (the ”Incumbent Board”) cease for any reason to constitute at least a majority of the Board of Directors of the Company (the “Board of Directors”); provided, however that any individual becoming a director subsequent to such date whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board of Directors;

(3)

Consummation of a reorganization, merger or consolidation, or sale or other disposition of all or substantially all of the assets, of the Company (a “Business Combination”), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Common Stock and Outstanding Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Common Stock and Outstanding Voting Securities, as the case may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 30% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed

prior to the Business Combination and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board of Directors, providing for such Business Combination; and

(4)

In addition to the above described Changes in Control, a Subsidiary Transaction (defined below) will constitute a Change in Control with respect to a Participant to the extent specified below. A “Subsidiary Transaction” is a transaction that results in securities representing 80% or more of the voting interests in a Subsidiary or substantially all of a Subsidiary’s assets being transferred to an entity not controlled by or under common control with Energen.

(i) A Subsidiary Transaction involving a disposition of the Company’s largest Subsidiary or the assets of the Company’s largest Subsidiary will constitute a Change in Control if immediately prior to such transaction the Participant was an officer or employee of the Company or the Company’s largest Subsidiary. The largest Subsidiary is determined by net book value of property, plant and equipment.

(ii) A Subsidiary Transaction involving a disposition of

Energen Resources Corporation or its assets will constitute a Change in Control if immediately prior to the transaction the Participant was an officer or employee of Energen Resources Corporation.

(iii) A Subsidiary Transaction involving a disposition of

Alabama Gas Corporation or its assets will constitute a Change in Control if immediately prior to the transaction the Participant was an officer or employee of Alabama Gas Corporation.


(d)	"Committee" shall mean the Officers Review Committee of the Board (or such other committee of the Board that the Board shall designate from time to time) or any subcommittee thereof comprised of two or more directors each of whom is an "outside director" within the meaning of Section 162(m).


(e)	"Company" shall mean Energen Corporation.


(f)	“Covered Employee" shall mean (i) the Company’s Chief Executive Officer and (ii), subject to change from time to time at the discretion of the Committee, the Company’s Chief Financial Officer, the Company’s General Counsel, the Chief Operating Officer of Alabama Gas Corporation, and the Chief Operating Officer of Energen Resources Corporation.

(g) “Participant” shall mean those executive officers and key employees of the Company or a Subsidiary designated by the Committee as participants under the Plan.


(h)	“Performance-Based Exception” means the performance-based exception from the tax deductibility limitations of Section 162(m).


(i)	“Plan" shall mean the Energen Corporation Annual Incentive Compensation Plan, as set forth herein and as it may be amended from time to time.


(j)	“Plan Year” shall mean the fiscal year of the Company or such other period as may be determined by the Committee.


(k)	“Retirement” shall mean termination of employment by a Participant (other than for Cause) who is at least 55 years old and has at least 10 years of service with the Company and its subsidiaries.


(l)	“Section 162(m)” shall mean Section 162(m) of the Internal Revenue Code of 1986, as amended, and any regulations promulgated thereunder.


(m)	“Subsidiary” shall mean and include any corporation other than the Company which is included in the affiliated group of the Company, as such term is defined in Section 1504 of the Code, without regard to Section 1504(b

3. ADMINISTRATION.

The Committee shall administer and interpret the Plan. Any determination made by the Committee under the Plan shall be final and conclusive. The Committee may employ such legal counsel, consultants and agents (including counsel or agents who are employees of the Company or a Subsidiary) as it may deem desirable for the administration of the Plan and may rely upon any opinion received from any such counsel or consultant or agent and any computation received from such consultant or agent. All expenses incurred in the administration of the Plan, including, without limitation, for the engagement of any counsel, consultant or agent, shall be paid by the Company. No member or former member of the Board or the Committee shall be liable for any act, omission, interpretation, construction or determination made in connection with the Plan other than as a result of such individual's willful misconduct.

4. TERMS AND CONDITIONS OF INCENTIVES.

4.1 ESTABLISHMENT OF PERFORMANCE OBJECTIVES AND INCENTIVE OPPORTUNITY. Within 90 days of the commencement of each Plan Year (or such later time as may be permitted for performance-based compensation under Section 162(m)), the Committee shall establish written performance objectives and a cash

incentive opportunity for each Participant chosen to receive an incentive for such Plan Year. At the time of setting the performance objectives, the Committee shall specify the formula to be used in calculating each of the criteria on which an incentive is based and their relative weights. The incentive opportunity shall be expressed as an amount of cash or percentage of salary. The Committee may also specify a minimum acceptable level of achievement of the relevant performance objectives, as well as one or more additional levels of achievement, and a formula to determine the percentage of the incentive opportunity earned by the employee upon attainment of each such level of achievement. The performance objectives and incentive opportunity relating to any particular incentive need not be the same as those relating to any other incentive, whether made at the same or a different time. The Committee may delegate to the Chief Executive Officer of the Company the establishment and measurement of such performance objectives for Participants who are not Covered Employees.

4.2 PERFORMANCE OBJECTIVES CRITERIA .

(a) Criteria . The performance objectives for Participants who are Covered Employees shall be specific, measurable goals set by the Committee, may include multiple objectives and may be based on one or more operational or financial criteria. In setting the performance objectives, the Committee shall select from one or more of the following criteria (the “Section 162(m) Criteria”) in either absolute or relative terms, for the Company or any subsidiary business unit:

(1) total shareholder return;

(2) return on assets, return on equity or return on capital employed;


(3)	measures of profitability such as earnings per share, corporate or business unit net income, net income before extraordinary or one-time items, earnings before interest and taxes, earnings before interests, taxes, depreciation and amortization, or earnings before interest, depreciation, amortization, taxes and exploration expense;

(4) cash flow measures;

(5) gross or net revenues or gross or net margins;


(6)	levels of operating expense or other expense items reported on the income statement;


(7)	oil and/or gas reserves, reserve growth, production, production growth, production replacement, either absolute or on an appropriate per unit basis (e.g. reserve or production growth per diluted share);


(8)	efficiency or productivity measures such as annual or multi-year average finding costs, absolute or per unit operating and maintenance costs, lease operating expenses, operating and maintenance expenses;


(9)	measures of selected operations activities such as number of wells drilled or number of miles of pipe installed;


10)	satisfactory completion of a major project or organizational initiative with specific criteria set in advance by the Committee defining “satisfactory”;


(11)	debt ratios or other measures of credit quality or liquidity;


(12)	strategic asset sales or acquisitions in compliance with specific criteria set in advance by the Committee.


(13)	measures of distribution system throughput, customer count, use per customer and burner tip count; and capital expenditure.


(14)	measures of customer satisfaction and customer service; and


(15)	measures of safety.

(b) Adjustments . When provided for by the Committee at the time the performance objectives are established, the performance objectives may be adjusted to exclude the effect of any of one or more of the following events that occur during the Performance Period:


(1)	asset write-downs, sales and dispositions;


(2)	litigation, claims, judgments or settlements;


(3)	the effect of changes in law, regulation, accounting principles or other provisions affecting reported results;


(4)	accruals for reorganization and restructuring programs;


(5)	material changes to invested capital from pension and post-retirement benefits-related items and similar non-operational items; and


(6)	any extraordinary, unusual, non-recurring or non-comparable items:


(i)	as described in Accounting Standards Codification No. 225,


(ii)	as described in management’s discussion and analysis of financial condition and results of operations appearing in the Company’s Annual Report to stockholders for the applicable year, or


(iii)	as publicly announced by the Company in a press release or conference call relating to the Company’s results of operations or financial condition for a completed quarterly or annual fiscal period; such as non-cash mark-to-market gains and losses on open derivative contracts.

(c) Per Share Adjustments . Performance objectives set on a per share basis such as earnings or cash flow per share shall be appropriately adjusted to reflect changes in outstanding shares resulting from stock dividends, splits or combinations or mergers, reorganizations or similar transactions.

(d) Non-Covered Employees . The performance objectives for Participants who are not Covered Employees may be based on Section 162(m) Criteria or on criteria different from or supplemental to the Section 162(m) Criteria.

4.3 EARNING OF INCENTIVE, INDIVIDUAL MAXIMUM. Promptly after the date on which the necessary information for a particular Plan Year becomes available, the Committee shall determine the extent to which the incentive opportunity for such Plan Year has been earned through the achievement of the relevant performance objectives by each Participant who was granted an incentive for such Plan Year. At its discretion, the Committee may reduce a Participant’s earned incentive by up to 25%. The Committee shall certify in writing the earned incentives adjusted for any discretionary reductions. Notwithstanding the terms of any incentive, the maximum incentive under this Plan to any individual for any one Plan Year shall not exceed $2.5 million.

4.4 PAYMENT OF INCENTIVES. Promptly after the Committee has certified in writing that an incentive has been earned and any discretionary reductions, such incentives shall be paid in cash in a lump sum, provided, that any amounts, the payment of which has been deferred under the Energen Corporation 1997 Deferred Compensation Plan or any successor plan, shall be credited to the Participant’s account in accordance with the terms of that plan.

4.5 TERMINATION OF EMPLOYMENT – COMPLETED PLAN YEAR . If Participant’s employment is terminated for any reason (including death, disability or retirement) other than Cause after the end of a Plan Year but before payment of incentives for such Plan Year, the Participant shall remain entitled to payment of incentives, if any, earned for such Plan Year. A Participant whose employment is terminated for Cause after the end of a Plan Year but before payment of incentives for such Plan Year shall not receive payment of any incentive for the completed Plan Year.

4.6 TERMINATION OF EMPLOYMENT – PARTIAL PLAN YEAR – NO CHANGE IN CONTROL. If prior to the last day of a Plan Year during which a Change in Control does not occur (a “Routine Plan Year”), a Participant’s employment terminates as a result of the Participant's death, disability, or Retirement, such Participant shall receive an incentive equal to the amount that the Participant would have received as an incentive if such Participant had remained an employee through the end of the Plan Year multiplied by a fraction, the numerator of which is the number of days that elapsed during the Plan Year in which the termination occurs prior to and including the date of the Participant’s termination of employment and the denominator of which is the number of days in the full Plan Year (a "pro rata incentive"). If a Participant's employment terminates for any other reason during a Routine Plan Year, then no incentive shall be payable to the Participant for such Plan Year, provided, that at its discretion, the Committee may determine to pay such Participant (other than a Participant terminated for cause) up to a pro rata incentive.

4.7 TERMINATION OF EMPLOYMENT – PARTIAL PLAN YEAR – WITH CHANGE IN CONTROL . If prior to the last day of a Plan Year during which a Change in Control occurs (a “Change in Control Plan Year”),


(i)	a Participant’s employment terminates as a result of the Participant's death, disability, or Retirement, or


(ii)	after the occurrence of the Change in Control, the Participant’s employment is otherwise involuntarily terminated other than for Cause, including a termination for good reason entitling the Participant to severance compensation under a written change in control severance compensation agreement between the Company or a Subsidary and the Participant;

such Participant shall receive an incentive equal to the Participant’s target incentive for the Plan Year multiplied by a fraction, the numerator of which is the number of days that elapsed during the Plan Year in which the termination occurs prior to and including the date of the Participant’s termination of employment and the denominator of which is the number of days in the full Plan Year (a "pro rata incentive"). If a Participant's employment terminates for any other reason during a Change in Control Plan Year, then no incentive shall be payable to the Participant for such Plan Year, provided, that at its discretion, the Committee may determine to pay such Participant (other than a Participant terminated for cause) up to a pro rata incentive.

5. GENERAL PROVISIONS.

5.1 EFFECTIVENESS OF THE PLAN. Subject to the approval by the holders of the Common Stock at the 2002 Annual Meeting of Stockholders, the Plan shall be effective with respect to Plan Years beginning on or after January 1, 2002.

5.2 AMENDMENT AND TERMINATION. The Board or the Committee may at any time amend, suspend, discontinue or terminate the Plan; provided, however, that no such amendment, suspension, discontinuance or termination shall adversely affect the rights of any Participant in respect of any Plan Year which has already commenced and no such action shall be effective without approval by the stockholders of the Company to the extent necessary to continue to qualify the amounts payable hereunder to Covered Employees as performance-based compensation under Section 162(m).

5.3 NO RIGHT OF CONTINUED EMPLOYMENT. Nothing in this Plan shall be construed as conferring upon any Participant any right to continue in the employment of the Company or any of its subsidiaries.

5.4 NO LIMITATION TO CORPORATION ACTION. Nothing in this Plan shall preclude the Committee or the Board, as each or either shall deem necessary or appropriate, from authorizing the payment of compensation outside the parameters of the

Plan, including, without limitation, base salaries, incentives under any other plan of the Company and/or its Subsidiaries (whether or not approved by stockholders), any other incentives (whether or not based on the attainment of performance objectives) and retention or other special payments.

5.5 NONALIENATION OF BENEFITS. Except as expressly provided herein, no Participant shall have the power or right to transfer, anticipate, or otherwise encumber the Participant's interest under the Plan except by will or the laws of descent and distribution.

5.6 WITHHOLDING. Any amount payable to a Participant under this Plan shall be subject to any applicable Federal, state and local income and employment taxes and any other amounts that the Company or a Subsidiary is required at law to deduct and withhold from such payment.

5.7 SEVERABILITY. If any provision of this Plan is held unenforceable, the remainder of the Plan shall continue in full force and effect without regard to such unenforceable provision and shall be applied as though the unenforceable provision were not contained in the Plan.

5.8 GOVERNING LAW. The Plan shall be construed in accordance with and governed by the laws of the State of Alabama, without reference to the principles of conflict of laws.

5.9 HEADINGS. Headings are inserted in this Plan for convenience of reference only and are to be ignored in a construction of the provisions of the Plan.

Exhibit 21

SUBSIDIARIES OF ENERGEN CORPORATION

Energen Resources Corporation*

* Incorporated in the State of Alabama

Exhibit 23(a)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Forms S-8 (File No. 33-46641, File No. 333-104726, 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 March 2, 2015 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

March 2, 2015

Exhibit 23(b)

CONSENT

We hereby consent to the reference to our firm name and our audit of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and natural gas properties located in the U.S. as of December 31, 2014 which appears in this Form 10-K and the inclusion of our report dated February 11, 2015, which appears as an Exhibit to this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-8 (File No. 33-46641, File No. 333-104726, 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, 2014 which appears in this Form 10-K and our report dated February 11, 2015, which appears as an Exhibit to this Form 10-K.

/s/ Ryder Scott Company, L.P.

Houston, Texas

March 2, 2015

Exhibit 23(c)

CONSENT

We hereby consent to the reference to our firm name and our audit of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and natural gas properties located in the U.S. as of December 31, 2014 which appears in this Form 10-K and the inclusion of our report dated February 9, 2015, which appears as an Exhibit to this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-8 (File No. 33-46641, File No. 333-104726, 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, 2014 which appears in this Form 10-K and our report dated February 9, 2015, which appears as an Exhibit to this Form 10-K.

/s/ T. Scott Hickman & Associates, Inc.

Midland, Texas

March 2, 2015

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, 2014 , 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 10 ^th day of February, 2015.

/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/ Frances Powell Hawes

Frances Powell Hawes

/s/ Stephen A. Snider

Stephen A. Snider

/s/ Gary C. Youngblood

Gary C. Youngblood

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 function):


a)	All significant deficiencies and material weaknesses in the design or operation of internal controls 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.



March 2, 2015	By	/s/ J. T. McManus, II
		J. T. McManus, II Chairman and Chief Executive Officer of Energen Corporation

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 function):


a)	All significant deficiencies and material weaknesses in the design or operation of internal controls 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.



March 2, 2015	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

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, 2014 , 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 March 2, 2015



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.

Exhibit 99(a)

ENERGEN RESOURCES CORPORATION

Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2014

\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

February 11, 2015

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, 2014 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 February 4, 2015 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, 2014. The properties reviewed by Ryder Scott incorporate 4830 reserve determinations and are located in the states of Colorado, New Mexico and Texas.

The properties reviewed by Ryder Scott account for a portion of Energen’s total net proved reserves as of December 31, 2014. 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	94	77	89
Proved Developed	91	73	84
Proved Undeveloped	100	100	100

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.”

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

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, 2014 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, 2014, 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, 2014



	Proved
	Developed			Total
	Producing	Non-Producing	Undeveloped	Proved
Net Reserves – Audited by Ryder Scott
Oil/Condensate – MBBL	110,583	6,159	62,451	179,193
Plant Products – MBBL	33,406	1,750	25,841	60,997
Gas – MMCF	417,885	9,384	118,841	546,110
Total Equivalent Oil - MBOE	213,636	9,473	108,099	331,208

Net Reserves – Not Audited by Ryder Scott
Oil/Condensate – MBBL	1,955	0	79	2,034
Plant Products – MBBL	12,260	206	0	12,466
Gas – MMCF	159,504	2,301	11	161,816
Total Equivalent Oil - MBOE	40,799	590	81	41,470

Net Reserves – Total Corporation
Oil/Condensate – MBBL	112,538	6,159	62,530	181,227
Plant Products – MBBL	45,666	1,956	25,841	73,463
Gas – MMCF	577,389	11,685	118,852	707,926
Total Equivalent Oil - MBOE	254,435	10,063	108,180	372,678

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousand barrels of oil equivalent.

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 included 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.”

Proved reserve 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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.

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 2014, 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 developed non-producing and 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 2014. 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 formations in the Permian Basin and coal seams in the San Juan 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 San Juan Basin, Carracas and Tiffany Areas, producing from the Fruitland Coal.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 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, 2014 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS



Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$94.99/Bbl	$88.16/Bbl
	NGLs	WTI Cushing	$94.99/Bbl	$28.85/Bbl
	Gas	Henry Hub	$4.35/MMBTU	$4.03/MCF
	Gas	Colorado Interstate	$4.37/MMBTU	$4.03/MCF

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

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 developed non-producing and 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, 2014. 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, 2014, 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.

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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, or inclined during the dewatering phase for coal seam gas, as appropriate, 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.

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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

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 6 percent of the total proved net liquid hydrocarbon reserves and 23 percent of the total proved net gas reserves or 11 percent of the total proved net reserves on an equivalent barrel, BOE, basis based on estimates prepared by Energen as of December 31, 2014.

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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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.

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 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, 2014 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

Senior Vice President

JEB (DPR)/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 a 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. For more information regarding Mr. Blankenship’s geographic and job specific experience, please refer to the Ryder Scott Company website at 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 also 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 the subject of 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 2014 included training 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’s 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.

In 2012, Mr. Blankenship’s attended classes on The Application of SPEE Monograph 3, Statistical Review of Shale Plays, the Simulation Model Review Process, A New SEC Data Gathering Program, Reserves Impact on Book Value Calculations, Comparison of Different Reserves Standards, Different Production Decline Models Used for Resource Plays, and Eagle Ford Shale Play Volumetric Analysis. Mr. Blankenship also served as instructor in some short courses on Unconventional Resource Evaluation.

Based on his educational background, professional training and more than 37 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Blankenship has attained the professional qualifications as a 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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 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)


(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


(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.



	ERC Net "Subject Area" Audited Reserves

	Oil, MBBL	Gas, MMCF	NGL, MBL	Liquid Eq MBOE
Effective Date	December 31, 2014

Proved Developed
Producing	1,464.1	148,335.2	11,810.7	37,997.4
Nonproducing	—	2,301.2	205.9	589.4
TOTAL PROVED	1,464.1	150,636.4	12,016.6	38,586.8



Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
Subject Area :
	Oil/Condensate	WTI Cushing	$94.98/Bbl	$84.07/Bbl
	NGLs	Mt. Belvieu	$0.75/Gal	$0.68/Gal
	Gas	Henry Hub	$4.35/MMBTU	$4.32/MCF