10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2012

(  )  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	Registrant	State of Incorporation	IRS Employer Identification Number
1-7810	Energen Corporation	Alabama	63-0757759
2-38960	Alabama Gas Corporation	Alabama	63-0022000

605 Richard Arrington Jr. Boulevard North, Birmingham, Alabama 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

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

Title of Each Class	Exchange on Which Registered
Energen Corporation 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 registrants are a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES (X) NO ( )

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

YES ( ) NO (X)

Indicate by a check mark whether registrants (1) have 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 registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. YES (X) NO ( )

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).

Energen Corporation YES (X) NO ( )

Alabama Gas Corporation YES (X) NO ( )

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. ( )

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.

Energen Corporation Large accelerated filer (X) Accelerated filer ( ) Non-accelerated filer ( ) Smaller reporting company ( )

Alabama Gas Corporation Large accelerated filer ( ) Accelerated filer ( ) Non-accelerated filer (X) Smaller reporting company ( )

Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ( ) NO (X)

Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30, 2012:

Energen Corporation $3,193,878,000

Indicate number of shares outstanding of each of the registrant's classes of common stock as of February 15, 2013:

Energen Corporation	72,222,552 shares
Alabama Gas Corporation	1,972,052 shares

Alabama Gas Corporation meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format pursuant to General Instruction I(2).

DOCUMENTS INCORPORATED BY REFERENCE

Energen Corporation Proxy Statement to be filed on or about March 27, 2013 (Part III, Item 10-14)

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.
Behind Pipe Reserves	Oil or gas reserves located above or below the currently producing zone(s) that cannot be extracted until a recompletion or pay-add occurs.
Cash Flow Hedge	The designation of a derivative instrument to reduce exposure to variability in cash flows from the forecasted sale of oil, gas or natural gas liquids production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted sale.
Collar	A financial 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 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 gas in sufficient quantities to justify completion as an oil or gas well.
Exploration Expenses	Costs primarily associated with drilling unsuccessful exploratory wells in undeveloped properties, exploratory geological and geophysical activities, and costs of impaired and expired leaseholds.
Exploratory Well	A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.
Futures Contract	An exchange-traded legal contract 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 Revenues	Revenues reported after deduction of royalty interest payments.
Gross Well or Acre	A well or acre in which a working interest is owned.
Liquified Natural Gas (LNG)	Natural gas that is liquified by reducing the temperature to negative 260 degrees Fahrenheit. LNG typically is used to supplement traditional natural gas supplies during periods of peak demand.
Long-Lived Reserves	Reserves generally considered to have a productive life of approximately 10 years or more, as measured by the reserves-to-production ratio.
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.
Odorization	The adding of odorant to natural gas which is a characteristic odor so that leaks can be readily detected by smell.
Operational Enhancement	Any action undertaken to improve production efficiency of oil and 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 formation from which oil and 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.
Reserves-to-Production Ratio	Ratio expressing years of supply determined by dividing the remaining recoverable 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 reserves.
Secondary Recovery	The process of injecting water, gas, etc., into a formation in order to produce additional oil otherwise unobtainable by initial recovery efforts.
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.
Transportation	Moving gas through pipelines on a contract basis for others.
Throughput	Total volumes of natural gas sold or transported by the gas utility.
Working Interest	Ownership interest in the oil and 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.
-e	Following a unit of measure denotes that the gas components have been converted to barrels of oil equivalents at a rate of 1 barrel per 6 thousand cubic feet.

	ENERGEN CORPORATION 2012 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
	PART I	Page
Item 1.	Business	3
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	11
Item 2.	Properties	12
Item 3.	Legal Proceedings	15
Item 4.	Mine Safety Disclosures	15
	PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer
	Purchases of Equity Securities	17
Item 6.	Selected Financial Data	19
Item 7.	Management's Discussion and Analysis of Financial Condition and
	Results of Operations	22
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 8.	Financial Statements and Supplementary Data	39
Item 9.	Changes in and Disagreements With Accountants on Accounting and
	Financial Disclosure	100
Item 9A.	Controls and Procedures	100
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	102
Item 11.	Executive Compensation	102
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	102
Item 13.	Certain Relationships and Related Transactions, and Director Independence	102
Item 14.	Principal Accountant Fees and Services	102
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	103
Signatures		108

2

This Form 10-K is filed on behalf of Energen Corporation (Energen or the Company)

and Alabama Gas Corporation (Alagasco).

Forward-Looking Statements: The disclosure and analysis in this 2012 Annual Report on Form 10-K contains forward-looking statements that express management’s expectations of future plans, objectives and performance of the Company and its subsidiaries. Such statements constitute forward-looking statements within the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Exchange Act, as amended, and are noted in the Company’s disclosure as permitted by the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address the Company’s future business and financial performance and financial condition, and often contain words such as “expect”, “anticipate”, “intend”, “plan”, “believe”, “seek”, “see”, “project”, “will”, “estimate”, “may”, and other words of similar meaning.

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties (many of which are beyond our control) that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, production levels, reserve levels, energy markets, supply and demand for and the price of energy commodities including oil, gas and natural gas liquids, fluctuations in the weather, drilling risks, costs associated with compliance with environmental and regulatory obligations, inflation rates, legislative and regulatory changes, financial market conditions, the Company’s ability to access the capital markets, acts of nature, sabotage, terrorism (including cyber-attacks) and other similar acts that disrupt operations or cause damage greater than covered by insurance, future business decisions, utility customer growth and retention and usage per customer, litigation results and other factors and uncertainties discussed elsewhere in this 10-K and in the Company’s other public filings and press releases, all of which are difficult to predict. While it is not possible to predict or identify all the factors that could cause the Company’s actual results to differ materially from expected or historical results, the Company has identified certain risk factors which may affect the Company’s future business and financial performance.

See Item 1A, Risk Factors, for a discussion of risk factors that may affect the Company 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. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.

PART I

ITEM 1.BUSINESS

General

Energen Corporation, based in Birmingham, Alabama, is a diversified energy holding company engaged in the development, acquisition, exploration and production of oil, natural gas and natural gas liquids in the continental United States and in the purchase, distribution and sale of natural gas in central and north Alabama. Its two principal subsidiaries are Energen Resources Corporation and Alabama Gas Corporation (Alagasco).

Alagasco was formed in 1948 by the merger of Alabama Gas Company into Birmingham Gas Company, the predecessors of which had been in existence since the mid-1800s. Alagasco became publicly traded in 1953. Energen Resources was formed in 1971 as a subsidiary of Alagasco. Energen was incorporated in 1978 in preparation for the 1979 corporate reorganization in which Alagasco and Energen Resources became subsidiaries of Energen.

The Company maintains a Web site with the address www.energen.com. The Company does not include the information contained on its Web site as part of this report nor is the information incorporated by reference into this report. The Company 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. The Company's Web site also includes its Business Conduct Guidelines, Corporate Governance Guidelines, Audit Committee Charter, Officers' Review Committee Charter, Governance and Nominations Committee Charter and Finance Committee Charter, each of which is available in print upon shareholder request.

3

Financial Information About Industry Segments

The information required by this item is provided in Note 18, Industry Segment Information, in the Notes to Financial Statements.

Narrative Description of Business

• Oil and Gas Operations

General: Energen's oil and gas operations focus on increasing production and adding proved reserves through the development and acquisition of oil and gas properties. In addition, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. All oil, gas and natural gas liquids production is sold to third parties. Energen Resources also provides operating services in the Permian, San Juan and Black Warrior basins for its joint interest and third parties. These services include overall project management and day-to-day decision-making relative to project operations.

At the end of 2012, Energen Resources' proved oil and gas reserves totaled 346.4 million barrels of oil equivalent (MMBOE). Substantially all of these reserves are located in the Permian Basin in west Texas, the San Juan Basin in New Mexico and Colorado and the Black Warrior Basin in Alabama. Approximately 75 percent of Energen Resources' year-end reserves are proved developed reserves. Energen Resources’ reserves are long-lived, with a year-end reserves-to-production ratio of 14 years. Oil, natural gas and natural gas liquids represent approximately 45 percent, 39 percent and 16 percent, respectively, of Energen Resources' proved reserves.

Growth Strategy: Energen operates under a strategy to grow the oil and gas operations of Energen Resources largely through the acquisition and exploitation of proved and high-quality unproved reserves. The company traditionally prefers properties located onshore in North America that offer long-lived reserves and multiple pay-zone opportunities. Energen Resources also conducts exploration activities in and around the basins in which it operates; exploration in other areas is possible if the opportunities complement its core expertise and meet its investment requirements. Following an acquisition, Energen Resources focuses on increasing production and reserves through development well drilling, exploration, behind-pipe recompletions, pay-adds, workovers, secondary recovery, and operational enhancements. Energen Resources prefers to operate its properties in order to better control the nature and pace of drilling and development activities. Energen Resources operated approximately 94 percent of its proved reserves at December 31, 2012.

Since the end of fiscal year 1995, Energen Resources has invested approximately $1.9 billion to acquire proved and unproved reserves, $3.7 billion in related development and $1.3 billion in exploration. Energen Resources' capital spending plans for2013 target a total investment of approximately $905 million, the bulk of which will focus on drilling and related development activities on its existing properties, with approximately 98 percent targeting the liquids-rich Permian Basin. The company may choose to allocate additional capital during the year for property acquisitions and/or increased drilling and development activities.

Energen Resources' 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 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 gas reservoirs; and changes in management's intent to develop certain opportunities.

During the three years ended December 31, 2012, the Company's development and exploratory efforts have added 130 MMBOE of proved reserves from the drilling of 1,300 gross development, exploratory and service wells (including 18 sidetrack wells) and 326 well recompletions and pay-adds. In 2012, Energen Resources' successful development and exploratory wells and other activities added approximately 57 MMBOE of proved reserves; the Company drilled 434 gross development, exploratory and service wells (including 3 sidetrack wells), performed some 116 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources' production totaled 24.1 MMBOE in 2012 and is estimated to total 26.1 MMBOE in 2013, including 24.9 MMBOE of estimated production from proved reserves owned at December 31, 2012.

4

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

Years ended December 31,	2012	2011	2010
Development:
Productive	239.9	370.3	210.0
Dry	—	3.3	1.0
Total	239.9	373.6	211.0
Exploratory:
Productive	74.1	23.3	3.4
Dry	1.1	1.0	5.0
Total	75.2	24.3	8.4

As of December 31, 2012, the Company was participating in the drilling of 8 gross development and 4 gross exploratory wells, with the Company's interest equivalent to 6.9 wells and 3.3 wells, respectively. In addition to the development wells drilled, the Company drilled 47.8, 29.1 and 39.8 net service wells during 2012, 2011 and 2010, respectively.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2012, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

	Gross	Net
Oil wells	4,531	2,988
Gas wells	4,402	2,413
Developed acreage	810,862	614,697
Undeveloped acreage	171,723	117,762

There were 10 wells with multiple completions in 2012. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Texas and Colorado.

Risk Management: Energen Resources attempts to lower the commodity price risk associated with its oil and natural gas business through the use of swaps and basis hedges. Energen Resources does not hedge more than 80 percent of its estimated annual production. Energen Resources recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

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

5

• Natural Gas Distribution

General: Alagasco is the largest natural gas distribution utility in the state of Alabama. Alagasco purchases natural gas through interstate and intrastate suppliers and distributes the purchased gas through its distribution facilities for sale to residential, commercial and industrial customers and other end-users of natural gas. Alagasco also provides transportation services to large industrial and commercial customers located on its distribution system. These transportation customers, using Alagasco as their agent or acting on their own, purchase gas directly from marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system. Alagasco charges a fee to transport such customer-owned gas through its distribution system to the customers' facilities.

Alagasco's service territory is located in central and parts of north Alabama and includes 186 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.5 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During2012, Alagasco served an average of 393,467 residential customers and 31,450 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 11,298 miles of main and more than 11,899 miles of service lines, odorization and regulation facilities, and customer meters.

APSC Regulation: As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period ending December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year).

Alagasco's allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco's return on average equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation.

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

The APSC approved an Enhanced Stability Reserve (ESR) in 1998 which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year.

Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco anticipates recovering underfunded ESR balances over a five year period with an annual limitation of $660,000.

6

Gas Supply: Alagasco's distribution system is connected to two major interstate natural gas pipeline systems, Southern Natural Gas Company (Southern) and Transcontinental Gas Pipe Line Company (Transco). It is also connected to two intrastate natural gas pipeline systems and to Alagasco's two liquified natural gas (LNG) facilities.

Alagasco purchases natural gas from various natural gas producers and marketers. Certain volumes are purchased under firm contractual commitments with other volumes purchased on a spot market basis. The purchased volumes are delivered to Alagasco's system using a variety of firm transportation, interruptible transportation and storage capacity arrangements designed to meet the system's varying levels of demand. Alagasco's LNG facilities can provide the system with up to an additional 200,000 thousand cubic feet per day (Mcfd) of natural gas to meet peak day demand.

As of December 31, 2012, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:

	December 31, 2012
	(Mcfd)
Southern firm transportation	112,933
Southern storage and no notice transportation	231,679
Transco firm transportation	70,000
Various intrastate transportation	20,216

Competition: The price of natural gas is a significant competitive factor in Alagasco's service territory, particularly among large commercial and industrial transportation customers. Propane, coal and fuel oil are readily available, and many industrial customers have the capability to switch to alternate fuels and alternate sources of gas. In the residential and small commercial and industrial markets, electricity is the principal competitor. With the support of the APSC, Alagasco has implemented a variety of programs to help it compete for gas load in all market segments. The Company has been effective at utilizing these programs to avoid load loss to competitive fuels.

Alagasco’s Transportation Tariff allows the Company to transport gas for large commercial and industrial customers rather than buying and reselling it to them and is based on Alagasco's sales profit margin so that operating margins are unaffected. During 2012, substantially all of Alagasco's large commercial and industrial customer deliveries involved the transportation of customer-owned gas.

Natural gas service available to Alagasco customers falls into two broad categories: interruptible and firm. Interruptible service contractually is subject to interruption at Alagasco’s discretion. The most common reason for such interruption is curtailment during periods of peak core market heating demand. Customers who contract for interruptible service can generally adjust production schedules or switch to alternate fuels during periods of service interruption or curtailment. More expensive firm service, on the other hand, generally is not subject to interruption and is provided to residential and small commercial and industrial customers. These core market customers depend on natural gas primarily for space heating.

Customers: Alagasco is a mature utility operating in a slow-growth service area which includes municipalities that have in recent years experienced population declines. Alagasco's average customer count for 2012 declined approximately 0.6 percent from 2011 and reflected a moderation in decline over the five-year trend. Other factors impacting Alagasco's average customer account include recent warmer weather, enhanced credit and collection efforts and the loss of customers due to a 2011 weather event.

Seasonality:Alagasco's gas distribution business is highly seasonal since a material portion of the utility's total sales and delivery volumes relate to space heating customers. Alagasco's tariff includes a Temperature Adjustment Rider primarily for residential, small commercial and small industrial customers that moderates the impact of departures from normal temperatures on Alagasco's earnings. The adjustments are made through the GSA.

• Environmental Matters and Climate Change

Various federal, state and local environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company's financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

7

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 the Company to cost increases, and impose restrictions and limitations on the Company's operations. Currently, there are various proposed law and regulatory changes with the potential to materially impact the Company. Such proposals include, but are not limited to, measures dealing with hydraulic fracturing, emission limits and reporting and the repeal of certain oil and gas tax incentives and deductions. Due to the nature of the political and regulatory processes and based on its consideration of existing proposals, the Company is unable to determine whether such proposed laws and regulations are reasonably likely to be enacted or to determine, if enacted, the magnitude of the potential impact of such laws.

Energen regularly utilizes hydraulic fracturing in its drilling and completion activities. The Company'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 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 1% by volume) that can vary by project. The carefully designed, millimeter-thick cracks or fractures in the target formation are propped open by the sand, thereby allowing the natural gas or crude oil 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 that we are able to recover from our reserves. The degree to which additional oil and 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 the Company’s routine operations. The Company does not separately track costs associated with these routine compliance activities.

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

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

• positive or negative changes to usage and customer count at Alagasco from prolonged increases or decreases in average temperature for Alagasco’s central and north Alabama service territory;

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

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns and is the subject of a recent inquiry discussed below. Also discussed below is the recent completion of a removal action at the Huntsville, Alabama manufactured gas plant site. An investigation of the sites does not indicate the present need for other remediation activities and management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the financial position of Alagasco.

8

In May 2012, Alagasco received from the United States Environmental Protection Agency (EPA) a Request for information Pursuant to Section 104 of CERCLA relating to the EPA's investigation of a site which it refers to as the 35^th Avenue Superfund Site in and around Birmingham, Jefferson County, Alabama. The inquiry requests information about a parcel owned by Alagasco and located in the vicinity of the 35^th Avenue site. The parcel is the former site of a manufactured gas distribution facility. Alagasco has responded to the inquiry.

In June 2009, Alagasco received a General Notice Letter from the EPA identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949. While Alagasco no longer owns the Huntsville site, the Company and the current site owner entered into a Consent Order, and developed and completed during 2011 an action plan for the site. Alagasco has incurred costs associated with the site of approximately $5 million. As of December 31, 2012, the expected remaining costs are not expected to be material to the Company. Alagasco has recorded a corresponding amount, subject to APSC review guidelines, against the refundable negative salvage costs being refunded to customers.

• Employees

The Company has approximately 1,575 employees, of which Alagasco employs 1,087 and Energen Resources employs 488. The Company believes that its relations with employees are good.

9

ITEM 1A.RISK FACTORS

The future success and continued viability of Energen and its businesses, 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, and should not be viewed as complete or comprehensive. The Company undertakes 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 the Company’s disclosure specific to Forward-Looking Statements made elsewhere in this report.

Commodity prices for crude oil and natural gas are volatile, and a substantial reduction in commodity prices could adversely affect the Company's results and the carrying value of its oil and natural gas properties: The Company and Alagasco are significantly influenced by commodity prices. Historical markets for natural gas, oil and natural gas liquids have been volatile. Energen Resources’ revenues, operating results, profitability and cash flows depend primarily upon the prices realized for its oil, gas and natural gas liquid production. Additionally, downward commodity price trends may impact expected cash flows from future production and potentially reduce the carrying value of Company-owned oil and natural gas properties. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are passed-through to customers.

Market conditions or a downgrade in the Company's credit rating could negatively impact its cost of and ability to access capital for future development and working capital needs: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for both lenders and the Company. Market volatility and credit market disruption may severely limit credit availability and issuer credit ratings can change rapidly. Events negatively affecting credit ratings and credit market liquidity could increase borrowing costs or limit availability of funds to the Company.

Energen Resources' hedging activities may prevent Energen Resources from benefiting fully from price increases and expose Energen Resources to other risks, including counterparty credit risk:Although Energen Resources makes use of futures, swaps, options, collars and fixed-price contracts to mitigate price risk, fluctuations in future oil, gas and natural gas liquids prices could materially affect the Company's financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company's financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes 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 Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources' position. In addition, various existing and pending financial reform rules and regulations could have an adverse effect on the ability of Energen Resources to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

The Company is exposed to counterparty credit risk as a result of its concentrated customer base: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids 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 the Company's 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. Energen Resources 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.

The Company's operations depend upon the use of third party facilities and an interruption of its ability to utilize these facilities may adversely affect its financial condition and results of operations: Energen Resources delivers to and Alagasco is served by third party facilities. These facilities include third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Energen Resources, Alagasco and the Company.

10

The Company's oil and natural gas reserves are estimates, and actual future production may vary significantly and may also be negatively impacted by its inability to invest in production on planned timelines:There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.

The Company's operations involve operational risk including risk of personal injury, property damage and environmental damage and its insurance policies do not cover all such risks: Inherent in the oil and gas production activities of Energen Resources and the gas distribution activities of Alagasco are a variety of hazards and operation risks, such as:

• Pipeline and storage leaks, ruptures and spills;

• Equipment malfunctions and mechanical failures;

• Fires and explosions;

• Well blowouts, explosions and cratering; and

• Soil, surface 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 property, environmental pollution, impairment of operations and substantial financial losses. 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, the Company maintains insurance against some, but not all, of these risks and losses and the insurance coverages are subject to retention levels and coverage limits. The occurrence of any of these events could adversely affect Energen Resources', Alagasco's and the Company's financial positions, results of operations and cash flows.

Alagasco operates in a limited service territory and is therefore subject to concentrated regional risks which may negatively affect Alagasco's financial condition and results of operations: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.

The Company is subject to numerous federal, state and local laws and regulations that may require significant expenditures or impose significant restrictions on its operations:Energen and Alagasco are subject to extensive federal, state and local regulation which significantly influences operations. Although the Company believes that operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. 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 the Company to significant tax or cost increases and can impose significant restrictions and limitations on the Company's operations.

The Company's business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions:The Company relies on its information technology infrastructure to process, transmit and store electronic information critical for the efficient operation of its business and day-to-day operations. All information systems are potentially vulnerable to security threats, including hacking, viruses, other malicious software, and other unlawful attempts to disrupt or gain access to such systems. Breaches in the Company's information technology infrastructure could lead to a material disruption in its business, including the theft, destruction, loss, misappropriation or release of confidential data or other business information, and may have a material adverse effect on the Company's operations, financial position and results of operations.

ITEM 1B.UNRESOLVED STAFF COMMENTS

None

11

ITEM 2.    PROPERTIES

The corporate headquarters of Energen, Energen Resources and Alagasco are located in leased office space in Birmingham, Alabama. See the discussion under Item 1, Business, for further information related to Energen Resources’ and Alagasco’s business operations. Information concerning Energen Resources' production and reserves is summarized in the table below and included in Note 17, Oil and 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 Resources and Alagasco and additional information regarding Energen Resources’ production, revenue and production costs.

Oil and Gas Operations

Energen Resources focuses on increasing its production and proved reserves through the acquisition and development of onshore North American oil and gas properties. Energen Resources maintains district offices in Midland, Texas; Farmington, New Mexico; Arcadia, Louisiana; and Brookwood, Alabama.

The major areas of operations include (1) the Permian Basin, (2) the San Juan Basin, (3) the Black Warrior Basin and (4) North Louisiana/East Texas as highlighted on the above map.

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

	Year ended
	December 31, 2012	December 31, 2012	December 31, 2012
	Production Volumes (MBOE)	Proved Reserves (MBOE)	Reserves-to-Production Ratio
Permian Basin	11,198	225,006	20.09 years
San Juan Basin	9,921	100,910	10.17 years
Black Warrior Basin	2,120	16,165	7.63 years
North Louisiana/East Texas	763	3,394	4.45 years
Other	64	884	13.81 years
Total	24,066	346,359	14.39 years

12

The following table sets forth proved reserves by area as of December 31, 2012:

	Gas MMcf	Oil MBbl	NGL MBbl
Permian Basin	208,831	154,172	36,028
San Juan Basin	478,592	1,017	20,127
Black Warrior Basin	96,993	—	—
North Louisiana/East Texas	20,055	51	—
Other	4,657	108	—
Total	809,128	155,348	56,155

The following table sets forth proved developed reserves by area as of December 31, 2012:

	Gas MMcf	Oil MBbl	NGL MBbl
Permian Basin	127,443	104,825	17,725
San Juan Basin	459,509	992	18,715
Black Warrior Basin	96,993	—	—
North Louisiana/East Texas	20,055	51	—
Other	4,657	108	—
Total	708,657	105,976	36,440

The following table sets forth proved undeveloped reserves by area as of December 31, 2012:

	Gas MMcf	Oil MBbl	NGL MBbl
Permian Basin	81,388	49,347	18,303
San Juan Basin	19,083	25	1,412
Black Warrior Basin	—	—	—
North Louisiana/East Texas	—	—	—
Total	100,471	49,372	19,715

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

Year ended December 31, 2012	Total MMBOE
Balance at beginning of period	94.6
Undeveloped reserves transferred to developed reserves*	(24.6)
Revisions**	(28.2)
Acquisitions	10.2
Extensions and discoveries	33.9
Balance at end of period	85.9

* Reflects capital expenditures of approximately $443 million during the year ended December 31, 2012 in development of previously proved undeveloped reserves.

** The majority of the revisions relate to the five-year proved undeveloped reserve development rules (8.9 MMBOE) and to well performance (8.8 MMBOE).

Energen Resources files Form EIA-23 with the Department of Energy which reports gross proved reserves, including the working interest and royalty interest share of other owners, for properties operated by the Company. The proved reserves reported in the table above represent our share of proved reserves for all properties, based on our ownership interest in each property. For properties operated by Energen Resources, the difference between the gross proved reserves reported on Form EIA-23 and the gross reserves

13

associated with the Company-owned net proved reserves reported in the table above does not exceed five percent. Estimated proved reserves as of December 31, 2012 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 generally used in the Petroleum Industry and in accordance with Securities and Exchange Commission (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 Resources. 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.

The Company 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 2012, 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 Resources has wells:

Alabama, Texas	14.65 psia
Colorado	14.73 psia
Louisiana, New Mexico	15.025 psia

The following table sets forth the total net productive gas and oil wells by area as of December 31, 2012, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

	Net Wells	Net Developed Acreage	Net Undeveloped Acreage
Permian Basin	2,965	160,294	97,211
San Juan Basin	1,454	281,179	20,471
Black Warrior Basin	797	146,529	80
North Louisiana/East Texas	175	20,793	—
Other	10	5,902	—
Total	5,401	614,697	117,762

The net undeveloped acreage largely relates to the recent purchase of oil properties in the Permian Basin.

14

Energen Resources sells oil, natural gas, and natural gas liquids under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity (firm volumes). Energen Resources is contractually committed to deliver approximately 52 billion cubic feet (net) of natural gas through March 2014. The Company expects to fulfill delivery commitments through production of existing proved reserves.

	Gas MMcf
San Juan Basin	42,790
Black Warrior Basin	9,222
Total	52,012

Natural Gas Distribution

The properties of Alagasco consist primarily of its gas distribution system, which includes approximately 11,298 miles of main and more than 11,899 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two LNG facilities, thirteen operation centers, two business centers, and other related property and equipment, some of which are leased by Alagasco.

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 specific relief. 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 Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive or other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

On November 2, 2011 Energen Resources spudded the Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. During the drilling phase, Chesapeake Exploration, LLC, notified Energen Resources that it believed it was the owner of the lease from which the Cadenhead Well was producing. Shortly thereafter, Energen Resources filed a declaratory judgment action in the District Court of Ward County, Texas to resolve the title dispute. Energen Resources has a fifty percent working interest in the Cadenhead Well. The Cadenhead Well produced approximately 63 net MBOE in 2012 and is expected to produce approximately 42 net MBOE in 2013. On January 18, 2013, a judgment was entered which was adverse to Energen Resources' claim of ownership. The Company believes the adverse ruling was incorrect, and plans to vigorously pursue all available avenues of appeal.

Other

Various other pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for the estimated liability. See the Note 7, Commitments and Contingencies, in the Notes to Financial Statements for further discussion with respect to legal proceedings.

ITEM 4.    MINE SAFETY DISCLOSURES

None

15

EXECUTIVE OFFICERS OF THE REGISTRANTS

Name	Age	Position (1)
James T. McManus, II	54	Chairman, Chief Executive Officer and President of Energen and Chairman and Chief Executive Officer of Alagasco (2)
Charles W. Porter, Jr.	48	Vice President, Chief Financial Officer and Treasurer of Energen and Alagasco (3)
John S. Richardson	55	President and Chief Operating Officer of Energen Resources (4)
Dudley C. Reynolds	59	President and Chief Operating Officer of Alagasco (5)
J. David Woodruff, Jr.	56	Vice President, General Counsel and Secretary of Energen and Alagasco (6)
Russell E. Lynch, Jr.	39	Vice President and Controller of Energen (7)

Notes:    

(1) All executive officers of Energen have been employed by Energen or a subsidiary for the past five years. 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. Reynolds has been employed by the Company in various capacities since 1980. He was elected General Counsel and Secretary of Energen and each of its subsidiaries in April 1991. He was elected President and Chief Operating Officer of Alagasco effective January 1, 2003.

(6) 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.

(7) Mr. Lynch has been employed by the Company in various capacities since 2001. He became Energen’s Director of Financial Accounting in 2007. He was elected Vice President and Controller of Energen effective January 1, 2009.

16

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 (in dollars)	High	Low	Close	Dividends Paid
March 31, 2011	63.83	48.62	63.12	0.135
June 30, 2011	65.44	53.79	56.50	0.135
September 30, 2011	62.50	38.84	40.89	0.135
December 31, 2011	53.24	37.22	50.00	0.135
March 31, 2012	58.24	47.33	49.15	0.14
June 30, 2012	53.28	40.13	45.13	0.14
September 30, 2012	55.59	43.81	52.41	0.14
December 31, 2012	54.77	41.38	45.09	0.14

Energen's common stock is listed on the New York Stock Exchange under the symbol EGN. On February 15, 2013, there were 5,467 holders of record of Energen's common stock. At the date of this filing, Energen Corporation owned all the issued and outstanding common stock of Alabama Gas Corporation. Energen expects to pay annual cash dividends of $0.58 per share on the Company’s common stock in 2013. 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.

The following table summarizes information concerning securities authorized for issuance under equity compensation plans as of December 31, 2012:

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*	1,648,475	$	47.58	4,288,140
Equity compensation plans not approved by security holders	—	—		—
Total	1,648,475	$	47.58	4,288,140

* These plans include 3,418,881 shares associated with the Company’s Stock Incentive Plan, 162,904 shares associated with the 1992 Energen Corporation Directors Stock Plan and 706,355 shares associated with the 1997 Deferred Compensation Plan.

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, 2012 through October 31, 2012	943*	$	51.55	—	8,992,700
November 1, 2012 through November 30, 2012	—	—		—	8,992,700
December 1, 2012 through December 31, 2012	—	—		—	8,992,700
Total	943	$	51.55	—	8,992,700

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

** By resolution adopted May 24, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board of Directors authorized the Company to repurchase up to 12,564,400 shares of the Company's common stock. The resolutions do not have an expiration date.

17

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), the Standard & Poor’s Supercomposite Oil & Gas Exploration & Production Index (S15OILP), and the Standard & Poor’s Supercomposite Gas Utilities Index (S15GASUX). 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, 2007, in the Company and each of the indices. Total shareholder return includes reinvested dividends.

As of December 31,	2007		2008		2009		2010		2011		2012
S&P 500	$	100	$	63	$	80	$	92	$	94	$	109
Energen	$	100	$	46	$	75	$	78	$	81	$	74
S15OILP	$	100	$	63	$	91	$	103	$	95	$	97
S15GASUX	$	100	$	76	$	96	$	112	$	135	$	134

18

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

Energen Corporation

Years ended December 31, (dollars in thousands, except per share amounts)	2012		2011		2010		2009		2008
INCOME STATEMENT
Operating revenues	$	1,617,169	$	1,483,479	$	1,578,534	$	1,440,420	$	1,568,910
Net income	$	253,562	$	259,624	$	290,807	$	256,325	$	321,915
Diluted earnings per average common share	$	3.51	$	3.59	$	4.04	$	3.57	$	4.47
BALANCE SHEET
Total property, plant and equipment, net	$	5,541,636	$	4,620,776	$	3,719,227	$	3,144,469	$	2,867,648
Total assets	$	6,175,890	$	5,237,416	$	4,363,560	$	3,803,118	$	3,775,404
Long-term debt	$	1,103,528	$	1,153,700	$	405,254	$	410,786	$	561,631
Total shareholders' equity	$	2,676,690	$	2,432,163	$	2,154,043	$	1,988,243	$	1,913,920
COMMON STOCK DATA
Cash dividends paid per common share	$	0.56	$	0.54	$	0.52	$	0.50	$	0.48
Diluted average common shares outstanding (000)	72,316		72,332		72,051		71,885		72,030
Price range:
High	$	58.24	$	65.44	$	49.94	$	48.89	$	79.57
Low	$	40.13	$	37.22	$	40.25	$	23.18	$	23.00
Close	$	45.09	$	50.00	$	48.26	$	46.80	$	29.33

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SELECTED BUSINESS SEGMENT DATA

Energen Corporation

Years ended December 31, (dollars in thousands)	2012			2011			2010			2009			2008
OIL AND GAS OPERATIONS
Operating revenues
Natural gas	$	288,979		$	386,894		$	483,935		$	460,370		$	536,283
Oil	790,345			467,320			404,625			284,750			292,908
Natural gas liquids	85,938			87,466			65,161			67,254			68,216
Other	318			6,846			5,041			10,172			16,725
Total	$	1,165,580		$	948,526		$	958,762		$	822,546		$	914,132
Non-cash mark-to-market gains (losses) (included in operating revenues above)
Natural gas	$	(515	)	$	—		$	—		$	—		$	348
Oil	58,786			(37,473		)	(3		)	(107		)	—
Natural gas liquids	479			(114		)	—			—			—
Total	$	58,750		$	(37,587	)	$	(3	)	$	(107	)	$	348
Production volumes
Natural gas (MMcf)	76,362			71,718			70,924			72,337			67,573
Oil (MBbl)	8,766			6,318			5,131			4,690			4,114
Natural gas liquids (MMgal)	108.1			91.4			79.0			75.2			70.7
Total production volumes (MBOE)	24,066			20,448			18,832			18,537			17,059
Proved reserves
Natural gas (MMcf)	809,128			957,368			954,387			897,546			1,038,453
Oil (MBbl)	155,348			129,578			103,262			77,963			62,034
Natural gas liquids (MBbl)	56,155			53,957			40,601			30,257			28,953
Total (MMcfe)	2,078,154			2,058,594			1,817,565			1,546,866			1,584,375
Total (MBOE)	346,359			343,099			302,928			257,811			264,063
Other data
Lease operating expense
Lease operating expense and other	$	250,497		$	202,094		$	182,180		$	181,777		$	174,127
Production taxes	55,878			54,951			42,721			35,652			62,552
Total	$	306,375		$	257,045		$	224,901		$	217,429		$	236,679
Depreciation, depletion and amortization	$	377,328		$	244,081		$	203,823		$	184,089		$	139,539
Asset impairment	$	21,545		$	—		$	—		$	—		$	—
Capital expenditures	$	1,291,211		$	1,115,452		$	717,782		$	427,399		$	449,571
Exploration expense	$	19,363		$	13,110		$	64,584		$	10,234		$	9,296
Operating income	$	367,243		$	363,131		$	406,729		$	353,645		$	482,588
NATURAL GAS DISTRIBUTION
Operating revenues
Residential	$	277,698		$	343,740		$	414,870		$	398,289		$	410,106
Commercial and industrial	115,711			136,469			159,658			161,543			178,395
Transportation	58,857			55,234			57,049			53,856			51,723
Other	(677		)	(490		)	(11,805		)	4,186			14,554
Total	$	451,589		$	534,953		$	619,772		$	617,874		$	654,778
Gas delivery volumes (MMcf)
Residential	16,014			21,132			24,463			20,921			21,632
Commercial and industrial	8,372			9,994			10,985			9,934			10,934
Transportation	48,106			44,614			46,479			40,903			46,789
Total	72,492			75,740			81,927			71,758			79,355
Average number of customers
Residential	393,467			395,766			404,697			409,214			413,151
Commercial, industrial and transportation	31,450			31,840			32,632			33,264			33,911
Total	424,917			427,606			437,329			442,478			447,062

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Other data
Depreciation and amortization	$	42,270	$	39,916	$	44,042	$	50,995	$	48,874
Capital expenditures	$	71,869	$	73,984	$	93,566	$	77,809	$	63,320
Operating income	$	93,216	$	86,216	$	88,383	$	83,984	$	81,956

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

RESULTS OF OPERATIONS

Consolidated Net Income

Energen Corporation's net income for the year ended December 31, 2012 totaled $253.6 million, or $3.51 per diluted share compared to the year ended December 31, 2011 net income of $259.6 million, or $3.59 per diluted share. This 2.2 percent decrease in earnings per diluted share (EPS) largely reflected lower prices for natural gas and natural gas liquids, increased depreciation, depletion and amortization (DD&A) expense, a noncash impairment on certain natural gas properties in East Texas of approximately $13.4 million after-tax, higher lease operating expense excluding production taxes, increased interest expense, higher exploration expense and an after-tax gain of $3.6 million on the sale of certain oil properties in the Permian Basin during 2011. Positively affecting net income was the impact of a net 3.6 million barrels of oil equivalent (MMBOE) increase in production volumes from Energen Resources Corporation, Energen's oil and gas subsidiary, a year-over-year after-tax $60.6 million non-cash mark-to-market increase in derivatives (resulting from an after-tax $37.2 million non-cash mark-to-market gain on derivatives for 2012 and an after-tax $23.4 million non-cash mark-to-market loss on derivatives for 2011) and higher oil commodity prices. For the year ended December 31, 2012, Energen Resources earned $204.1 million, as compared with $213 million in the previous year. Alabama Gas Corporation (Alagasco), Energen's utility subsidiary, generated net income of $49.4 million in the current year as compared with net income in the prior period of $46.6 million. For the year ended December 31, 2010, Energen reported net income of $290.8 million, or $4.04 per diluted share.

During 2011, the Company expanded its risk management program for commodity price exposure to include hedges for production in future years not yet currently flowing. These hedges, while not qualifying as cash flow hedges, are considered valid economic hedges and are accounted for as mark-to-market transactions. The mark-to-market hedges are expected to provide further risk mitigation of future cash flows from operations and to provide support for the Company's planned capital expenditures. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains and losses recognized in operating revenues. Revenues per unit of production, as discussed under Oil and Gas Operations, include realized prices and the effects of designated cash flow hedges and exclude the impact of the mark-to-market hedges.

2012 vs 2011: For the year ended December 31, 2012, Energen Resources' net income totaled $204.1 million as compared to $213 million in the prior year. Lower natural gas and natural gas liquids commodity prices of approximately $90 million after-tax, increased DD&A expense of approximately $86 million after-tax, a noncash impairment on certain natural gas properties in East Texas of approximately $13.4 million after-tax, higher lease operating expense of approximately $31 million after-tax, increased interest expense of approximately $12 million after-tax, higher exploration expense of approximately $4 million after-tax, the 2011 after-tax gain on the $3.6 million sale of certain oil properties were partially offset by increased production volumes of approximately $152 million after-tax, a year-over-year after-tax $60.6 million non-cash mark-to-market increase in derivatives (resulting from an after-tax $37.2 million non-cash mark-to-market gain on derivatives for 2012 and an after-tax $23.4 million non-cash mark-to-market loss on derivatives for 2011) and higher oil commodity prices of approximately $21 million after-tax.

Alagasco's net income of $49.4 million in 2012 compared to net income of $46.6 million in 2011. This increase in earnings largely reflected the utility’s ability to earn on a higher level of equity in support of Alagasco's investment in its distribution system and support systems devoted to public service.

2011 vs 2010: Energen Resources' net income totaled $213 million in 2011 as compared with $245.3 million in 2010 primarily due to decreased natural gas commodity prices of approximately $64 million after-tax, an after-tax $23.4 million non-cash mark-to-market loss on derivatives, higher DD&A expense of approximately $25 million after-tax, higher lease operating expense of approximately $12 million after-tax, increased production taxes of approximately $8 million and higher administrative expense of approximately $7 million after-tax. These decreases were partially offset by the impact of greater production volumes of approximately $68 million after-tax, lower exploration expense of approximately $32 million after-tax, higher oil and natural gas liquids commodity prices of approximately $12 million after-tax and the after-tax gain of $3.6 million on the sale of certain oil properties in the Permian Basin.

Alagasco earned net income of $46.6 million in 2011 as compared with net income of $46.9 million in 2010 which primarily reflects the timing of rate recovery under Alagasco's rate-setting mechanisms largely offset by the utility’s ability to earn on a higher level of equity in support of Alagasco's investment in its distribution system and support systems devoted to public service.

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Operating Income

Consolidated operating income in 2012, 2011 and 2010 totaled $459.4 million, $448.3 million and $493.4 million, respectively. Growth in operating income for 2012 was influenced by increased production and higher oil commodity prices partially offset by lower natural gas and natural gas liquids commodity prices. The decrease in operating income for 2011 is primarily due to significantly lower natural gas commodity prices partially offset by increased production at Energen Resources and higher oil and natural gas liquids commodity prices. During 2012 and 2011, Alagasco contributed to operating income consistent with the level of equity supporting the investment in its distribution system and support systems devoted to public service.

Oil and Gas Operations: Revenues from oil and gas operations increased in the current year largely as a result of significantly higher production volumes and higher oil commodity prices partially offset by lower natural gas and natural gas liquids commodity prices. Production increased due to higher volumes related to increased field development in certain Permian Basin properties and increased volumes related to acquisitions of certain Permian Basin properties partially offset by normal production declines. Revenue per unit of production for natural gas production fell 29.7 percent to $3.79 per thousand cubic feet (Mcf), oil revenue per unit of production increased 4.4 percent to $83.45 per barrel and natural gas liquids revenue per unit of production fell 17.7 percent to $0.79 per gallon during 2012. Production rose 17.7 percent to 24.1 MMBOE during 2012. Natural gas production increased 6.5 percent to 76.4 billion cubic feet (Bcf) while oil volumes rose 38.7 percent to 8,766 thousand barrels (MBbl). Production of natural gas liquids increased 18.3 percent to 108.1 million gallons (MMgal). Revenues per unit of production include realized prices and the effects of designated cash flow hedges and exclude the impact of the mark-to-market hedges.

In 2011, revenues from oil and gas operations decreased largely as a result of significantly lower natural gas commodity prices partially offset by the impact of increased natural gas, oil and natural gas liquids production volumes and higher oil and natural gas liquids commodity prices. Production increased due to increased volumes related to the September 2010 and December 2010 purchases of certain Permian Basin properties and field development partially offset by normal production declines. During 2011, revenue per unit of production for natural gas production fell 21 percent to $5.39 per Mcf, oil revenue per unit of production rose 1.3 percent to $79.90 per barrel and natural gas liquids revenue per unit of production increased 15.7 percent to $0.96 per gallon. Production rose 8.6 percent to 20.4 MMBOE during 2011. Natural gas production increased 1.1 percent to 71.7 Bcf while oil volumes rose 23.1 percent to 6,318 MBbl. Production of natural gas liquids increased 15.7 percent to 91.4 MMgal.

Operating fees from coalbed methane operations are calculated as a percentage of net proceeds on certain properties, as defined by the related operating agreements, and vary with changes in natural gas prices, production volumes and operating expenses.

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Years ended December 31, (in thousands, except sales price data)	2012			2011			2010
Operating revenues
Natural gas	$	288,979		$	386,894		$	483,935
Oil	790,345			467,320			404,625
Natural gas liquids	85,938			87,466			65,161
Operating fees	1,921			3,228			3,650
Other	(1,603		)	3,618			1,391
Total operating revenues	$	1,165,580		$	948,526		$	958,762
Non-cash mark-to-market gains (losses) (included in operating revenues above)
Natural gas	$	(515	)	$	—		$	—
Oil	58,786			(37,473		)	(3		)
Natural gas liquids	479			(114		)	—
Total	$	58,750		$	(37,587	)	$	(3	)
Production volumes
Natural gas (MMcf)	76,362			71,718			70,924
Oil (MBbl)	8,766			6,318			5,131
Natural gas liquids (MMgal)	108.1			91.4			79.0
Total production volumes (MBOE)	24,066			20,448			18,832
Permian Basin - Spraberry Trend production volumes (included in production volumes above)*
Natural gas (MMcf)	3,592			1,650			554
Oil (MBbl)	2,134			1,136			447
Natural gas liquids (MMgal)	25.8			14.7			6.3
Total production volumes (MBOE)	3,347			1,762			689
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (per Mcf)	$	3.79		$	5.39		$	6.82
Oil (per barrel)	$	83.45		$	79.90		$	78.86
Natural gas liquids (per gallon)	$	0.79		$	0.96		$	0.83
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (per Mcf)	$	2.71		$	3.93		$	4.22
Oil (per barrel)	$	87.56		$	90.53		$	75.06
Natural gas liquids (per gallon)	$	0.75		$	1.11		$	0.86
Average production (lifting) cost (per BOE)	$	9.45		$	9.08		$	8.90
Average production tax (per BOE)	$	2.32		$	2.69		$	2.27
Average DD&A rate (per BOE)	$	15.50		$	11.75		$	10.63

* The Spraberry Trend in the Permian Basin contained 15 percent or more of the Company's total proved reserves as of December 31, 2012

Operations and maintenance (O&M) expense rose $56.5 million in 2012 and decreased $19.6 million in 2011. Lease operating expense (excluding production taxes) generally reflects year over year increases in the number of active wells resulting from Energen Resources' ongoing development, exploratory and acquisition activities. In 2012, lease operating expense (excluding production taxes) increased $48.4 million largely due to increased water disposal costs (approximately $14.5 million), higher workover and repair expense (approximately $8.4 million), higher ad valorem taxes (approximately $6.4 million), Permian Basin liquids-rich oil property acquisitions (approximately $5 million), additional equipment rental expense (approximately $3.5 million), increased marketing and transportation costs (approximately $3.2 million), increased chemical and treatment costs (approximately $2.5 million), additional electrical costs (approximately $2 million), increased labor costs (approximately $1.6 million), higher environmental compliance expense (approximately $1.1 million) and increased nonoperated costs (approximately $1.1 million) partially offset by decreased other O&M expense (approximately $4 million). During 2011, lease operating expense (excluding

24

production taxes) increased $19.9 million largely due to additional workover and repair expense (approximately $6.5 million), increased marketing and transportation costs (approximately $2.5 million), the Permian Basin property acquisitions (approximately $2.4 million), higher labor costs (approximately $1.8 million), additional water disposal costs (approximately $1.8 million), higher ad valorem taxes (approximately $1.4 million) and increased chemical usage (approximately $1.2 million). On a per unit basis, the average lease operating expense (excluding production taxes) for 2012 was $10.41 per barrel of oil equivalent (BOE) as compared to $9.88 per BOE in the same period a year ago. Administrative expense rose $1.8 million in 2012 largely due to increased labor costs (approximately $4 million) partially offset by decreased costs from the Company's benefit and performance based compensation plans (approximately $2.5 million). In 2011, administrative expense rose $12 million primarily due to higher labor costs (approximately $4 million), increased costs related to the Company’s performance-based compensation plans (approximately $3.9 million) and increased legal expenses (approximately $3 million). Exploration expense rose $6.3 million during 2012 primarily due to charges incurred of $5.3 million for unproved capitalized leasehold costs. Exploration expense fell $51.5 million during 2011 largely due to charges incurred during 2010 of $39.7 million for unproved capitalized leasehold costs and $15.5 million for well costs, all related to Alabama shale leasehold.

DD&A expense increased $154.8 million in 2012, which includes an impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of certain properties to their fair value based on expected future discounted cash flows, and $40.3 million in 2011. The average DD&A rates were $15.50 per BOE in 2012 (excluding the asset impairment), $11.75 per BOE in 2011 and $10.63 per BOE in 2010. The increase in the 2012 and 2011 per unit DD&A rates, which contributed approximately $64.1 million and $22.9 million, respectively, to the increase in DD&A expense, was primarily due to higher rates resulting from the acquisition of properties and an increase in development costs. Increased production volumes also contributed approximately $90.1 million and $17.2 million to the increase in DD&A expense in 2012 and 2011, respectively.

Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes. Energen Resources recorded severance taxes of $55.9 million, $55 million and $42.7 million for 2012, 2011 and 2010, respectively. Severance taxes were $0.9 million higher in 2012 resulting from higher production volumes largely offset by lower commodity market prices. Increased production volumes contributed approximately $9.7 million to the increase in severance taxes while decreased commodity market prices lowered severance taxes by approximately $8.8 million. In 2011, severance taxes were $12.2 million higher resulting from increased oil and natural gas liquids commodity market prices and higher production volumes. Higher commodity market prices and the impact of increased production volumes contributed approximately $8.6 million and $3.7 million to the increase in severance taxes, respectively. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution: As discussed more fully in Note 2, Regulatory Matters, in the Notes to Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) and is allowed to earn a range of return of 13.15 percent to 13.65 percent on average equity throughout the term of the Rate Stabilization and Equalization (RSE) order. RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Given existing economic conditions, Alagasco expects only modest growth in equity as annual dividends are typically paid by the utility.

Under the inflation-based Cost Control Management (CCM) established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation.

Alagasco generates revenues through the sale and transportation of natural gas. The transportation rate does not contain an amount representing the cost of gas, and Alagasco's rate structure allows similar margins on transportation and sales gas. Weather can cause variations in space heating revenues; as such, Alagasco’s tariff provides a temperature adjustment mechanism that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers and is adjusted through the Gas Supply Adjustment rider (GSA). Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

Alagasco's natural gas and transportation sales revenues totaled $451.6 million, $535.0 million and $619.8 million in 2012, 2011 and 2010, respectively. Sales revenue in 2012 fell primarily due to decreased customer usage of approximately $53 million and a decline in gas cost of approximately $38 million. In 2012, Alagasco had net reduction in revenues of $6.3 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. During the year ended December 31, 2011,

25

Alagasco had net reduction in revenues of $6.7 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. In 2012, weather that was 27.1 percent warmer than in the prior year contributed to a 24.2 percent decrease in residential sales volumes and a 16.2 percent decline in commercial and industrial volumes. Transportation volumes rose 7.8 percent. In 2011, sales revenue declined largely due to a decrease in gas costs of approximately $44 million and a decline in customer usage of approximately $39 million. Adjustments from the utility’s rate setting mechanisms also partially offset the decrease in revenues as Alagasco had net reduction in revenues of $6.7 million pre-tax in 2011, as discussed above. During the year ended December 31, 2010, Alagasco had a net reduction in revenues of $17.4 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. Weather was 15.4 percent warmer in 2011 than in the prior year. Residential sales volumes declined 13.6 percent while commercial and industrial volumes decreased 9 percent. Transportation volumes fell 4 percent. A significant decrease in gas purchase volumes combined with a decrease in gas costs resulted in a 39.1 percent decrease in cost of gas in 2012. In 2011, lower gas costs along with decreased gas purchase volumes contributed to a 26.3 percent decrease in cost of gas.

O&M expense at the utility rose 1.7 percent in 2012 largely due to higher business development and marketing expense (approximately $1.9 million), increased distribution operations (approximately $0.8 million), additional technology costs (approximately $0.6 million) and increased legal expense (approximately $0.4 million) partially offset by decreased bad debt expense (approximately $2.3 million) impacted by warmer weather in the current year and enhanced credit and collection processes implemented in 2011. O&M expense at the utility rose 7.9 percent in 2011 largely due to increased labor-related costs (approximately $3 million), higher marketing expenses (approximately $2.7 million), increased distribution operation expenses (approximately $1.3 million), increased bad debt expense (approximately $0.9 million) and additional consulting and technology costs (approximately $0.8 million). Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2012, 2011 and 2010.

Depreciation expense increased 5.9 percent in 2012 largely due to the extension and replacement of the utility's distribution system and replacement of its support systems. In 2011, depreciation expense decreased 9.4 percent primarily due to revised depreciation rates effective June 1, 2010, partially offset due to the extension and replacement of the utility's distribution system and replacement of its support systems. The revised depreciation rates decreased depreciation expense by approximately $6.8 million for the year ended December 31, 2011 from expense amounts calculated using the prior depreciation rate. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates. Approved depreciation rates averaged approximately 3.2 percent, 3.1 percent and 3.6 percent in the years ended December 31, 2012, 2011 and 2010, respectively.

Alagasco's expense for taxes other than income primarily reflects various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Years ended December 31, (in thousands)	2012			2011			2010
Natural gas transportation and sales revenues	$	451,589		$	534,953		$	619,772
Cost of natural gas	(142,228		)	(233,523		)	(316,988		)
Operations and maintenance	(141,334		)	(139,030		)	(128,830		)
Depreciation	(42,270		)	(39,916		)	(44,042		)
Income taxes	(30,244		)	(26,670		)	(29,875		)
Taxes, other than income taxes	(32,541		)	(36,268		)	(41,529		)
Operating income	$	62,972		$	59,546		$	58,508
Natural gas sales volumes (MMcf)
Residential	16,014			21,132			24,463
Commercial and industrial	8,372			9,994			10,985
Total natural gas sales volumes	24,386			31,126			35,448
Natural gas transportation volumes (MMcf)	48,106			44,614			46,479
Total deliveries (MMcf)	72,492			75,740			81,927

26

Non-Operating Items

Consolidated: Interest expense rose $20.7 million and $5.6 million in 2012 and 2011, respectively, largely due to the August 2011 issuance of $400 million of Senior Notes by Energen with an interest rate of 4.625 percent, the December 2011 issuance of $50 million of Senior Notes by Alagasco with an interest rate of 3.86 percent and the November 2011 issuance of $300 million of Senior Term Loans. The $300 million issuance includes $100 million with a floating rate of LIBOR plus 1.375 percent, currently 1.59 percent at December 31, 2012 and $200 million swapped to a fixed rate at 2.4175 percent. These increases in interest expense for 2011 were partially offset by the repayment of $150 million of medium-term notes with an interest rate of 7.625 percent in December 2010. Higher short-term borrowings also contributed to the increase in interest expense for both years. The average daily outstanding balance under credit facilities was $331.1 million in 2012. The average daily outstanding balance under credit facilities was $229.1 million in 2011 as compared to $19.7 million in 2010. Income tax expense decreased in 2012 and 2011 largely due to lower pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

The Company's net cash from operating activities totaled $735.7 million, $761.8 million and $671.0 million in 2012, 2011 and 2010, respectively. Net income decreased during 2012 largely due to lower realized natural gas and natural gas liquids commodity prices partially offset by increased production volumes at Energen Resources and higher oil commodity prices. The Company’s working capital needs were also influenced by accrued taxes along with commodity prices, and the timing of payments and recoveries, including gas supply pass-through adjustments. During 2011, net income decreased largely due to lower realized natural gas commodity prices partially offset by increased production volumes at Energen Resources and higher oil and natural gas liquids commodity prices. During 2011, the income tax receivable decreased approximately $37.1 million primarily from an income tax refund associated with the 2010 impact of bonus depreciation and the write-off of Alabama shale leasehold. Net income increased during 2010 largely due to higher realized commodity prices along with an increase in production volumes at Energen Resources. During 2010, the income tax receivable increased approximately $39.9 million associated with the impact of bonus depreciation and the write-off of Alabama shale leasehold. Working capital needs during 2012, 2011 and 2010 at Alagasco were largely affected by lower gas costs compared to the prior period, accrued taxes and storage gas inventory. Other working capital items, which primarily are the result of changes in throughput and the timing of payments and recoveries, including gas supply pass-through adjustments, combined to create the remaining increases in all years.

The Company made net investments of $1,322.2 million during 2012. Energen Resources invested $139.6 million in property acquisitions including approximately $58.6 million of unproved leaseholds; $692.4 million for development costs (excludes 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 (including the effects of closing adjustments). This purchase had an effective date of December 1, 2011. Energen acquired total proved reserves of approximately 8.2 MMBOE. Energen Resources had cash proceeds in 2012 of $3 million primarily from the sale of certain Black Warrior Basin properties. Utility expenditures in 2012 totaled $69.9 million (excludes approximately $1.3 million of accrued capital cost) and primarily represented expansion and replacement of its distribution system and replacement of its support facilities and information systems. During 2011, the Company made net investments of $1,193.5 million. Energen Resources invested $310.2 million in property acquisitions including approximately $91.9 million of unproved leaseholds; $618 million for development costs (excludes the reversal of approximately $1 million of accrued development cost) including approximately $520 million to drill 403 net development and service wells; and $188.7 million for exploration including approximately $178.8 million to drill 24 net exploratory wells. In November 2011, Energen Resources completed a purchase of liquids-rich properties located in the Permian Basin for a cash price of approximately $162 million adding approximately 13.6 MMBOE in proved reserves. Energen Resources completed, in December 2011, a purchase of oil properties located in the Permian Basin for a cash price of approximately $60 million. The acquisition added approximately 3.4 MMBOE in proved reserves. Energen Resources had cash proceeds in 2011 of $8 million primarily from the sale of certain Permian and Black Warrior basin properties. Utility expenditures in 2011 totaled $73.4 million (includes approximately $0.4 million of accrued capital cost). During 2010, the Company made net investments of $842.7 million. Energen Resources invested $410.3 million in property acquisitions including approximately $201.9 million of unproved leaseholds, $301.2 million for development costs (excludes approximately $26.6 million of accrued development cost) including approximately $258.2 million to drill 251 net development and service wells and $36.5 million for exploration. In September 2010, Energen Resources completed a purchase of oil properties located in the Permian Basin for a cash price of approximately $188 million adding approximately 18 MMBOE in proved reserves. Energen Resources completed, in December 2010, a purchase of oil properties located in the Permian Basin for a cash price of approximately $74 million. The acquisition added approximately 7.6 MMBOE in proved reserves. Energen Resources also completed in December 2010, the purchase of oil properties with only unproved reserves in the Permian Basin for a cash price of $103 million. Energen Resources had cash proceeds in 2010 of $3.2 million primarily from the sale of certain Permian and Black Warrior basin properties. Utility expenditures in 2010 totaled $92.1 million (excludes approximately $0.5 million of accrued capital cost).

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During 2012, the Company added approximately 12 MMBOE of reserves primarily from the Permian Basin oil property acquisitions. Also during 2012, Energen Resources added 57 MMBOE of reserves from discoveries and other additions, primarily the result of development and exploratory drilling that increased the number of proved undeveloped locations in the Permian Basin. Energen Resources added approximately 66 MMBOE and 53 MMBOE of reserves in 2011 and 2010, respectively.

The Company provided $586.6 million from net financing activities in 2012 largely from an increase in short-term borrowings used to fund development activity at Energen Resources. In 2011, the Company provided $418.6 million from net financing activities largely from the August 2011 issuance of $400 million of Senior Notes by Energen with an interest rate of 4.625 percent, the December 2011 issuance of $50 million of Senior Notes by Alagasco with an interest rate of 3.86 percent and the November 2011 issuance of $300 million of Senior Term Loans with a floating interest rate, partially offset by a decrease in short-term debt borrowings. In 2010, the Company provided $118.5 million from financing activities primarily from an increase in short-term debt borrowings partially offset by the payment of current maturities for long-term debt of $150.7 million. In addition, long-term debt was reduced by $1.2 million and $5.5 million for current maturities in 2012 and 2011, respectively. For each of the years, net cash used in financing activities also reflected dividends paid to common shareholders.

Capital Expenditures

Oil and Gas Operations: Capital projects at Energen Resources are detailed below. The expanded exploratory expenditures are the result of our activities following the acquisitions of significant unproved leasehold in the Permian Basin.

Years ended December 31, (in thousands)	2012		2011		2010
Capital and exploration expenditures for:
Property acquisitions	$	138,496	$	306,881	$	409,042
Development	748,251		621,550		331,850
Exploration	416,678		188,660		36,455
Other	4,543		9,277		4,103
Total	1,307,968		1,126,368		781,450
Less exploration expenditures charged to income	16,757		10,916		63,668
Net capital expenditures	$	1,291,211	$	1,115,452	$	717,782

Natural Gas Distribution: Capital projects at Alagasco are detailed below.

Years ended December 31, (in thousands)	2012		2011		2010
Capital expenditures for:
Renewals, replacements, system expansion and other	$	50,075	$	53,970	$	68,774
Support systems and facilities	21,794		20,014		24,792
Total	$	71,869	$	73,984	$	93,566

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FUTURE CAPITAL RESOURCES AND LIQUIDITY

Oil and Gas Operations

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2013, the Company expects its oil and gas capital spending to total approximately $905 million, including $765 million for existing properties and $130 million for exploration. Included in this $765 million is approximately $487 million for the development of previously identified proved undeveloped reserves.

Capital expenditures by area during 2013 are planned as follows:

Year ended December 31, (in thousands)	2013
Permian Basin	$	745,000
San Juan Basin	20,000
Exploration	130,000
Other	10,000
Total	$	905,000

Energen anticipates having the following drilling rigs and net wells by area during 2013. The drilling rigs presented below are operated while the net wells include operated and non-operated wells.

	Drilling Rigs	Net Wells
Permian Basin	17 – 19	299

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company expects to use internally generated cash flow supplemented by its credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company currently has no plans for the issuance of equity.

Impairment

During the first quarter of 2012, Energen Resources recognized a noncash 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. 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 was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

During 2010, Energen Resources incurred write-offs of unproved capitalized leasehold costs associated with its Alabama shale acreage. The non-cash charges totaled $39.7 million pre-tax and were charged to exploration expense, which is included in O&M expense, after the Company determined that the shale acreage was not economically viable. Energen Resources also recorded $15.5 million pre-tax in write-offs of well costs related to Alabama shale leasehold.

Natural Gas Distribution

Alagasco's rate schedules for natural gas distribution charges contain a GSA rider which permits the pass-through to customers for changes in the cost of gas supply. The GSA rider is designed to capture the Company's cost of natural gas and provides for a pass-through of gas cost fluctuations to customers without markup; the cost of gas includes the commodity cost, pipeline capacity, transportation and fuel costs, and risk management realized gains and losses.

Alagasco is a mature utility operating in a slow-growth service area which includes municipalities that have in recent years experienced population declines. Alagasco's average customer count for 2012 declined approximately 0.6 percent from 2011 and reflected a moderation in decline over the five-year trend. Other factors impacting Alagasco's average customer account include

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recent warmer weather, enhanced credit and collection efforts and the loss of customers due to a 2011 weather event. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices and the underlying current and future economic conditions facing the utility's customer base. During the year ended December 31, 2012, Alagasco reduced the bad debt reserve by approximately $6.4 million primarily due to certain aged receivables transitioned to the utility's long-term collections, in addition to the impact of its collection related initiatives.

Alagasco maintains an investment in storage gas that is expected to average approximately $34 million in 2013 but will vary depending upon the price of natural gas. During 2013, Alagasco plans to invest approximately $75 million in capital expenditures for the normal needs of its distribution and support systems and technology-related projects designed to improve customer service. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities. Alagasco also may issue long-term debt periodically to replace short-term obligations, enhance liquidity and provide for permanent financing.

Stock Repurchases

Energen periodically considers stock repurchases as a capital investment. Energen may buy shares on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. The Company did not repurchase shares of common stock for this program during 2012, 2011 or 2010. The Company expects any future stock repurchases to be funded through internally generated cash flows or through the utilization of credit facilities. During 2012, the Company had noncash purchases of approximately $0.3 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation plans. The Company utilized internally generated cash flows in payment of the related tax withholdings.

Credit Facilities

Access to capital is an integral part of the Company's business plan. While the Company expects to have ongoing access to its credit facilities and the longer-term markets, continued access could be adversely affected by current and future economic and business conditions and credit rating downgrades. On October 30, 2012, Energen and Alagasco entered into $1,250 million and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. These syndicated credit facilities replace Energen's $850 million and Alagasco's $150 million three-year syndicated credit facilities. Energen obligations under the $1,250 million syndicated credit facility are unconditionally guaranteed by Energen Resources. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of not more than 65 percent for both the Company and Alagasco. Both the Company and Alagasco were in compliance with the terms of the syndicated credit facilities at December 31, 2012.

Working Capital

At December 31, 2012, the Company reported negative working capital of $734.7 million arising from current liabilities of $1,159.8 million exceeding current assets of $425.1 million. The negative working capital is primarily due to a $628 million increase in borrowing under the syndicated unsecured credit facilities and in support of Energen's 2012 capital projects. Generally Accepted Accounting Principles require classification as short term for obligations such as these that are subject to the execution of individual notes with maturity dates less than one year. The syndicated unsecured credit facilities were entered into on October 30, 2012 and have a five-year term. Accordingly, the Company believes that it has adequate financing capacity available for its expected liquidity needs.

Working capital of Energen is also influenced by the fair value of the Company's derivative financial instruments associated with future production, and working capital of Alagasco is additionally impacted by the recovery and pass-through of regulatory items and the seasonality of Alagasco's business. Energen's accounts receivable and accounts payable at December 31, 2012 include $64.8 million and $2.6 million, respectively, associated with its derivative financial instruments. Working capital at Alagasco reflects an expected pass-through to rate payers of $18.3 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates. Energen and Alagasco rely upon cash flows from operations supplemented by its syndicated unsecured credit facilities to fund working capital needs.

Credit Ratings

Energen and Alagasco's current debt ratings by Standard & Poor's are considered investment grade with a stable outlook. Energen and Alagasco's current debt ratings by Moody's Investor Service are considered investment grade (provisional) with a revised outlook as of January 28, 2013 of "ratings under review down from stable.”

Dividends

Energen expects to pay annual cash dividends of $0.58 per share on the Company’s common stock in 2013. 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.

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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 the Company's significant contractual cash obligations, other than hedging contracts, as of December 31, 2012:

	Payments Due before December 31,
(in thousands)	Total		2013		2014-2015		2016-2017		2018 and Thereafter
Short-term debt	$	643,000	$	643,000	$	—	$	—	$	—
Long-term debt (1)	1,154,028		50,000		280,000		119,000		705,028
Interest payments on debt	485,393		52,557		95,806		79,146		257,884
Purchase obligations (2)	59,287		36,278		14,279		5,699		3,031
Capital lease obligations	3,577		1,730		1,847		—		—
Operating leases	35,653		5,144		9,342		8,121		13,046
Asset retirement obligations (3)	695,932		11,891		5,274		6,248		672,519
Nonqualified supplemental retirement plans	40,500		3,834		3,841		4,924		27,901
Total contractual cash obligations	$	3,117,370	$	804,434	$	410,389	$	223,138	$	1,679,409

(1) Long-term cash obligations include $0.5 million of unamortized debt discounts as of December 31, 2012.

(2) Certain of the Company's long-term contracts associated with the delivery and storage of natural gas include fixed charges of $59 million through September 2024. The Company also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 171 Bcf through August 2020.

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

Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources 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 33.4 million barrels of oil equivalent (MMBOE) through November 2021.

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources' total resulting exposure could be as much as $21.9 million depending on the contractor's ability to remarket the drilling rigs.

There are no required contributions to the qualified pension plans during 2013. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $9.0 million to the qualified pension plans in January 2013. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2013. The Company expects to make discretionary payments of approximately $1.6 million to postretirement benefit program assets during 2013. The contractual obligations reported above exclude any payments the Company expects to make to postretirement benefit program assets.

The contractual obligations reported above exclude the Company's liability of $12.6 million related to the Company’s provision for uncertain tax positions. The Company cannot make a reasonably reliable estimate of the amount and period of related future payments for such liability.

During the third quarter of 2011, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted on behalf of the Office of Natural Resources Revenue

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(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 ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company's New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department's findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of December 31, 2012.

OUTLOOK

Oil and Gas Operations: Energen Resources plans to continue to implement its growth strategy with capital spending in 2013. Production in 2013 is estimated to be 26.1 MMBOE, including approximately 24.9 MMBOE of estimated production from proved reserves owned at December 31, 2012. Production estimates do not include amounts for potential future acquisitions. In the event Energen Resources 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)	2013
Permian Basin	14.7
San Juan Basin	9.0
Black Warrior Basin	2.0
North Louisiana/East Texas	0.4
Total	26.1

Production volumes by commodity are expected to be as follows:

Year ended December 31, (MMBOE)	2013
Gas	12.1
Oil	10.6
Natural gas liquids	3.4
Total	26.1

During 2013, Energen Resources expects an annualized decline rate of approximately 12.5 percent for its proved developed producing properties owned at December 31, 2012. During the same period, total production from proved properties is expected to increase approximately 3.4 percent and total production is expected to increase approximately 8.8 percent. The above proved developed producing properties decline rate is not necessarily indicative of the Company’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 Resources expects a compound annual decline rate for proved producing properties owned at December 31, 2012 of approximately 11.1 percent for the 10 year period 2012 to 2022.

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Energen Resources' major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, national supply and demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, worldwide political developments and actions of the Organization of 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. Additionally, downward commodity price trends may impact expected cash flows from future production and potentially reduce the carrying value of Company-owned oil and natural gas properties.

Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids 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 the Company's overall exposure to credit risk, either positively or negatively, in that the Company's oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources 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.

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. At December 31, 2012, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with twelve of its active counterparties and in a net loss position with the remaining two at December 31, 2012. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Energen Resources does not hedge more than 80 percent of its estimated annual production.

In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors. Alagasco has not entered into any new cash flow derivative transactions on its gas supply since 2010. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco's APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

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Energen Resources entered into the following transactions for 2013 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Oil
2013	8,858	MBbl	$90.95 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	*720	MBbl	$90.10 Bbl	NYMEX Swaps
Oil Basis Differential
2013	3,592	MBbl	$(3.03) Bbl	WTS/WTI Basis Swaps**
	2,760	MBbl	$(1.01) Bbl	WTI/WTI Basis Swaps***
	*925	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps***
Natural Gas Liquids
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
* Contract entered into subsequent to December 31, 2012
**WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
***WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Alagasco entered into the following natural gas transactions for 2013:

Production Period	Total Hedged Volumes	Description
2013	1.5 Bcf	NYMEX Swaps

Energen Resources has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of crude oil, natural gas and natural gas liquids 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, 2012, Energen Resources was in a net gain position of $95.8 million for derivative contracts and estimates that a 10 percent increase or decrease in the commodities prices would have resulted in an approximate $205 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 1, Summary of Significant Accounting Policies, in the Notes to Financial Statements. Over-the-counter derivatives are valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These 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 the Company is 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 New York Mercantile Exchange (NYMEX) natural gas and oil futures. 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. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties' valuation models, the Company maintains communications with

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its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources. 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 or Alagasco. As of the balance sheet date, the Company believes that these prices represent the best estimate of the exit price for these instruments and are representative of the prices for which the contract will ultimately settle or realize.

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	December 31, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(3,629	)	$	68,421		$	64,792
Noncurrent assets	18,899			21,678			40,577
Current liabilities	(2,593		)	—			(2,593		)
Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
Net derivative asset	$	4,157		$	89,019		$	93,176

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value of amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. As of December 31, 2011, Alagasco had $56.8 million and $3.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012 and 2011.

Level 3 assets as of December 31, 2012 represent approximately 1.5 percent of total assets and an immaterial amount of total liabilities, respectively. Changes in fair value primarily result from price changes in the underlying commodity. The Company 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 derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $27.0 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $2.5 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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 Securities and Exchange Commission (SEC) to promulgate implementing rules and regulations. The Dodd-Frank Act imposes certain margin, clearing and trade execution requirements.  The Company and Alagasco expect their derivatives transactions to qualify for an end-user exception which will exempt 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.  If, contrary to current expectations, either the Company or Alagasco is not able to utilize the end-user exception, the Company or Alagasco could be forced to curtail their hedging activities or incur significant expense associated with compliance measures and liquidity requirements. A reduction in the ability to utilize derivatives to hedge risks associated with its business could have a material adverse effect on its business, financial condition, results of operations or cash flows.

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Natural Gas Distribution: The extension of RSE in December 2007 provides Alagasco the opportunity to continue earning an allowed return on average equity between 13.15 percent and 13.65 percent through December 31, 2014. Under the terms of that extension, RSE will continue beyond that date, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue its operation. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment rider which permits the pass-through to customers for changes in the cost of gas supply. Also as discussed in Note 2, Regulatory Matters, in the Notes to Financial Statements, the utility's CCM is based on the rate of inflation. Continued low inflation or the risk of deflation combined with a return to higher gas prices resulting in increased bad debt expense could impact the utility's ability to manage its O&M expense sufficiently for the inflation-based cost control requirements of RSE and may result in an average return on equity lower than the allowed range of return. In addition, decreases in residential customers and declines in usage per customer in the residential and small commercial classes, as well as market sensitive load losses from large industrial and commercial customers, will make it more difficult for the utility to earn within its allowed range of return on equity. With the support of the APSC, Alagasco has implemented a variety of programs to help it compete for gas load in all market segments. The Company has been effective in utilizing these programs to deter load loss to competitive fuels.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Company'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 the Company. 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.

Oil and Gas Operations

Accounting for Natural Gas and Oil Producing Activities and Related Reserves: The Company 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 gas reserves are the 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. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and gas reserves have been determined by Company engineers. Independent oil and gas reservoir engineers have audited the estimates of proved reserves of natural gas, crude oil and natural gas liquids attributed to the Company's net interests in oil and gas properties as of December 31, 2012. 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. The Company'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 gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated reserves held by the Company. If reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if 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 2013 depreciation, depletion and amortization expense associated with an assumed downward revision in the reported oil and gas reserve amounts at December 31, 2012:

	Percentage Change in Oil & Gas Reserves
	From Reported Reserves as of December 31, 2012
(dollars in thousands)	-5%		-10%
Estimated increase in DD&A expense for the year ended December 31, 2013, net of tax	$	13,297	$	27,893

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 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. The Company monitors its oil and gas properties

36

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, Energen Resources makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, the Company 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 Resources 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 the Company's need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact the Company's original and ongoing assessments of potential impairment.

Energen Resources also may recognize impairments of capitalized costs for unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold costs and exploratory drilling costs. 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. The Company considers a combination of geologic and engineering factors to evaluate the need for impairment of these costs.

Derivatives: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. Energen Resources recognizes all derivatives on the balance sheet and measures all derivatives at fair value. Realized gains and losses from derivatives designated as cash flow hedges are recognized in oil and gas production revenues when the forecasted transaction occurs. Energen Resources also periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources 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.

Natural Gas Distribution

Regulated Operations: Alagasco capitalizes costs as regulatory assets that otherwise would be charged to expense if it is probable that the cost is recoverable in the future through regulated rates. Likewise, if current recovery is provided for a cost that will be incurred in the future, the cost would be recognized as a regulatory liability. Alagasco's rate setting methodology, Rate Stabilization and Equalization, has been in effect since 1983.

Consolidated

Employee Benefit Plans: An employer is required to recognize the net funded status of defined benefit pensions and other postretirement benefit plans (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. The pension benefit obligation is the projected benefit obligation, a measurement of earned benefit obligations at expected retirement salary levels; 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. Alagasco established a regulatory asset for the portion of the total benefit obligation to be recovered through rates in future periods.

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 the Company's benefit plans includes assumptions regarding the appropriate weighted average discount rate, the expected long-term rate of return on the plans' assets and the estimated weighted average rate of increase in the compensation level of its employee base for defined benefit pension plans. The key assumptions used in determining these calculations are disclosed in Note 5, Employee Benefit Plans, in the Notes to Financial Statements.

In selecting the discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company 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 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 costs was 4.52 percent for the plans for the year ended December 31, 2012. 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 expense was 7 percent for each of the applicable plans for the year ended December 31, 2012. The estimated weighted average rate of increase in the compensation level for pay related plans was 3.59 percent for the year ended December 31, 2012.

37

The selection and use of actuarial assumptions affects the amount of benefit expense recorded in the Company’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, 2012:

(in thousands)	Pension Expense		Postretirement Expense
Discount rate change	$	1,350	$	40
Return on assets	$	500	$	160
Compensation increase	$	745	$	—

The weighted average discount rate, return on plan assets and estimated rate of compensation increase used in the 2013 actuarial assumptions are 3.47 percent, 7.00 percent and 3.71 percent, respectively.

Asset Retirement Obligation: The Company 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, the Company will settle the obligation for its recorded amount and recognize the resulting gain or loss. Energen Resources has an obligation to remove tangible equipment and restore land at the end of oil and gas production operations. Alagasco has certain removal cost obligations related to its gas distribution assets and a conditional asset retirement obligation to purge and cap its distribution and transmission lines upon abandonment. 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.

Uncertain Tax Positions: The Company accounts for uncertain tax positions in accordance with accounting guidance which prescribes a recognition threshold and measurement attribute for financial statement recognition. The application of income tax law is inherently complex; laws and regulation in this area are voluminous and often ambiguous. As such, the Company is required to make many subjective assumptions and judgments regarding income tax exposures. Interpretations and guidance related to income tax laws and regulation change over time. It is possible that changes in the Company’s subjective assumptions and judgments could materially affect amounts recognized in the consolidated balance sheets and statements of income. Additional information related to the Company’s uncertain tax positions is provided in Note 4, Income Taxes, in the Notes to the Financial Statements.

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD

See Note 15, 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 required by this item with respect to market risk is set forth in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations under the heading "Outlook" and in Note 8, Financial Instruments and Risk Management, in the Notes to Financial Statements.

38

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ENERGEN CORPORATION

ALABAMA GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULES

		Page
1.	Financial Statements
	Energen Corporation
	Report of Independent Registered Public Accounting Firm	40
	Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010	42
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010	43
	Consolidated Balance Sheets as of December 31, 2012 and 2011	44
	Consolidated Statements of Shareholders' Equity for the years ended December 31, 2012, 2011 and 2010	46
	Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010	47
	Notes to Financial Statements	53
	Alabama Gas Corporation
	Report of Independent Registered Public Accounting Firm	41
	Statements of Income for the years ended December 31, 2012, 2011 and 2010	48
	Balance Sheets as of December 31, 2012 and 2011	49
	Statements of Shareholder's Equity for the years ended December 31, 2012, 2011 and 2010	51
	Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010	52
	Notes to Financial Statements	53
2.	Financial Statement Schedules
	Energen Corporation
	Schedule II - Valuation and Qualifying Accounts	99
	Alabama Gas Corporation
	Schedule II - Valuation and Qualifying Accounts	99

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.

39

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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying indexpresents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report On Internal Control Over Financial Reportingappearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 28, 2013

40

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Alabama Gas Corporation:

In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Alabama Gas Corporation at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, 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 appearingunder Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 28, 2013

41

CONSOLIDATED STATEMENTS OF INCOME

Energen Corporation

Years ended December 31, (in thousands, except share data)	2012			2011			2010
Operating Revenues
Oil and gas operations	$	1,165,580		$	948,526		$	958,762
Natural gas distribution	451,589			534,953			619,772
Total operating revenues	1,617,169			1,483,479			1,578,534
Operating Expenses
Cost of gas	142,228			233,523			316,988
Operations and maintenance	477,883			419,119			429,165
Depreciation, depletion and amortization	419,598			283,997			247,865
Asset impairment	21,545			—			—
Taxes, other than income taxes	88,989			91,734			84,961
Accretion expense	7,534			6,837			6,178
Total operating expenses	1,157,777			1,035,210			1,085,157
Operating Income	459,392			448,269			493,377
Other Income (Expense)
Interest expense	(65,556		)	(44,822		)	(39,222		)
Other income	4,448			2,334			4,285
Other expense	(903		)	(456		)	(643		)
Total other expense	(62,011		)	(42,944		)	(35,580		)
Income Before Income Taxes	397,381			405,325			457,797
Income tax expense	143,819			145,701			166,990
Net Income	$	253,562		$	259,624		$	290,807
Diluted Earnings Per Average Common Share	$	3.51		$	3.59		$	4.04
Basic Earnings Per Average Common Share	$	3.52		$	3.60		$	4.05
Diluted Average Common Shares Outstanding	72,316,214			72,332,369			72,050,997
Basic Average Common Shares Outstanding	72,119,021			72,055,661			71,845,463

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

42

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Energen Corporation

Years ended December 31, (in thousands)	2012			2011			2010
Net Income	$	253,562		$	259,624		$	290,807
Other comprehensive income (loss):
Current period change in fair value of commodity derivative instruments, net of tax of $40,720, $41,399 and $19,491, respectively	66,438			67,547			31,801
Reclassification adjustment for commodity derivative instruments, net of tax of ($17,994), ($8,953) and ($76,535), respectively	(29,359		)	(14,607		)	(124,873		)
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $100, $96 and $98, respectively	186			177			182
Amortization of prior service cost, net of taxes of $119, $104 and $104, respectively	221			194			194
Amortization of net loss, net of taxes of $1,676, $1,270 and $1,152, respectively	3,113			2,359			2,139
Current period change in fair value of pension and postretirement plans, net of taxes of ($9,393), ($5,699), and ($783), respectively	(17,443		)	(10,584		)	(1,455		)
Total pension and postretirement plans	(13,923		)	(7,854		)	1,060
Current period change in fair value of interest rate swap, net of tax of ($1,228) and ($507), respectively	(2,281		)	(941		)	—
Reclassification adjustment for interest rate swap, net of tax of $574	1,066			—			—
Comprehensive Income	$	275,503		$	303,769		$	198,795

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

43

CONSOLIDATED BALANCE SHEETS

Energen Corporation

(in thousands)	December 31, 2012		December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents	$	9,704	$	9,541
Accounts receivable, net of allowance for doubtful accounts of $6,549 and $12,946 at December 31, 2012 and 2011, respectively	277,900		231,925
Inventories
Storage gas inventory	32,205		44,047
Materials and supplies	28,291		26,420
Liquified natural gas in storage	3,498		3,545
Regulatory asset	45,515		57,143
Income tax receivable	6,664		7,343
Deferred income taxes	8,520		48,818
Prepayments and other	12,823		15,386
Total current assets	425,120		444,168
Property, Plant and Equipment
Oil and gas properties, successful efforts method	6,439,127		5,166,368
Less accumulated depreciation, depletion and amortization	1,765,241		1,382,526
Oil and gas properties, net	4,673,886		3,783,842
Utility plant	1,416,590		1,358,266
Less accumulated depreciation	573,947		544,838
Utility plant, net	842,643		813,428
Other property, net	25,107		23,506
Total property, plant and equipment, net	5,541,636		4,620,776
Other Assets
Regulatory asset	110,566		95,633
Pension and other postretirement assets	1,404		—
Long-term derivative instruments	40,577		31,056
Deferred charges and other	56,587		45,783
Total other assets	209,134		172,472
TOTAL ASSETS	$	6,175,890	$	5,237,416

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

44

CONSOLIDATED BALANCE SHEETS

Energen Corporation

(in thousands, except share data)	December 31, 2012			December 31, 2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	50,000		$	1,000
Notes payable to banks	643,000			15,000
Accounts payable	257,579			302,048
Accrued taxes	30,076			32,359
Customers' deposits	24,705			23,950
Amounts due customers	19,718			21,065
Accrued wages and benefits	24,984			35,258
Regulatory liability	45,116			58,279
Royalty payable	34,426			22,592
Other	30,178			32,328
Total current liabilities	1,159,782			543,879
Long-term debt	1,103,528			1,153,700
Deferred Credits and Other Liabilities
Asset retirement obligation	118,023			107,340
Pension and other postretirement liabilities	110,282			62,532
Regulatory liability	80,404			87,234
Deferred income taxes	905,601			806,127
Long-term derivative instruments	11,305			34,663
Other	10,275			9,778
Total deferred credits and other liabilities	1,235,890			1,107,674
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, 75,067,760 shares issued at December 31, 2012 and 75,007,412 shares issued at December 31, 2011	751			750
Premium on capital stock	492,108			482,918
Capital surplus	2,802			2,802
Retained earnings	2,314,055			2,100,885
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	46,352			9,273
Pension and postretirement plans	(52,507		)	(38,584		)
Interest rate swap	(2,156		)	(941		)
Deferred compensation plan	2,774			3,511
Treasury stock, at cost: 2,998,620 shares and 3,036,549 shares at December 31, 2012 and 2011, respectively	(127,489		)	(128,451		)
Total shareholders' equity	2,676,690			2,432,163
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,175,890		$	5,237,416

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

45

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

Energen Corporation

	Common Stock			Premium on Capital Stock			Capital Surplus		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, 2009	74,593,431	$	746	$	461,661		$	2,802	$	1,626,753		$	17,615		$	3,121		$	(124,455	)	$	1,988,243
Net income									290,807												290,807
Other comprehensive loss												(92,012		)							(92,012		)
Purchase of treasury shares, net																		(2,893		)	(2,893		)
Shares issued for employee benefit plans	192,945	2		6,449																	6,451
Deferred compensation obligation															167			(167		)	—
Stock based compensation				(83		)															(83		)
Tax benefit from employee stock plans				907																	907
Cash dividends - $0.52 per share									(37,377		)										(37,377		)
BALANCE DECEMBER 31, 2010	74,786,376	748		468,934			2,802		1,880,183			(74,397		)	3,288			(127,515		)	2,154,043
Net income									259,624												259,624
Other comprehensive income												44,145									44,145
Purchase of treasury shares, net																		(713		)	(713		)
Shares issued for employee benefit plans	221,036	2		7,235																	7,237
Deferred compensation obligation															223			(223		)	—
Stock based compensation				5,763																	5,763
Tax benefit from employee stock plans				986																	986
Cash dividends - $0.54 per share									(38,922		)										(38,922		)
BALANCE DECEMBER 31, 2011	75,007,412	750		482,918			2,802		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																		(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	$	492,108		$	2,802	$	2,314,055		$	(8,311	)	$	2,774		$	(127,489	)	$	2,676,690

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

46

CONSOLIDATED STATEMENTS OF CASH FLOWS

Energen Corporation

Years ended December 31, (in thousands)	2012			2011			2010
Operating Activities
Net income	$	253,562		$	259,624		$	290,807
Adjustments to reconcile net income to net cash    provided by operating activities:
Depreciation, depletion and amortization	419,598			283,997			247,865
Asset impairment	21,545			—			—
Accretion expense	7,534			6,837			6,178
Deferred income taxes	124,399			129,041			133,840
Bad debt expense	153			2,525			1,565
Change in derivative fair value	(41,819		)	36,210			(819		)
Gain on sale of assets	(529		)	(5,994		)	(2,521		)
Other, net	15,681			13,298			(568		)
Exploratory expense	16,757			10,916			63,668
Net change in:
Accounts receivable	(11,923		)	(16,359		)	(31,939		)
Inventories	10,018			(14,710		)	4,022
Accounts payable	(16,392		)	12,978			18,889
Amounts due customers, including gas supply pass-through	(57,747		)	(2,597		)	20,751
Income tax receivable	679			37,146			(39,937		)
Pension and other postretirement benefit contributions	(5,996		)	(5,986		)	(42,233		)
Other current assets and liabilities	217			14,905			1,454
Net cash provided by operating activities	735,737			761,831			671,022
Investing Activities
Additions to property, plant and equipment	(1,184,300		)	(889,614		)	(434,121		)
Acquisitions, net of cash acquired	(139,563		)	(310,193		)	(410,348		)
Proceeds from sale of assets	2,562			7,987			3,155
Purchase of short-term investments	—			—			(154,880		)
Sale of short-term investments	—			—			154,965
Other, net	(881		)	(1,679		)	(1,464		)
Net cash used in investing activities	(1,322,182		)	(1,193,499		)	(842,693		)
Financing Activities
Payment of dividends on common stock	(40,392		)	(38,922		)	(37,377		)
Issuance of common stock	1,224			6,415			685
Issuance of long-term debt	—			749,952			—
Reduction of long-term debt	(1,218		)	(5,547		)	(150,729		)
Net change in short-term debt	628,000			(290,000		)	305,000
Tax benefit on stock compensation	550			986			907
Other	(1,556		)	(4,334		)	—
Net cash provided by financing activities	586,608			418,550			118,486
Net change in cash and cash equivalents	163			(13,118		)	(53,185		)
Cash and cash equivalents at beginning of period	9,541			22,659			75,844
Cash and cash equivalents at end of period	$	9,704		$	9,541		$	22,659

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

47

STATEMENTS OF INCOME

Alabama Gas Corporation

Years ended December 31, (in thousands)	2012			2011			2010
Operating Revenues	$	451,589		$	534,953		$	619,772
Operating Expenses
Cost of gas	142,228			233,523			316,988
Operations and maintenance	141,334			139,030			128,830
Depreciation and amortization	42,270			39,916			44,042
Income taxes
Current	18,966			(1,388		)	1,014
Deferred	11,278			28,058			28,861
Taxes, other than income taxes	32,541			36,268			41,529
Total operating expenses	388,617			475,407			561,264
Operating Income	62,972			59,546			58,508
Other Income (Expense)
Allowance for funds used during construction	623			807			808
Other income	2,382			1,309			1,923
Other expense	(291		)	(320		)	(462		)
Total other income	2,714			1,796			2,269
Interest Expense
Interest on long-term debt	13,744			12,100			11,907
Other interest expense	2,540			2,640			1,987
Total interest expense	16,284			14,740			13,894
Net Income	$	49,402		$	46,602		$	46,883

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

48

BALANCE SHEETS

Alabama Gas Corporation

(in thousands)	December 31, 2012			December 31, 2011
ASSETS
Property, Plant and Equipment
Utility plant	$	1,416,590		$	1,358,266
Less accumulated depreciation	573,947			544,838
Utility plant, net	842,643			813,428
Other property, net	42			43
Current Assets
Cash	5,559			7,817
Accounts receivable
Gas	94,011			96,812
Other	5,117			6,858
Affiliated companies	5,742			2,841
Allowance for doubtful accounts	(5,700		)	(12,100		)
Inventories
Storage gas inventory	32,205			44,047
Materials and supplies	5,528			4,183
Liquified natural gas in storage	3,498			3,545
Regulatory asset	45,515			57,143
Income tax receivable	2,762			9,762
Deferred income taxes	18,799			21,986
Prepayments and other	4,451			4,422
Total current assets	217,487			247,316
Other Assets
Regulatory asset	110,566			95,633
Pension and other postretirement assets	848			—
Deferred charges and other	11,290			10,380
Total other assets	122,704			106,013
TOTAL ASSETS	$	1,182,876		$	1,166,800

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

49

BALANCE SHEETS

Alabama Gas Corporation

(in thousands, except share data)	December 31, 2012		December 31, 2011
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative, $0.01 par value, 120,000 shares authorized	$	—	$	—
Common shareholder's equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at December 31, 2012 and 2011, respectively	20		20
Premium on capital stock	31,682		31,682
Capital surplus	2,802		2,802
Retained earnings	325,999		310,234
Total common shareholder's equity	360,503		344,738
Long-term debt	250,028		250,246
Total capitalization	610,531		594,984
Current Liabilities
Long-term debt due within one year	—		—
Notes payable to banks	77,000		15,000
Accounts payable	51,741		110,552
Accrued taxes	24,186		26,861
Customers' deposits	24,705		23,950
Amounts due customers	19,718		21,065
Accrued wages and benefits	6,703		12,971
Regulatory liability	45,116		58,279
Other	9,018		9,250
Total current liabilities	258,187		277,928
Deferred Credits and Other Liabilities
Deferred income taxes	189,381		181,492
Pension and other postretirement liabilities	43,611		21,383
Regulatory liability	80,404		87,234
Long-term derivative instruments	—		3,070
Other	762		709
Total deferred credits and other liabilities	314,158		293,888
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,182,876	$	1,166,800

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

50

STATEMENTS OF SHAREHOLDER'S EQUITY

Alabama Gas Corporation

(in thousands, except share data)
	Common Stock			Premium on Capital Stock		Capital Surplus		Retained Earnings			Total Shareholder's Equity
	Number of Shares	Par Value
Balance December 31, 2009	1,972,052	$	20	$	31,682	$	2,802	$	283,299		$	317,803
Net income								46,883			46,883
Cash dividends								(37,367		)	(37,367		)
Balance December 31, 2010	1,972,052	20		31,682		2,802		292,815			327,319
Net income								46,602			46,602
Cash dividends								(29,183		)	(29,183		)
Balance December 31, 2011	1,972,052	20		31,682		2,802		310,234			344,738
Net income								49,402			49,402
Cash dividends								(33,637		)	(33,637		)
Balance December 31, 2012	1,972,052	$	20	$	31,682	$	2,802	$	325,999		$	360,503

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

51

STATEMENTS OF CASH FLOWS

Alabama Gas Corporation

Years ended December 31, (in thousands)	2012			2011			2010
Operating Activities
Net income	$	49,402		$	46,602		$	46,883
Adjustments to reconcile net income to net cash     provided by operating activities:
Depreciation and amortization	42,270			39,916			44,042
Deferred income taxes	11,278			28,058			28,861
Bad debt expense	146			2,457			1,561
Other, net	10,667			1,560			(10,958		)
Net change in:
Accounts receivable	(13,528		)	4,862			(26,567		)
Inventories	10,544			(7,371		)	5,854
Accounts payable	(5,906		)	(1,499		)	2,663
Amounts due customers, including gas supply pass-through	(57,747		)	(2,597		)	20,751
Income tax receivable	7,000			553			(6,846		)
Pension and other postretirement benefit contributions	(2,725		)	(2,811		)	(26,083		)
Other current assets and liabilities	(8,654		)	(2,802		)	14,273
Net cash provided by operating activities	42,747			106,928			94,434
Investing Activities
Additions to property, plant and equipment	(69,860		)	(73,447		)	(92,099		)
Other, net	(3,252		)	(2,743		)	(1,827		)
Net cash used in investing activities	(73,112		)	(76,190		)	(93,926		)
Financing Activities
Payment of dividends on common stock	(33,637		)	(29,183		)	(37,367		)
Proceeds from issuance of long-term debt	—			50,000			—
Reduction of long-term debt	(218		)	(5,547		)	(729		)
Net advances to parent company	—			—			(24,962		)
Net change in short-term debt	62,000			(55,000		)	70,000
Other	(38		)	(101		)	—
Net cash provided by (used in) financing activities	28,107			(39,831		)	6,942
Net change in cash and cash equivalents	(2,258		)	(9,093		)	7,450
Cash and cash equivalents at beginning of period	7,817			16,910			9,460
Cash and cash equivalents at end of period	$	5,559		$	7,817		$	16,910

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

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NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Energen Corporation (Energen or the Company) is a diversified energy holding company engaged primarily in the development, acquisition, exploration and production of oil and gas in the continental United States (oil and gas operations) and in the purchase, distribution and sale of natural gas principally in central and north Alabama (natural gas distribution). The following is a description of the Company's significant accounting policies and practices.

A. Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, principally Energen Resources Corporation and Alabama Gas Corporation (Alagasco), after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years' financial statements to the current-year presentation.

B. Oil and Gas Operations

Property and Related Depletion: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid 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. 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. 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 Revenue: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids 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 reserves for such property. Energen Resources had no material production imbalances at December 31, 2012 and 2011.

Derivative Commodity Instruments: Energen Resources recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps and basis hedges typically 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.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of December 31, 2012, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s 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.

The Company periodically enters into derivatives that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding

53

New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change. Open mark-to-market gains (losses) on derivatives included in operating revenues were as follows:

Years ended December 31, (in thousands)	2012		2011			2010
Mark-to-market gain (loss) on derivatives	$	58,750	$	(37,587	)	$	(3	)

All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the cash flow 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 hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness in hedging the exposure to the hedged transaction's variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the cash flow hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge.

Long-Lived Assets and Discontinued Operations: The Company reports gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for certain held-for-sale properties are reclassified and reported as discontinued operations for prior periods. Energen Resources 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 fair value.

Acquisitions: Energen Resources recognizes all acquisitions at fair value. Energen Resources estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen Resources 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 Resources 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 operations and maintenance expense on the consolidated income statements.

C. Natural Gas Distribution

Regulatory Accounting: Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) with respect to rates, accounting and various other matters. In general, Alagasco capitalizes or defers certain costs or revenues, based on the approvals received from the APSC, to be recovered from or refunded to customers in future periods. These costs or revenues are recorded as regulatory assets or liabilities.

Utility Plant and Depreciation: Property, plant and equipment are stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. Gains and losses on all dispositions of land are recognized at time of disposal. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets are charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the APSC. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $14.2 million, $22.2 million and $2.7 million for the period January through December 2012, January through December 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $18.3 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $53.5 million

54

of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a seven year period beginning January 1, 2013. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the Enhanced Stability Reserve (ESR) and other commission-approved charges. The refunds as of December 2012 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates. Approved depreciation rates averaged approximately 3.2 percent, 3.1 percent and 3.6 percent in the years ended December 31, 2012, 2011 and 2010, respectively. The revised depreciation rates decreased depreciation expense by approximately $6.8 million and $9.2 million for the years ended December 31, 2011 and 2010, respectively, from expense amounts calculated using the prior depreciation rate.

Inventories: Inventories, which consist primarily of gas stored underground, are stated at average cost. Liquified natural gas is stated at base cost.

Operating Revenue and Gas Costs: Alagasco records natural gas distribution revenues in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material gas imbalances at December 31, 2012. Alagasco had gas imbalances of $0.5 million at December 31, 2011.

Derivative Commodity Instruments: In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet at fair value. Any realized gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco's APSC approved tariff and are recognized as a regulatory asset or regulatory liability. 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 Alagasco.

Taxes on revenues: The collection and payment of revenue taxes such as utility license taxes and fees, franchise fees and taxes imposed by other governmental authorities are reported on a gross basis. These amounts are included in taxes other than income taxes on the consolidated statements of income as follows:

Years ended December 31, (in thousands)	2012		2011		2010
Taxes on revenues	$	21,479	$	25,268	$	30,704

The collection and payment of utility gross receipts tax is presented on a net basis.

D. Fair Value Measurements

The carrying values of cash and cash equivalents, accounts payable and receivable, 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). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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 fair value hierarchy that prioritizes the inputs used to measure fair value is defined 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 assumption that market value 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.

55

Derivative commodity instruments are over-the-counter derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These 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 the Company is 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 New York Mercantile Exchange natural gas and oil futures. 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. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties' valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.

Pension and postretirement plan assets include mutual and comingled funds and a limited partnership. 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 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.

E. Income Taxes

The Company 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. The Company 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 the Company's best estimate of the amount of probable credit losses in the existing accounts receivable. The Company 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 Equivalents

All highly liquid financial instruments with an original maturity of three months or less at the time of purchase are considered to be cash or cash equivalents.

As of December 31, 2012, the Company and Alagasco revised the presentation of outstanding checks in its financial statements. Previously, the Company and Alagasco reflected outstanding checks as a reduction in cash as of the date the checks cleared the bank as opposed to the date the checks were released for payment. Under the revised presentation, as of December 31, 2011, Energen's cash and accounts payable would have been reduced by $8.0 million and $7.3 million, respectively, while accounts receivable would have increased by $0.7 million. Under the revised presentation, as of December 31, 2011, Alagasco's cash and accounts payable would have been reduced by $6.8 million and $6.1 million, respectively, while accounts receivable would have increased by $0.7 million. The Company and Alagasco considered the impact of this adjustment on the December 31, 2011 balance sheets and statements of cash flows for the year then ended and determined that the amounts were not material. The effect of not revising the presentation of cash balances as of December 31, 2011, but presenting the correct cash balances at December 31, 2012, resulted in a decrease of $8.0 million and $6.8 million to Energen and Alagasco's 2012 operating cash flows, respectively. This adjustment caused no impact to Energen or Alagasco's income statements.

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, 2012 and 2011, Energen had no short-term investments.

56

I. Earnings Per Share (EPS)

The Company'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

The Company 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. The Company recognizes all stock-based compensation expense in the period of grant for retirement eligible employees. The Company utilizes the long-form method of calculating the available pool of windfall tax benefit. For 2012 and 2011, the Company recognized an excess tax benefit of $0.6 million and $1.0 million, respectively, related to its 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 oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that regulatory accounting will continue as the applicable accounting standard for the Company's regulated operations, the Company'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, self insurance reserves and regulatory assets and liabilities. 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 two defined benefit non-contributory qualified pension plans. These plans cover substantially all employees. Pension benefits for the majority of the Company’s employees are based on years of service and final earnings; one plan is based on years of service and flat dollar amounts. The Company also has nonqualified supplemental pension plans covering certain officers of the Company. In addition to providing pension benefits, the Company provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. The Company continues to provide these benefits to certain non-salaried employees. Substantially all of the Company's employees may become eligible for certain benefits if they reach normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.

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

Measurement: The Company calculates periodic expense for defined benefit pension plans and other post retirement 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 pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. Alagasco recognizes a regulatory asset for the portion of the obligation to be recovered in rates in future periods and a regulatory liability for the portion of the plan obligation to be provided through rates in the future. The Company measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.

Discount Rate: In selecting each discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company 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.

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Long-Term Rate of Return: The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The Company 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. As more fully described in Note 2, Regulatory Matters, and as currently approved, the ESR provides deferred treatment and recovery for extraordinary operations and maintenance (O&M) expenses related to environmental response costs.

2. REGULATORY MATTERS

Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period through December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for Securities and Exchange Commission reporting purposes.

Alagasco's allowed range of return on average common equity is 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the years ended December 31, 2012, 2011 and 2010, Alagasco had net pre-tax reductions in revenues of $6.3 million, $6.7 million and $17.4 million, respectively, to bring the return on average equity to midpoint within the allowed range of return. Under the provisions of RSE, a $7.8 million annual increase, $13.0 million annual increase and $1.3 million annual decrease in revenues became effective December 1, 2012, 2011, and 2010, respectively.

RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. In the rate year ended September 30, 2010, $2.5 million of extraordinary bad debt expense was excluded from the CCM calculation.  Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2012, 2011 and 2010.

Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

The APSC approved an Enhanced Stability Reserve in 1998 which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year.

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Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco anticipates recovering underfunded ESR balances over a five year amortization period with an annual limitation of $660,000. Amounts in excess of this limitation are deferred for recovery in future years.

The excess of total acquisition costs over book value of net assets of acquired municipal gas distribution systems is included in utility plant and is being amortized through Alagasco's rate-setting mechanism on a straight-line basis with a weighted average remaining life of approximately 13 years. At December 31, 2012 and 2011, the net unamortized acquisition adjustments were $3.8 million and $4.4 million, respectively.

3. LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:

(in thousands)	December 31, 2012		December 31, 2011
Energen Corporation:
Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.6%, for notes due July 24, 2017 to February 15, 2028	$	154,000	$	155,000
5% Notes, due October 1, 2013	50,000		50,000
4.625% Notes, due September 1, 2021	400,000		400,000
Senior Term Loans, (floating rate interest LIBOR plus 1.375%; 1.59% at December 31, 2012), due March 31, 2014 to November 29, 2016	300,000		300,000
Alabama Gas Corporation:
5.20% Notes, due January 15, 2020	40,000		40,000
5.70% Notes, due January 15, 2035	35,028		35,246
5.368% Notes, due December 1, 2015	80,000		80,000
5.90% Notes, due January 15, 2037	45,000		45,000
3.86% Notes, due December 21, 2021	50,000		50,000
Total	1,154,028		1,155,246
Less amounts due within one year	50,000		1,000
Less unamortized debt discount	500		546
Total	$	1,103,528	$	1,153,700

The aggregate maturities of Energen's long-term debt for the next five years are as follows:

Years ending December 31, (in thousands)
2013	2014	2015	2016	2017
$50,000	$100,000	$180,000	$100,000	$19,000

The aggregate maturities of Alagasco's long-term debt for the next five years are as follows:

Years ending December 31, (in thousands)
2013	2014	2015	2016	2017
—	—	$80,000	—	—

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In August 2011, the Company issued $400 million in Senior Notes with an interest rate of 4.625 percent due September 1, 2021. In November 2011, the Company issued $300 million in Senior Term Loans (Senior Term Loans) with a floating interest rate due March 31, 2014 through November 29, 2016. The Company used the long-term debt proceeds to replace short-term obligations, enhance liquidity and to finance the property acquisition program at Energen Resources. In December 2011, Alagasco issued $50 million of long-term debt with an interest rate of 3.86 percent due December 21, 2021 to replace short-term obligations.

In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company's interest rate swap was a $3.3 million and a $1.5 million liability at December 31, 2012 and 2011, respectively, and is classified as a Level 2 fair value.

The long-term debt and short-term debt agreements of Energen and Alagasco 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 covenants or events of default based on credit ratings, the interest rates applicable to the Senior Term Loans and the Energen and Alagasco syndicated credit facilities discussed below may adjust based on credit rating changes. All of the Company's debt is unsecured; however, approximately $4 million of the Company's indebtedness is effectively secured through a sale-leaseback arrangement.

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, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s Indenture dated November 1, 1993 with The Bank of New York as Trustee, a cross default provision provides that any debt default by Alagasco of more than $10 million will constitute an event of default by Alagasco. Neither Indenture includes a restriction on the payment of dividends.

Energen and Alagasco Credit Facilities: On October 30, 2012, Energen and Alagasco entered into $1,250 million and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. These syndicated credit facilities replace Energen's $850 million and Alagasco's $150 million three-year syndicated credit facilities. Borrowings under these credit facilities are subject to the execution of individual note agreements each with maturity dates of less than one year. Accordingly, outstanding amounts due under these credit facilities are classified as short term obligations in the accompanying consolidated financial statements. Alagasco has been authorized by the APSC to borrow up to $200 million at any one time under the short-term credit facilities.

Energen’s obligations under the $1,250 million syndicated credit facility are unconditionally guaranteed by Energen Resources. The financial covenants of the Energen credit facility limit Energen to a maximum consolidated debt to capitalization ratio of no more than 65 percent as of the end of any fiscal quarter. Energen may not pay dividends during an event of default or if the payment would result in an event of default.

Similarly, the financial covenants of the Alagasco credit facility limit Alagasco to a maximum consolidated debt to capitalization ratio of no more than 65 percent as of the end of any fiscal quarter. Alagasco may not pay dividends during an event of default or if the payment would result in an event of default.

Under the Energen credit facility, a cross default provision provides that any debt default of more than $50 million by Energen, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s credit facility, a cross default provision provides that any debt default by Alagasco of more than $50 million will constitute an event of default by Alagasco.

Upon an uncured event of default under either of the credit facilities, all amounts owing under the defaulted 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 and Alagasco were in compliance with the terms of their respective credit facilities as of December 31, 2012.

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The following is a summary of information relating to the credit facilities:

(in thousands)	December 31, 2012			December 31, 2011
Energen outstanding	$	566,000		$	—
Alagasco outstanding	77,000			15,000
Notes payable to banks	643,000			15,000
Available for borrowings	707,000			1,004,000
Total	$	1,350,000		$	1,019,000
Energen maximum amount outstanding at any month-end	$	643,000		$	363,000
Energen average daily amount outstanding	$	331,068		$	229,094
Energen weighted average interest rates based on:
Average daily amount outstanding	1.82		%	2.04		%
Amount outstanding at year-end	1.35		%	3.58		%
Alagasco maximum amount outstanding at any month-end	$	77,000		$	70,000
Alagasco average daily amount outstanding	$	21,254		$	29,268
Alagasco weighted average interest rates based on:
Average daily amount outstanding	1.44		%	1.72		%
Amount outstanding at year-end	1.11		%	3.58		%

Energen's total interest expense was $65.6 million, $44.8 million and $39.2 million for the years ended December 31, 2012, 2011 and 2010, respectively. Energen's total interest expense for the year ended December 31, 2012 included capitalized interest expense of $0.5 million. Total interest expense for Alagasco was $16.3 million, $14.7 million and $13.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

4. INCOME TAXES

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

Years ended December 31, (in thousands)	2012		2011		2010
Taxes estimated to be payable currently:
Federal	$	16,295	$	11,595	$	31,920
State	3,125		5,065		1,230
Total current	19,420		16,660		33,150
Taxes deferred:
Federal	119,053		125,622		121,804
State	5,346		3,419		12,036
Total deferred	124,399		129,041		133,840
Total income tax expense	$	143,819	$	145,701	$	166,990

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The components of Alagasco's income taxes consisted of the following:

Years ended December 31, (in thousands)	2012		2011			2010
Taxes estimated to be payable currently:
Federal	$	18,227	$	(1,280	)	$	859
State	739		(108		)	155
Total current	18,966		(1,388		)	1,014
Taxes deferred:
Federal	9,066		24,938			25,582
State	2,212		3,120			3,279
Total deferred	11,278		28,058			28,861
Total income tax expense	$	30,244	$	26,670		$	29,875

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

(in thousands)	December 31, 2012						December 31, 2011
	Current			Noncurrent			Current			Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	10,137		$	—		$	9,582		$	—
Allowance for doubtful accounts	2,408			—			4,848			—
Insurance accruals	2,021			—			2,562			—
Compensation accruals	13,116			—			11,181			—
Inventories	1,664			—			1,438			—
Other comprehensive income	—			19,158			2,799			12,801
Gas supply adjustment related accruals	969			—			1,196			—
Derivative instruments	—			—			13,167			—
State net operating losses and other carryforwards	—			3,577			987			3,022
Other	3,140			25			2,797			27
Total deferred tax assets	33,455			22,760			50,557			15,850
Valuation allowance	(268		)	(2,793		)	(270		)	(2,752		)
Total deferred tax assets	33,187			19,967			50,287			13,098
Deferred tax liabilities:
Depreciation and basis differences	—			898,625			—			791,073
Pension and other costs	—			20,143			—			25,685
Derivative instruments	4,272			3,162			—			—
Other comprehensive income	18,133			—			—			—
Other	2,262			3,638			1,469			2,467
Total deferred tax liabilities	24,667			925,568			1,469			819,225
Net deferred tax assets (liabilities)	$	8,520		$	(905,601	)	$	48,818		$	(806,127	)

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

(in thousands)	December 31, 2012					December 31, 2011
	Current		Noncurrent			Current		Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	10,137	$	—		$	9,582	$	—
Allowance for doubtful accounts	2,155		—			4,575		—
Insurance accruals	1,856		—			2,358		—
Compensation accruals	2,645		—			2,274		—
Inventories	1,664		—			1,438		—
Gas supply adjustment related accruals	969		—			1,196		—
State net operating losses and other carryforwards	—		—			987		—
Other	774		2			924		4
Total deferred tax assets	20,200		2			23,334		4
Deferred tax liabilities:
Depreciation and basis differences	—		167,329			—		156,121
Pension and other costs	—		22,054			—		25,375
Other	1,401		—			1,348		—
Total deferred tax liabilities	1,401		189,383			1,348		181,496
Net deferred tax assets (liabilities)	$	18,799	$	(189,381	)	$	21,986	$	(181,492	)

The Company files a consolidated federal income tax return with all of its subsidiaries. The Company has a noncurrent deferred tax asset of $0.5 million relating to Energen Resources’ $12.2 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. The Company has a full valuation allowance recorded against a noncurrent deferred tax asset of $3.1 million arising from certain state net operating loss and charitable contribution carryforwards. The Company 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 the Company 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 for the Company 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)	2012			2011			2010
Income tax expense at statutory federal income tax rate	$	139,083		$	141,864		$	160,229
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	4,904			5,544			8,398
Qualified Section 199 production activities deduction	(94		)	(593		)	(1,745		)
401(k) stock dividend deduction	(514		)	(532		)	(565		)
Other, net	440			(582		)	673
Total income tax expense	$	143,819		$	145,701		$	166,990
Effective income tax rate (%)	36.19			35.95			36.48

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Total income tax expense for Alagasco 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)	2012		2011			2010
Income tax expense at statutory federal income tax rate	$	27,876	$	25,645		$	26,865
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	2,238		2,059			2,157
Reversal of tax reserves from audit settlements, net	—		(1,365		)	—
Other, net	130		331			853
Total income tax expense	$	30,244	$	26,670		$	29,875
Effective income tax rate (%)	37.97		36.40			38.92

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

(in thousands)
Balance as of December 31, 2009	$	17,797
Additions based on tax positions related to the current year	1,436
Additions for tax positions of prior years	11,703
Reductions for tax positions of prior years	(3,624		)
Lapse of statute of limitations	(1,313		)
Settlements	(1,409		)
Balance as of December 31, 2010	24,590
Additions based on tax positions related to the current year	3,644
Additions for tax positions of prior years	2,324
Reductions for tax positions of prior years	(39		)
Lapse of statute of limitations	(1,482		)
Settlements	(18,444		)
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

The reduction for settlements in 2011 and the increase in the additions for tax positions of prior years in 2010 are primarily related to Alagasco's tax accounting method change for the recovery of its gas distribution property that was in dispute under an Internal Revenue Service (IRS) examination of the Company's 2007-2008 federal consolidated income tax returns. In September 2010, the IRS made certain assessments primarily related to Alagasco's tax accounting method change for the recovery of its gas distribution property. The Company subsequently filed a petition in United States Tax Court challenging the IRS assessment. During the second quarter of 2011, the Company entered into a settlement agreement with the IRS. Under this settlement, Alagasco was allowed the full repair tax deductions as originally claimed in the 2007 and 2008 federal income tax returns. The Chief Judge of the United States Tax Court signed and entered the Decision putting this settlement agreement into effect on June 16, 2011.

During 2010, the Company had a gross reduction of $3.6 million and recognized in its effective income tax rate a $2.4 million net benefit associated with the release of an unrecognized income tax benefit liability. The Company reassessed its measurement due to recent developments related to the issue and believed that the full amount of the tax benefit has a greater than 50 percent chance of being fully realized. During 2011, the Company had a gross addition of $5.9 million and recognized in its effective income tax rate $2.9 million of income tax expense for additional unrecognized tax benefit liabilities. These liabilities were partially

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offset by a $1.5 million benefit for the release of the unrecognized income tax benefit liability due to the Company's settlement with the IRS discussed above.

The amount of unrecognized tax benefits at December 31, 2012 that would favorably impact the Company's effective tax rate, if recognized, is $5.1 million. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2012, 2011, and 2010, the Company recognized approximately $25,000 of income, $1.4 million of income and $0.8 million of expense for interest (net of tax benefit) and penalties, respectively. The Company had approximately $0.2 million and $0.2 million for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2012 and 2011, respectively.

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

(in thousands)
Balance as of December 31, 2009	$	7,621
Additions based on tax positions related to the current year	9
Additions for tax positions of prior years	11,645
Reductions for tax positions of prior years (lapse of statute of limitations)	(90		)
Settlements	(244		)
Balance as of December 31, 2010	18,941
Additions based on tax positions related to the current year	13
Additions for tax positions of prior years	1
Reductions for tax positions of prior years (lapse of statute of limitations)	(409		)
Settlements	(18,444		)
Balance as of December 31, 2011	102
Additions based on tax positions related to the current year	62
Additions for tax positions of prior years	201
Reductions for tax positions of prior years (lapse of statute of limitations)	(58		)
Balance as of December 31, 2012	$	307

The reduction for settlements in 2011 and the increase in the additions for tax positions of prior years in 2010 are primarily related to Alagasco's tax accounting method change for the recovery of its gas distribution property discussed above. None of Alagasco's unrecognized tax benefits at December 31, 2012 would impact the Company's effective tax rate, if recognized. Alagasco recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2012, 2011, and 2010, Alagasco recognized approximately $1,000 of income, $1.4 million of income and $1.0 million of expense for interest (net of tax benefit) and penalties, respectively. Alagasco had approximately $4,000 and $5,000 for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2012 and 2011, respectively.

The Company and Alagasco's tax returns for years 2009-2011 remain open to examination by the IRS and major state taxing jurisdictions. The Company and Alagasco have on-going income tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of the completion of various audits and the expiration of statute of limitations. Although the timing and outcome of these tax examinations is highly uncertain, the Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

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5. EMPLOYEE BENEFIT PLANS

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 the Company’s consolidated financial statements:

As of December 31, (in thousands)	2012			2011			2012			2011
	Pension						Postretirement Benefits
Accumulated benefit obligation	$	269,101		$	211,896
Benefit obligation:
Balance at beginning of period	$	250,619		$	233,772		$	88,064		$	83,748
Service cost	10,527			9,173			1,853			1,769
Interest cost	10,801			10,960			4,248			4,443
Actuarial (gain) loss	65,048			17,024			(5,413		)	1,858
Plan amendments	—			(169		)	—			—
Termination benefit charge	—			414			—			—
Retiree drug subsidy program	—			—			360			302
Benefits paid	(13,455		)	(20,555		)	(3,327		)	(4,056		)
Balance at end of period	$	323,540		$	250,619		$	85,785		$	88,064
Plan assets:
Fair value of plan assets at beginning of period	$	195,659		$	212,454		$	78,121		$	80,118
Actual return (loss) on plan assets	24,841			1,485			8,778			(1,653		)
Employer contributions	2,379			2,275			3,617			3,712
Benefits paid	(13,455		)	(20,555		)	(3,327		)	(4,056		)
Fair value of plan assets at end of period	$	209,424		$	195,659		$	87,189		$	78,121
Funded status of plan	$	(114,116	)	$	(54,960	)	$	1,404		$	(9,943	)
Noncurrent assets	$	—		$	—		$	1,404		$	—
Current liabilities	(3,834		)	(2,371		)	—			—
Noncurrent liabilities	(110,282		)	(52,589		)	—			(9,943		)
Net asset (liability) recognized	$	(114,116	)	$	(54,960	)	$	1,404		$	(9,943	)
Amounts recognized to accumulated other comprehensive income:
Prior service costs, net of taxes	$	528		$	749		$	—		$	—
Net actuarial (gain) loss, net of taxes	52,472			36,976			(715		)	451
Transition obligation, net of taxes	—			—			222			408
Total accumulated other comprehensive income (loss)	$	53,000		$	37,725		$	(493	)	$	859

Alagasco recognized a regulatory asset of $89.5 million and $67.8 million as of December 31, 2012 and 2011, respectively, for the portion of the pension plan obligation to be recovered through rates in future periods. Alagasco also recognized a regulatory liability of $1.2 million as of December 31, 2012 for the portion of the postretirement health care and life insurance benefit obligation to be refunded through rates in future periods. Alagasco recognized a regulatory asset of $8.4 million as of December 31, 2011 for the portion of the postretirement health care and life insurance benefit obligation to be recovered through rates in future periods.

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

	December 31, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
Insurance contracts	$	—	$	7,399	$	5,600	$	12,999
United States equities	4,741		—		—		4,741
Global equities	2,109		—		—		2,109
Fixed income	—		10,219		—		10,219
Total	$	6,850	$	17,618	$	5,600	$	30,068

	December 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
Insurance contracts	$	—	$	6,620	$	5,332	$	11,952
United States equities	4,546		—		—		4,546
Global equities	1,798		—		—		1,798
Fixed income	—		9,454		—		9,454
Total	$	6,344	$	16,074	$	5,332	$	27,750

While intended for payment of the nonqualified supplemental retirement plan benefits, these assets remain subject to the claims of the Company’s creditors and are not recognized in the funded status of the plan. These assets are recorded at fair value and included in Deferred Charges and Other 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)	2012		2011
Balance at beginning of period	$	5,332	$	5,069
Unrealized gains relating to instruments held at the reporting date	268		263
Balance at end of period	$	5,600	$	5,332

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The components of net periodic benefit cost were:

Years ended December 31, (in thousands)	2012			2011			2010
Pension Plans
Components of net periodic benefit cost:
Service cost	$	10,527		$	9,173		$	8,574
Interest cost	10,801			10,960			11,365
Expected long-term return on assets	(14,093		)	(15,471		)	(12,915		)
Prior service cost amortization	517			496			496
Actuarial loss amortization	8,603			6,435			5,773
Termination benefit charge	—			414			—
Net periodic expense	$	16,355		$	12,007		$	13,293
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	1,853		$	1,769		$	2,064
Interest cost	4,248			4,443			4,833
Expected long-term return on assets	(4,438		)	(4,418		)	(3,986		)
Actuarial loss amortization	37			—			—
Transition obligation amortization	1,917			1,917			1,917
Net periodic expense	$	3,617		$	3,711		$	4,828

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

Years ended December 31, (in thousands)	2012			2011			2010
Pension Plans
Net actuarial loss experienced during the year	$	28,748		$	14,312		$	4,332
Net actuarial loss recognized as expense	(4,908		)	(3,755		)	(3,290		)
Prior service cost recognized as expense	(340		)	(298		)	(298		)
Total recognized in other comprehensive income	23,500			10,259			744
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	(1,787	)	$	2,111		$	(2,094	)
Transition obligation recognized as expense	(294		)	(286		)	(280		)
Total recognized in other comprehensive income (loss)	$	(2,081	)	$	1,825		$	(2,374	)

Net retirement expense for Alagasco was $7.8 million, $5.2 million and $6.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. In the first quarter of 2011, the Company recognized a termination benefit charge of $0.4 million to provide for early retirement of certain non-highly compensated employees. Net periodic postretirement benefit expense for Alagasco was $2.7 million, $2.8 million and $3.6 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Estimated amounts to be amortized from accumulated other comprehensive income into pension cost during 2013 are as follows:

(in thousands)
Amortization of prior service cost	$	313
Amortization of net actuarial loss	$	8,591

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Estimated amounts to be amortized from accumulated other comprehensive income into benefit cost during 2013 are as follows:

(in thousands)
Amortization of transition obligation	$	264

The Company has a long-term disability plan covering most employees. The Company had expense for the years ended December 31, 2012, 2011 and 2010 of $0.7 million, $0.5 million and $0.4 million, respectively.

Assumptions:

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

Years ended December 31,	2012		2011		2010
Pension Plans
Discount rate	4.52	%	4.89	%	5.49	%
Expected long-term return on plan assets	7.00	%	7.25	%	7.25	%
Rate of compensation increase for pay-related plans	3.59	%	3.75	%	3.95	%
Postretirement Benefit Plans
Discount rate	4.95	%	5.45	%	5.90	%
Expected long-term return on plan assets	7.00	%	7.25	%	7.25	%
Rate of compensation increase	3.55	%	3.61	%	3.69	%

The weighted average rate assumptions used to determine the projected benefit obligations at the measurement date were as follows:

Years ended December 31,	2012		2011
Pension Plans
Discount rate	3.47	%	4.52	%
Rate of compensation increase for pay-related plans	3.71	%	3.59	%
Postretirement Benefit Plans
Discount rate	4.15	%	4.95	%
Rate of compensation increase for pay-related plans	3.70	%	3.55	%

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,	2012		2011
Health care cost trend rate assumed for next year	6.75	%	7.00	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2020		2020

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Assumed health care cost trend rates used in determining the accumulated postretirement benefit obligation have an effect on the amounts reported. For example, revising the weighted average health care cost trend rate by 1 percentage point would have the following effects:

(in thousands)
	1-Percentage Point Decrease			1-Percentage Point Increase
Effect on total of service and interest cost	$	(381	)	$	456
Effect on net postretirement benefit obligation	$	(3,688	)	$	4,342

Investment Strategy: The Company employs 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.

The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the Company to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily.

The Company 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 pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, 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		2012		2011		Target		2012		2011
Asset category:
Equity securities	41	%	41	%	39	%	60	%	60	%	60	%
Debt securities	38	%	38	%	40	%	40	%	40	%	40	%
Other	21	%	21	%	21	%	—	%	—	%	—	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

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

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

	December 31, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
United States equities	$	41,907	$	9,072	$	—	$	50,979
Global equities	23,782		10,697		—		34,479
Fixed income	—		78,806		—		78,806
Alternative investments	—		27,659		14,500		42,159
Cash and cash equivalents	—		3,001		—		3,001
Total	$	65,689	$	129,235	$	14,500	$	209,424
	December 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
United States equities	$	37,009	$	8,916	$	—	$	45,925
Global equities	20,064		4,914		4,352		29,330
Fixed income	—		78,443		—		78,443
Alternative investments	—		26,070		13,047		39,117
Cash and cash equivalents	—		2,844		—		2,844
Total	$	57,073	$	121,187	$	17,399	$	195,659

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 asset investments consist of limited partnerships and commingled and mutual funds with varying investment strategies. Alternative assets 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)	2012			2011
Balance at beginning of period	$	17,399		$	26,841
Unrealized gains (losses)	992			(752		)
Unrealized gains relating to instruments held at the reporting date	242			635
Settlements	(4,948		)	(9,604		)
Purchases	815			279
Balance at end of period	$	14,500		$	17,399

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

	December 31, 2012
(in thousands)	Level 1		Level 2		Total
United States equities	$	37,482	$	—	$	37,482
Global equities	15,049		—		15,049
Fixed income	—		34,658		34,658
Total	$	52,531	$	34,658	$	87,189

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	December 31, 2011
(in thousands)	Level 1		Level 2		Total
United States equities	$	33,649	$	—	$	33,649
Global equities	13,088		—		13,088
Fixed income	—		31,384		31,384
Total	$	46,737	$	31,384	$	78,121

The Company had no Level 3 postretirement benefit plan assets. United States equities consisted 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: There are no required contributions to the qualified pension plans during 2013. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $9.0 million to the qualified pension plans in January 2013. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2013. The Company expects to make benefit payments of approximately $3.8 million during 2013 to retirees with respect to the nonqualified supplemental retirement plans. The Company expects to make discretionary contributions of $1.6 million to the postretirement health care and life insurance benefit plans during 2013.

The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows. In addition, the following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy which began in 2007:

(in thousands)	Pension Benefits	Postretirement Benefits	Postretirement Benefits – Prescription Drug Subsidy
2013	$20,354	$4,435	$(243)
2014	$20,982	$4,586	$(248)
2015	$21,679	$4,754	$(252)
2016	$23,155	$4,940	$(258)
2017	$28,139	$5,165	$(260)
2018-2022	$166,646	$28,565	$(1,333)

In March 2010, The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (collectively, Health Care Reform) was signed into law. The impact of the legislation has been estimated and is first reflected in the December 31, 2011 measurement of the post retirement benefit obligation.  Energen has applied and been approved for the Early Retiree Reinsurance Program (ERRP). Energen is currently evaluating the application of the ERRP receipts and, therefore, the post retirement benefit obligations have not been reduced to reflect actual or expected receipts under the program.

6. COMMON STOCK PLANS

Energen Employee Savings Plan (ESP): A majority of Company employees are eligible to participate in the ESP by electing to contribute a portion of their compensation to the ESP. The Company may match a percentage of the contributions and make these contributions in Company common stock or in funds for the purchase of Company common stock. Employees may diversify 100 percent of their ESP Company stock account into other ESP investment options. The ESP also contains employee stock ownership plan provisions. At December 31, 2012, total shares reserved for issuance equaled 1,080,108. Expense associated with Company contributions to the ESP was $7.8 million, $6.8 million and $6.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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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. The Company 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 Company common stock were reserved for issuance with 3,418,881 remaining for issuance as of December 31, 2012.

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 Company 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 Company common stock.

No performance share awards were granted in 2012, 2011 or 2010. A summary of performance share award activity is presented below:

	Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2009	111,143		$	43.81
Vested and paid	(111,143	)	43.81
Nonvested at December 31, 2010	—		$	—

During the years ended December 31, 2012, 2011 and 2010, the Company recorded no expense for performance share awards.

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 Company common stock at not less than the fair market value on the date the option is 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.

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A summary of stock option activity as of December 31, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 are presented below:

	Stock Incentive Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2009	1,107,809		$	36.83
Granted	281,110		46.69
Exercised	(111,676	)	23.83
Forfeited	(1,200	)	13.72
Outstanding at December 31, 2010	1,276,043		40.16
Granted	293,978		54.99
Exercised	(227,405	)	32.33
Forfeited	(4,375	)	35.35
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
Exercisable at December 31, 2010	574,992		$	41.16
Exercisable at December 31, 2011	677,753		$	43.72
Exercisable at December 31, 2012	987,733		$	43.75
Remaining reserved for issuance at December 31, 2012	3,418,881		—

The Company 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	1/25/2012		1/26/2011		1/27/2010
Awards granted	371,040		293,978		281,110
Fair market value of stock option at grant	$18.79		$19.65		$16.47
Expected life of award	5.8 years		5.8 years		5.7 years
Risk-free interest rate	1.07	%	2.45	%	2.76	%
Annualized volatility rate	39.6	%	37.8	%	37.3	%
Dividend yield	1.0	%	1.0	%	1.1	%

The Company recorded stock option expense of $7.0 million, $5.6 million and $4.6 million during the years ended December 31, 2012, 2011 and 2010, respectively, with a related deferred tax benefit of $2.6 million, $2.1 million and $1.7 million respectively.

The total intrinsic value of stock options exercised during the year ended December 31, 2012, was $1.1 million. During the year ended December 31, 2012, the Company received cash of $1.5 million from the exercise of stock options and paid $1.8 million in settlement of stock appreciation rights. Total intrinsic value for outstanding options as of December 31, 2012, was $5.7 million and $5.7 million for exercisable options. The fair value of options vested for the year ended December 31, 2012 was $5.1 million. As of December 31, 2012, there was $1.9 million of unrecognized compensation cost related to outstanding nonvested stock options.

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The following table summarizes options outstanding as of December 31, 2012:

Stock Incentive Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
$14.86	16,270	.08 years
$21.38	5,560	1.08 years
$46.45	150,710	4.00 years
$55.08	7,260	4.50 years
$60.56	184,565	5.00 years
$29.79	333,232	6.00 years
$43.30	4,750	6.67 years
$46.69	281,110	7.00 years
$54.99	293,978	8.00 years
$54.11	371,040	9.00 years
$14.86-$60.56	1,648,475	6.83 years

The weighted average remaining contractual life of currently exercisable stock options is 5.76 years as of December 31, 2012.

Restricted Stock: In addition, the Stock Incentive Plan provided for the grant of restricted stock which have been valued based on the quoted market price of the Company’s common stock at the date of grant. Restricted stock awards have a three year vesting period. A summary of restricted stock activity as of December 31, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 is presented below:

	Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2009	53,005		$	32.66
Vested	(28,855	)	30.30
Nonvested at December 31, 2010	24,150		35.49
Vested	(14,875	)	30.81
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

The Company recorded expense of $0.1 million, $0.1 million and $0.2 million for the years ended December 31, 2012, 2011 and 2010, respectively, related to restricted stock, with a related deferred income tax benefit of $31,000, $47,000 and $70,000, respectively. As of December 31, 2012, there was $0.5 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 2.96 years.

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2004 Stock Appreciation Rights Plan: The Energen 2004 Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Company stock. Officers of the Company are not eligible to participate in this Plan. These awards are liability awards which settle in cash and are re-measured 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, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 are presented below:

	2004 Stock Appreciation Rights Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2009	503,215		$	35.46
Granted	171,749		46.69
Exercised/forfeited	(18,624	)	37.65
Outstanding at December 31, 2010	656,340		38.30
Granted	189,984		54.99
Exercised/forfeited	(69,106	)	41.21
Outstanding at December 31, 2011	777,218		42.00
Exercised/forfeited	(124,188	)	30.90
Outstanding at December 31, 2012	653,030		$	44.14

The Company issued the following awards with stock appreciation rights. The Company 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 as of December 31, 2012:

Grant date	1/26/2011	1/27/2010	2/13-16/2009	1/28/2009	2/4/2008	2/1/2007
Awards granted	189,984	171,749	3,292	305,257	67,093	85,906
Fair market value of award	$11.19	$11.93	$17.57	$18.46	$5.80	$9.25
Expected life of award	4.6 years	3.6 years	3.0 years	3.0 years	2.6 years	2.0 years
Risk-free interest rate	0.63%	0.44%	0.37%	0.37%	0.31%	0.26%
Annualized volatility rate	40.4%	40.4%	40.4%	40.4%	40.4%	40.4%
Dividend yield	1.2%	1.2%	1.2%	1.2%	1.2%	1.2%

Income associated with stock appreciation rights of $1.0 million was recorded for the year ended December 31, 2012. Expense associated with stock appreciation rights of $4.3 million and $3.4 million was recorded for the years ended December 31, 2011 and 2010, respectively. During the year ended December 31, 2012, the total intrinsic value of stock appreciation rights exercised was $2.6 million. During the year ended December 31, 2012, the Company paid $1.8 million in settlement of stock appreciation rights.

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Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provided for the grant of stock equivalent units which may include market conditions. Officers of the Company are not eligible to participate in this Plan. These awards are liability awards which are re-measured each reporting period and settle in cash at completion of the vesting period. Stock equivalent units with service conditions were valued based on the Company’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, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 are presented below:

	Petrotech Incentive Plan
	Shares
Outstanding at December 31, 2009	32,350
Granted (three-year vesting period)	2,442
Paid	(26,587	)
Outstanding at December 31, 2010	8,205
Granted (three-year vesting period)	6,314
Paid	(1,914	)
Forfeited	(1,544	)
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

None of the awards issued included a market condition. Energen Resources recognized expense of $2.6 million, $0.2 million and $0.2 million during 2012, 2011 and 2010, 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 the Company's common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company 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 the Company's creditors. Amounts earned under the Deferred Compensation Plan and invested in Company 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, 2012 there were 701,348 shares reserved for issuance from the 1997 Deferred Compensation Plan.

1992 Energen Corporation Directors Stock Plan: In 1992 the Company adopted the Energen Corporation Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Company common stock. Under the Plan, 11,120 shares, 12,420 shares and 15,400 shares were awarded during the years ended December 31, 2012, 2011 and 2010, respectively, leaving 151,784 shares reserved for issuance as of December 31, 2012.

Stock Repurchase Program: By resolution adopted May 25, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board authorized the Company to repurchase up to 12,564,400 shares of the Company's common stock. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2012, 2011 and 2010. As of December 31, 2012, a total of 8,992,700 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Company's stock compensation plans. For the years ended December 31, 2012, 2011 and 2010, the Company acquired 5,459 shares, 12,867 shares and 62,794 shares, respectively, in connection with its stock compensation plans.

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7. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources 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 33.4 million barrels of oil equivalent (MMBOE) through November 2021.

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources' total resulting exposure could be as much as $21.9 million depending on the contractor's ability to remarket the drilling rigs.

Certain of Alagasco's long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $59 million through September 2024. During the years ended December 31, 2012, 2011 and 2010, Alagasco recognized approximately $51 million, $51 million and $52 million, respectively, of current-year commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 171 Bcf through August 2020.

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

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns and is the subject of a recent inquiry discussed below. Also discussed below is the recent completion of a removal action at the Huntsville, Alabama manufactured gas plant site. An investigation of the sites does not indicate the present need for other remediation activities and management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the financial position of Alagasco.

In May 2012, Alagasco received from the United States Environmental Protection Agency (EPA) a Request for information Pursuant to Section 104 of CERCLA relating to the EPA's investigation of a site which it refers to as the 35^th Avenue Superfund Site in and around Birmingham, Jefferson County, Alabama. The inquiry requests information about a parcel owned by Alagasco and located in the vicinity of the 35^th Avenue site. The parcel is the former site of a manufactured gas distribution facility. Alagasco has responded to the inquiry.

In June 2009, Alagasco received a General Notice Letter from the EPA identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949. While Alagasco no longer owns the Huntsville site, the Company and the current site owner entered into a Consent Order, and developed and completed during 2011 an action plan for the site. Alagasco has incurred costs associated with the site of approximately $5 million. As of December 31, 2012, the expected remaining costs are not expected to be material to the Company. Alagasco has recorded a corresponding amount, subject to APSC review guidelines, against the refundable negative salvage costs being refunded to customers.

Legal Matters: 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. 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 Energen and its affiliates conduct business in jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

Various pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability. This provision was increased by $0.1 million during the year ended December 31, 2012.

On November 2, 2011 Energen Resources spudded the Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. During the drilling phase, Chesapeake Exploration, LLC, notified Energen Resources that it believed it was the owner of the lease from

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which the Cadenhead Well was producing. Shortly thereafter, Energen Resources filed a declaratory judgment action in the District Court of Ward County, Texas to resolve the title dispute. Energen Resources has a fifty percent working interest in the Cadenhead Well. The Cadenhead Well produced approximately 63 net MBOE in 2012 and is expected to produce approximately 42 net MBOE in 2013. On January 18, 2013, a judgment was entered which was adverse to Energen Resources' claim of ownership. The Company believes the adverse ruling was incorrect, and plans to vigorously pursue all available avenues of appeal.

New Mexico Audits: During the third quarter of 2011, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted 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 ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company's New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department's findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of December 31, 2012.

Lease Obligations: Alagasco leases the Company's headquarters building over a 25-year term ending January 31, 2024 and the related lease is accounted for as an operating lease. Under the terms of the lease, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Energen's total lease payments included as operating lease expense were $20.9 million, $19.1 million and $18.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. Minimum future rental payments required after 2012 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2013	2014	2015	2016	2017	2018 and thereafter
$5,144	$4,836	$4,506	$4,141	$3,980	$13,046

Alagasco's total payments related to leases included as operating expense, net of approximately $1.0 million of lease expense paid by Energen each year, were $2.1 million, $2.3 million and $2.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. Minimum future rental payments required after 2012 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2013	2014	2015	2016	2017	2018 and thereafter
$3,629	$3,858	$3,909	$3,934	$3,980	$13,046

Included in the table above are approximately $17.6 million of payments associated with leasing of the Company’s headquarters, which are expected to be reimbursed to Alagasco by Energen through the remaining term of the related lease. Such amounts are subject to intercompany allocations but are not subject to contractual agreements.

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Capital Lease Obligations: During the first quarter of 2012, the Company entered into capital leases related to certain equipment. The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2012:

(in thousands)
2013	$	1,743
2014	1,743
2015	145
Total minimum lease payments	3,631
Less amount representing interest	54
Total present value of minimum lease payments	$	3,577

8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Financial Instruments: The stated value of cash and cash equivalents, short-term investments, trade 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, approximates $1,255.8 million and $1,214.9 million and has a carrying value of $1,154.0 million and $1,155.2 million at December 31, 2012 and 2011, respectively. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $284.7 million and $274.9 million and has a carrying value of $250.0 million and $250.2 million at December 31, 2012 and 2011, 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.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers' current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At December 31, 2012, the fixed price purchases under these guarantees had a maximum term outstanding through March 2013 with an aggregate purchase price of $0.3 million and a market value of $0.3 million.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At December 31, 2012 and 2011, Alagasco’s finance receivable totaled approximately $10.7 million and $10.5 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.5 million and $0.4 million as of December 31, 2012 and 2011, respectively.

The following table sets forth a summary of changes in the allowance for credit losses as follows:

(in thousands)
Allowance for credit losses as of December 31, 2010	$	447
Provision	(26		)
Allowance for credit losses as of December 31, 2011	421
Provision	49
Allowance for credit losses as of December 31, 2012	$	470

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Risk Management: At December 31, 2012, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with twelve of its active counterparties and in a net loss position with the remaining two at December 31, 2012. The four largest counterparty net gain positions at December 31, 2012, Macquarie Bank Limited, J Aron & Company, BP Corporation North America Inc. and Shell Energy North America (US), L.P., constituted approximately $20.0 million, $16.6 million, $13.6 million and $10.3 million gain, respectively, of Energen Resources' net gain on fair value of derivatives.

The following table details the fair values of commodity contracts by business segment on the balance sheets:

(in thousands)	December 31, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	87,514			$	—		$	87,514
Long-term asset derivative instruments	37,954				—			37,954
Total derivative assets	125,468				—			125,468
Accounts receivable	(37,326		)	*	—			(37,326		)
Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
Long-term liability derivative instruments	(8,726		)		—			(8,726		)
Total derivative liabilities	(52,862		)		—			(52,862		)
Total derivatives designated	72,606				—			72,606
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,604				—			14,604
Long-term asset derivative instruments	9,433				—			9,433
Total derivative assets	24,037				—			24,037
Accounts payable	—				(2,593		)	(2,593		)
Long-term liability derivative instruments	(874		)		—			(874		)
Total derivative liabilities	(874		)		(2,593		)	(3,467		)
Total derivatives not designated	23,163				(2,593		)	20,570
Total derivatives	$	95,769			$	(2,593	)	$	93,176

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(in thousands)	December 31, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	73,636			$	—		$	73,636
Long-term asset derivative instruments	75,982				—			75,982
Total derivative assets	149,618				—			149,618
Accounts receivable	(48,174		)	*	—			(48,174		)
Long-term asset derivative instruments	(36,341		)	*	—			(36,341		)
Accounts payable	(37,070		)		—			(37,070		)
Long-term liability derivative instruments	(20,386		)		—			(20,386		)
Total derivative liabilities	(141,971		)		—			(141,971		)
Total derivatives designated	7,647				—			7,647
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(3,670		)	*	—			(3,670		)
Long-term asset derivative instruments	(8,585		)	*	—			(8,585		)
Total derivative assets	(12,255		)		—			(12,255		)
Accounts payable	(13,416		)		(56,804		)	(70,220		)
Long-term liability derivative instruments	(10,922		)		(3,070		)	(13,992		)
Total derivative liabilities	(24,338		)		(59,874		)	(84,212		)
Total derivatives not designated	(36,593		)		(59,874		)	(96,467		)
Total derivatives	$	(28,946	)		$	(59,874	)	$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

The Company had a net $28.4 million and a net $5.7 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in other comprehensive income as of December 31, 2012 and 2011, respectively.

The following table details the effect of derivative commodity instruments designated as hedging instruments on the financial statements:

Years ended December 31, (in thousands)	Location on Income Statement	2012			2011			2010
Net gain recognized in OCI on derivative (effective portion), net of tax of $40.7 million, $41.4 million and $19.5 million	—	$	66,438		$	67,547		$	31,801
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	52,694		$	26,326		$	200,324
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(5,340	)	$	(2,767	)	$	1,082

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

Years ended December 31, (in thousands)	Location on Income Statement	2012		2011			2010
Gain (loss) recognized in income on derivative	Operating revenues	$	61,841	$	(37,587	)	$	(3	)

As of December 31, 2012, $32.7 million of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, net of tax, are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of December 31, 2012, the Company had 5.6 billion and 9.7 billion cubic feet (Bcf) of natural gas hedges which expire during 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 9.7 million and 5.4 million barrels (MMBbl) of oil and oil basis hedges which expire during 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2013 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. During 2011, the Company had a discontinuance of hedge accounting when Energen Resources determined it was probable certain forecasted volumes would not occur, which resulted in $63,000 after-tax gain being recognized into operating revenues during the year ended December 31, 2012.

As of December 31, 2012, Energen Resources entered into the following transactions for 2013 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Oil
2013	8,858	MBbl	$90.95 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
Oil Basis Differential
2013	3,592	MBbl	$(3.03) Bbl	WTS/WTI Basis Swaps*
	2,760	MBbl	$(1.01) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Alagasco entered into the following natural gas transactions for 2013:

Production Period	Total Hedged Volumes	Description
2013	1.5 Bcf	NYMEX Swaps

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As of December 31, 2012, the maximum term over which Energen Resources and Alagasco has hedged exposures to the variability of cash flows is through December 31, 2014 and March 31, 2013, respectively. Alagasco has not entered into any new cash flow derivative transactions on its gas supply since 2010. 

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	December 31, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(3,629	)	$	68,421		$	64,792
Noncurrent assets	18,899			21,678			40,577
Current liabilities	(2,593		)	—			(2,593		)
Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
Net derivative asset	$	4,157		$	89,019		$	93,176

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. As of December 31, 2011, Alagasco had $56.8 million and $3.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012 and 2011.

The Company 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 derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $27 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $2.5 million associated with open Level 3 mark-to-market derivative contracts. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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

Years ended December 31, (in thousands)	2012			2011			2010
Balance at beginning of period	$	65,801		$	42,755		$	64,517
Realized gains (losses)	63,720			52,716			111,107
Unrealized gains relating to instruments held at the reporting date*	22,160			23,980			(21,521		)
Purchases and settlements during period	(62,662		)	(53,650		)	(111,348		)
Balance at end of period	$	89,019		$	65,801		$	42,755

*Includes $19.9 million in mark-to-market gains and $5.2 million in mark-to-market losses for the years ended December 31, 2012 and 2011, respectively. There were no Level 3 mark-to-market gains or losses for the year ended December 31, 2010.

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

(in thousands)	Fair Value as of December 31, 2012			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	38,254		Discounted Cash Flow	Forward Basis	($0.15 - $0.16) Mcf
2014	$	21,100		Discounted Cash Flow	Forward Basis	($0.13 - $0.17) Mcf
Natural Gas Basis - Permian
2013	$	160		Discounted Cash Flow	Forward Basis	($0.13) Mcf
2014	$	(871	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.13) Mcf
Oil Basis - WTS/WTI
2013	$	10,338		Discounted Cash Flow	Forward Basis	($5.19) Bbl
Oil Basis - WTI/WTI
2013	$	8,217		Discounted Cash Flow	Forward Basis	($2.92 - $3.62) Bbl
Natural Gas Liquids
2013	$	11,821		Discounted Cash Flow	Forward Price	$0.73 - $0.82 Gal

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

Concentration of Credit Risk:Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil 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 the Company's overall exposure to credit risk, either positively or negatively, in that the Company's oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources 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 oil and gas purchasers accounted for approximately 29 percent and 13 percent of Energen Resources’ accounts receivable for commodity sales as of December 31, 2012. Energen Resources’ other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2012. During the year ended December 31, 2012, the two largest oil and gas purchasers accounted for approximately 27 percent and 12 percent of Energen Resources’ total operating revenues.

Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 425,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.

9. RECONCILIATION OF EARNINGS PER SHARE

Years ended December 31,
(in thousands, except per share amounts)			2012					2011					2010
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	253,562	72,119	$	3.52	$	259,624	72,056	$	3.60	$	290,807	71,845	$	4.05
Effect of dilutive securities
Stock options			196					270					190
Non-vested restricted stock			1					6					16
Diluted EPS	$	253,562	72,316	$	3.51	$	259,624	72,332	$	3.59	$	290,807	72,051	$	4.04

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For the years ended December 31, 2012, 2011 and 2010, the Company had 849,583, 293,978 and 479,820 options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the years ended December 31, 2012, 2011 and 2011, the Company had no shares of non-restricted stock that were excluded from the computation of diluted EPS.

10. ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the period incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company. Revisions in estimates to the ARO result from revisions to the estimated timing or amount of the underlying cash flows. In 2012, 2011 and 2010, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2009	$	88,298
Liabilities incurred	4,033
Liabilities settled	(1,094		)
Accretion expense	6,178
Balance of ARO as of December 31, 2010	97,415
Liabilities incurred	4,627
Liabilities settled	(1,539		)
Accretion expense	6,837
Balance of ARO as of December 31, 2011	107,340
Liabilities incurred	3,994
Liabilities settled	(845		)
Accretion expense	7,534
Balance of ARO as of December 31, 2012	$	118,023

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $24.9 million and $20.8 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of December 31, 2012 and 2011, respectively. Regulatory assets for accumulated asset removal costs of $3.3 million and $1.0 million as of December 31, 2012 and 2011, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

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11. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental information concerning Energen's cash flow activities was as follows:

Years ended December 31, (in thousands)	2012		2011		2010
Interest paid, net of amount capitalized	$	61,379	$	33,601	$	37,517
Income taxes paid	$	17,170	$	9,432	$	83,894
Noncash investing activities:
Accrued development, exploration costs and other capital	$	120,024	$	72,030	$	75,167
Capitalized depreciation	$	80	$	93	$	116
Capitalized asset retirement obligations costs	$	4,409	$	4,927	$	4,194
Allowance for funds used during construction	$	623	$	807	$	808
Capital lease obligations	$	5,072	$	—	$	—
Noncash financing activities:
Issuance of common stock for employee benefit plans	$	838	$	822	$	5,765
Treasury stock acquired in connection with tax withholdings	$	277	$	713	$	2,894

The Company recorded a non-cash adjustment for accretion expense of $7.5 million, $6.8 million and $6.2 million during 2012, 2011 and 2010, respectively.

Supplemental information concerning Alagasco's cash flow activities was as follows:

Years ended December 31, (in thousands)	2012		2011		2010
Interest paid, net of amount capitalized	$	13,513	$	12,385	$	11,653
Income taxes paid	$	16,796	$	5,143	$	13,063
Interest on affiliated company debt, net	$	295	$	376	$	274
Noncash investing activities:
Accrued property, plant and equipment costs	$	3,536	$	2,229	$	2,592
Capitalized depreciation	$	80	$	93	$	116
Capitalized asset retirement obligations costs	$	415	$	300	$	161
Allowance for funds used during construction	$	623	$	807	$	808

12. ACQUISITION AND DISPOSITION OF OIL AND GAS PROPERTIES

During the first quarter of 2012, Energen Resources recognized a noncash 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. 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 was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

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.

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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.

On December 27, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $60 million. This purchase had an effective date of July 1, 2011. Energen acquired total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percent of the proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 15 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 December 27, 2011 (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	60,017
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	36,068
Unproved leasehold properties	23,686
Accounts receivable	680
Accounts payable	(244		)
Asset retirement obligation	(173		)
Total identifiable net assets	$	60,017

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The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

On November 16, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $162 million. This purchase had an effective date of August 1, 2011. Energen acquired total proved reserves of approximately 13.6 MMBOE. Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 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 November 16, 2011, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	161,967
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,544
Unproved leasehold properties	7,883
Accounts receivable	3,070
Accounts payable	(388		)
Asset retirement obligation	(142		)
Total identifiable net assets	$	161,967

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

In July 2011, Energen completed the purchase of properties in the Permian Basin for a cash purchase price of approximately $20 million. In April 2011, Energen completed the purchase of unproved leasehold properties for a cash purchase price of approximately $37 million covering an estimated 11,000 net acres in the Permian Basin.

During 2010, Energen Resources incurred write-offs of unproved capitalized leasehold costs associated with its Alabama shale acreage. The non-cash costs totaled $39.7 million pre-tax and were charged to exploration expense, which is included in O&M expense, after the Company determined that the shale acreage was not economically viable. During the year ended December 31, 2010, Energen Resources also recorded $15.5 million pre-tax in write-offs of well costs related to Alabama shale leasehold.

On December 15, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $74 million. This purchase had an effective date of December 1, 2010. Energen acquired proved reserves of approximately 7.6 MMBOE. Of the proved reserves acquired, an estimated 92 percent are undeveloped. Approximately 62 percent of the acquisition’s estimated proved reserves are oil, 24 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.

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The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 15, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	73,630
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	41,066
Unproved leasehold properties	32,500
Accounts receivable	143
Asset retirement obligation	(79		)
Total identifiable net assets	$	73,630

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2010.

On December 9, 2010, Energen completed the asset purchase of certain properties in the Permian Basin from SandRidge Energy, Inc. for a cash purchase price of $103 million (including the effects closing adjustments). This purchase had an effective date of December 9, 2010. Energen acquired no proved reserves related to this acquisition. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition.

On September 30, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash price of $188 million. This purchase had an effective date of September 1, 2010. Energen acquired proved reserves of approximately 18 MMBOE. Of the proved reserves acquired, an estimated 89 percent are undeveloped. Approximately 65 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 13 percent. Energen Resources used its 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 September 30, 2010, (including the effects of closing adjustment).

(in thousands)
Consideration given
Cash (net)	$	188,314
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,747
Unproved leasehold properties	35,360
Accounts receivable	1,461
Asset retirement obligation	(142		)
Accounts payable	(112		)
Total identifiable net assets	$	188,314

Included in the Company’s consolidated results of operations for the year ended December 31, 2010, is $5 million of operating revenues and $2.1 million in operating income resulting from the operation of the properties acquired above.

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13. REGULATORY ASSETS AND LIABILITIES

The following table details regulatory assets and liabilities on the consolidated balance sheets:

(in thousands)	December 31, 2012				December 31, 2011
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	90,708	$	170	$	77,587
Accretion and depreciation for asset retirement obligation	—		16,536		—		13,981
Risk management activities	2,593		—		56,804		3,070
Rate recovery of asset removal costs, net	—		3,322		—		994
Gas supply adjustment	42,726		—		—		—
Other	26		—		169		1
Total regulatory assets	$	45,515	$	110,566	$	57,143	$	95,633
Regulatory liabilities:
RSE adjustment	$	1,740	$	—	$	2,931	$	—
Unbilled service margin	25,078		—		22,419		—
Postretirement liabilities	—		1,237		—		—
Gas supply adjustment	—		—		12,626		—
Refundable negative salvage	18,265		53,467		20,269		65,646
Asset retirement obligation	—		24,930		—		20,785
Other	33		770		34		803
Total regulatory liabilities	$	45,116	$	80,404	$	58,279	$	87,234

As described in Note 2, Regulatory Matters, Alagasco's rates are established under the RSE rate-setting process and are based on average equity for the period. Alagasco's rates are not adjusted to exclude a return on its investment in regulatory assets during the recovery period.

14. TRANSACTIONS WITH RELATED PARTIES

The Company allocates certain corporate costs to Energen Resources and Alagasco based on the nature of the expense to be allocated using various factors including, but not limited to, total assets, earnings, or number of employees. The Company's cash management program seeks to minimize borrowing from outside sources through inter-company lending. Under this program, Alagasco may borrow from but does not lend to affiliates. Alagasco had net trade receivables from affiliates of $5.7 million and $2.8 million at December 31, 2012 and 2011, respectively. Interest income and expense between affiliates is calculated monthly based on the market weighted average interest rate. Alagasco had $0.3 million, $0.4 million and $0.3 million in affiliated company interest expense during the years ended December 31, 2012, 2011 and 2010, respectively.

15. RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The Company is currently evaluating the impact of the ASU but does not expect this update to have a material impact on its results of operations. In January 2013, the FASB issued Accounting Standard Update (ASU) No. 2013-01, Clarifying the Scope of Disclosures

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about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remain unchanged.

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. This update requires entities to present the components of net income and other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. This amendment was effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Adoption of this update did not have a material impact on the consolidated financial statements or results of operations.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment is effective for annual and interim reporting periods beginning after December 15, 2012. The Company is currently evaluating the impact of the ASU but does not expect this update to have a material impact on its consolidated financial statements or results of operations.

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirement in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments in this update result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRSs. The amendments are effective during interim and annual periods beginning after December 15, 2011. This standard did not have a material impact on the consolidated condensed financial statements of the Company. The additional fair value disclosures are included in Note 8, Financial Instruments.

16. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

The Company's business is seasonal in character. The following data summarizes quarterly operating results.

	Year ended December 31, 2012
(in thousands, except per share amounts)	First		Second		Third		Fourth
Operating revenues	$	418,444	$	470,355	$	295,324	$	433,046
Operating income	$	104,170	$	220,598	$	19,458	$	115,166
Net income	$	57,406	$	131,287	$	2,046	$	62,823
Diluted earnings per average common share	$	0.79	$	1.82	$	0.03	$	0.87
Basic earnings per average common share	$	0.80	$	1.82	$	0.03	$	0.87

	Year ended December 31, 2011
(in thousands, except per share amounts)	First		Second		Third		Fourth
Operating revenues	$	486,364	$	330,399	$	378,568	$	288,148
Operating income	$	159,881	$	106,335	$	150,412	$	31,641
Net income	$	94,268	$	63,325	$	87,599	$	14,432
Diluted earnings per average common share	$	1.30	$	0.87	$	1.21	$	0.20
Basic earnings per average common share	$	1.31	$	0.88	$	1.22	$	0.20

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Alagasco's business is seasonal in character and influenced by weather conditions. The following data summarizes Alagasco's quarterly operating results.

	Year ended December 31, 2012
(in thousands)	First		Second		Third			Fourth
Operating revenues	$	194,487	$	70,887	$	61,809		$	124,406
Operating income (loss)	$	78,560	$	4,448	$	(12,743	)	$	22,951
Net income (loss)	$	46,918	$	326	$	(10,039	)	$	12,197

	Year ended December 31, 2011
(in thousands)	First		Second		Third			Fourth
Operating revenues	$	269,572	$	86,309	$	59,616		$	119,456
Operating income (loss)	$	75,059	$	1,163	$	(10,681	)	$	20,675
Net income (loss)	$	44,175	$	262	$	(9,093	)	$	11,258

17. OIL AND GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:

(in thousands)	December 31, 2012		December 31, 2011
Proved	$	6,241,148	$	4,927,576
Unproved	197,979		238,792
Total capitalized costs	6,439,127		5,166,368
Accumulated depreciation, depletion and amortization	1,765,241		1,382,526
Capitalized costs, net	$	4,673,886	$	3,783,842

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)	2012		2011		2010
Property acquisition:
Proved	$	79,862	$	214,993	$	207,161
Unproved	58,634		91,888		201,881
Exploration	419,284		190,854		37,371
Development	749,256		623,775		332,541
Total costs incurred	$	1,307,036	$	1,121,510	$	778,954

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Results of Operations From Producing Activities: The following table sets forth results of the Company's oil and gas operations from producing activities:

Years ended December 31, (in thousands)	2012		2011		2010
Gross revenues*	$	1,167,183	$	944,908	$	957,371
Production (lifting costs)	306,375		257,045		224,901
Exploration expense	19,363		13,110		64,584
Depreciation, depletion and amortization	394,668		240,232		200,179
Accretion expense	7,534		6,837		6,178
Income tax expense	157,670		154,180		166,750
Results of operations from producing activities	$	281,573	$	273,504	$	294,779

*The years ended December 31, 2012, 2011 and 2010 gross revenues includes a pre-tax non cash mark-to-market gain on derivatives of $58.8 million, a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million and a pre-tax non-cash mark-to-market loss on derivatives of $3,000, respectively.

Oil and 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. Reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2012, 2011 and 2010. Changes to prices and costs could have a significant effect on the disclosed amount of reserves and their associated values. In addition, the estimation of 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 reserves disclosed. The proved reserves are located onshore in the United States of America.

Estimates of physical quantities of oil and 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 gas reservoir engineers, have audited the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2012. Ryder Scott audited the reserve estimates for coalbed methane in the Black Warrior and San Juan basins and substantially all of the Permian Basin reserves. T. Scott Hickman audited the reserves for the North Louisiana and East Texas regions and the conventional reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 99 percent of the Company's ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

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

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Year ended December 31, 2011	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
Proved reserves at beginning of period	954,387		103,262		40,601		302.9
Revisions of previous estimates	(12,823	)	(4,513	)	841		(5.8	)
Purchases	19,362		12,583		5,055		20.8
Extensions and discoveries	68,160		24,564		9,637		45.6
Production	(71,718	)	(6,318	)	(2,177	)	(20.4	)
Proved reserves at end of period	957,368		129,578		53,957		343.1
Proved developed reserves at end of period	788,812		83,899		33,154		248.5
Proved undeveloped reserves at end of period	168,556		45,679		20,803		94.6

Year ended December 31, 2010	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
Proved reserves at beginning of period	897,546		77,963		30,257		257.8
Revisions of previous estimates	66,679		(2,243	)	2,434		11.3
Purchases	21,700		16,443		5,730		25.8
Extensions and discoveries	39,570		16,234		4,058		26.8
Production	(70,924	)	(5,131	)	(1,880	)	(18.8	)
Sales	(184	)	(4	)	2		—
Proved reserves at end of period	954,387		103,262		40,601		302.9
Proved developed reserves at end of period	786,292		72,030		28,809		231.9
Proved undeveloped reserves at end of period	168,095		31,232		11,792		71.0

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

During 2012, Energen Resources 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.

2011 Activities: Energen Resources had downward reserve revisions during 2011 which totaled 5.8 MMBOE. The Black Warrior Basin had downward reserve revisions totaling 0.3 MMBOE of which approximately 0.7 MMBOE related to estimated negative price related revisions partially offset by other positive revisions of 0.4 MMBOE. The San Juan Basin downward reserve revisions of 2.6 MMBOE included 3.9 MMBOE in negative performance related revisions partially offset by 1.3 MMBOE related to estimated positive price related revisions. Downward reserve revisions of 3.1 MMBOE in the Permian Basin were primarily due to lower than anticipated injection response in certain waterflood units and other performance related adjustments. These downward revisions were partially offset by 1.4 MMBOE of estimated positive price related revisions.

Energen Resources purchased 20.8 MMBOE of reserves during 2011 primarily related to the acquisitions of oil properties in the Permian Basin.

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During 2011, Energen Resources had extensions and discoveries of 45.6 MMBOE of which 69 percent were proved undeveloped reserves and 31 percent were proved developed reserves. Extension drilling resulted in 41.1 MMBOE of discoveries with exploratory drilling providing 4.5 MMBOE of discoveries. The San Juan Basin added 5.9 MMBOE of reserves through the drilling or identification of 53 well locations. The Permian Basin added 39.6 MMBOE of reserves primarily through the drilling or identification of 395 well locations.

2010 Activities: Energen Resources had upward reserve revisions during 2010 which totaled 11.3 MMBOE. The Black Warrior Basin had upward reserve revisions totaling 0.6 MMBOE of which approximately 1.3 MMBOE related to changes in year-end pricing partially offset by downward reserve revisions of 0.7 MMBOE. The San Juan Basin upward reserve revisions of 11 MMBOE included 7.6 MMBOE related to changes in year-end pricing and 8.2 MMBOE associated with well performance partially offset by 5.3 MMBOE of downward reserve revisions resulting from the SEC’s five-year development rule. Downward reserve revisions of 1.3 MMBOE in the Permian Basin were due to lower than anticipated injection response in certain waterflood units offset by 3.0 MMBOE of estimated positive price related revisions.

Energen Resources purchased 25.8 MMBOE of reserves during 2010 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2010, Energen Resources had extensions and discoveries of 26.8 MMBOE of which 77 percent were proved undeveloped reserves and 23 percent were proved developed reserves. Extension drilling resulted in 26.6 MMBOE of discoveries with exploratory drilling providing 0.3 MMBOE of discoveries. The San Juan Basin added 6.4 MMBOE of reserves through the drilling or identification of 36 well locations; additionally, 1 sidetrack well added 1.1 MMBOE of reserves. The Permian Basin added 22.1 MMBOE of reserves primarily through the drilling or identification of 271 well locations.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and 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 the Company'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, 2012, 2011 and 2010, the Company had a deferred hedging gain of $74.8 million, a deferred hedging gain of $15 million and a deferred hedging loss of $70.4 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.

Years ended December 31, (in thousands)	2012		2011		2010
Future gross revenues	$	17,735,363	$	18,196,229	$	13,210,211
Future production costs	5,715,248		5,823,395		4,959,403
Future development costs	1,892,600		1,539,072		1,026,903
Future income tax expense	2,809,411		3,326,382		2,201,742
Future net cash flows	7,318,104		7,507,380		5,022,163
Discount at 10% per annum	3,618,785		3,878,217		2,555,027
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	3,699,319	$	3,629,163	$	2,467,136
Discounted future net cash flows before income taxes	$	4,411,399	$	4,691,086	$	3,155,746

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

Years ended December 31, (in thousands)	2012			2011			2010
Balance at beginning of year	$	3,629,163		$	2,467,136		$	1,563,190
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(922,792		)	707,411			945,179
Net changes due to revisions in quantity estimates	(383,755		)	(80,004		)	36,349
Development costs incurred, previously estimated	472,603			392,720			195,269
Accretion of discount	362,916			246,714			156,319
Changes in timing and other	(317,244		)	(25,937		)	15,815
Total revisions	(788,272		)	1,240,904			1,348,931
New field discoveries and extensions, net of future production and development costs	1,025,419			755,977			319,223
Sales of oil and gas produced, net of production costs	(812,781		)	(763,171		)	(576,755		)
Purchases	189,755			232,768			278,384
Sales	—			—			87
Net change in income taxes	456,035			(304,451		)	(465,924		)
Net change in standardized measure of discounted future net cash flows	70,156			1,162,027			903,946
Balance at end of year	$	3,699,319		$	3,629,163		$	2,467,136

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18. INDUSTRY SEGMENT INFORMATION

The Company is principally engaged in two business segments: the development, acquisition, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution). The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies.

Years ended December 31,(in thousands)	2012			2011			2010
Operating revenues
Oil and gas operations	$	1,165,580		$	948,526		$	958,762
Natural gas distribution	451,589			534,953			619,772
Total	$	1,617,169		$	1,483,479		$	1,578,534
Operating income (loss)
Oil and gas operations	$	367,243		$	363,131		$	406,729
Natural gas distribution	93,216			86,216			88,383
Eliminations and corporate expenses	(1,067		)	(1,078		)	(1,735		)
Total	$	459,392		$	448,269		$	493,377
Depreciation, depletion and amortization expense
Oil and gas operations	$	377,328		$	244,081		$	203,823
Natural gas distribution	42,270			39,916			44,042
Total	$	419,598		$	283,997		$	247,865
Interest expense
Oil and gas operations	$	49,972		$	30,907		$	25,753
Natural gas distribution	16,284			14,740			13,894
Eliminations and other	(700		)	(825		)	(425		)
Total	$	65,556		$	44,822		$	39,222
Income tax expense (benefit)
Oil and gas operations	$	114,375		$	120,079		$	138,775
Natural gas distribution	30,244			26,670			29,875
Other	(800		)	(1,048		)	(1,660		)
Total	$	143,819		$	145,701		$	166,990
Capital expenditures
Oil and gas operations	$	1,291,211		$	1,115,452		$	717,782
Natural gas distribution	71,869			73,984			93,566
Total	$	1,363,080		$	1,189,436		$	811,348
Identifiable assets
Oil and gas operations	$	4,975,170		$	4,046,242		$	3,160,601
Natural gas distribution	1,177,134			1,163,959			1,166,899
Eliminations and other	23,586			27,215			36,060
Total	$	6,175,890		$	5,237,416		$	4,363,560
Property, plant and equipment, net
Oil and gas operations	$	4,697,683		$	3,806,787		$	2,936,284
Natural gas distribution	842,685			813,471			782,665
Other	1,268			518			278
Total	$	5,541,636		$	4,620,776		$	3,719,227

98

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

Energen Corporation

Years ended December 31, (in thousands)	2012			2011			2010
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$	12,946		$	15,048		$	17,251
Additions:
Charged to income	1,415			4,269			2,665
Recoveries and adjustments	(1,262		)	(1,744		)	(1,100		)
Net additions	153			2,525			1,565
Less uncollectible accounts written off	(6,550		)	(4,627		)	(3,768		)
Balance at end of year	$	6,549		$	12,946		$	15,048

Alabama Gas Corporation

Years ended December 31, (in thousands)	2012			2011			2010
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$	12,100		$	14,200		$	16,400
Additions:
Charged to income	1,409			4,202			2,655
Recoveries and adjustments	(1,263		)	(1,745		)	(1,094		)
Net additions	146			2,457			1,561
Less uncollectible accounts written off	(6,546		)	(4,557		)	(3,761		)
Balance at end of year	$	5,700		$	12,100		$	14,200

99

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

None

ITEM 9A. CONTROLS AND PROCEDURES

Energen Corporation

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.

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

Management assessed the effectiveness of Energen Corporation's internal control over financial reporting as of December 31, 2012. Management based this assessment on criteria for effective internal control over financial reporting described in "Internal Control - Integrated Framework" 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, 2012, Energen Corporation maintained effective internal control over financial reporting. The effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 28, 2013

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.

100

Alabama Gas Corporation

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 Alabama Gas 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. Alabama Gas 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 Alabama Gas 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 Alabama Gas Corporation are being made only in accordance with authorization of management and directors of Alabama Gas Corporation; and

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

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

Management assessed the effectiveness of Alabama Gas Corporation's internal control over financial reporting as of December 31, 2012. Management based this assessment on criteria for effective internal control over financial reporting described in "Internal Control - Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management's assessment included an evaluation of the design of Alabama Gas 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, 2012, Alabama Gas Corporation maintained effective internal control over financial reporting. The effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 28, 2013

c. Changes in Internal Control Over Financial Reporting

Our chief executive officer and chief financial officer of Alabama Gas 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.

101

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 24, 2013. The definitive proxy statement will be filed on or about March 27, 2013.

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 24, 2013.

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 24, 2013.

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 24, 2013.

c. Securities Authorized for Issuance Under Equity Compensation Plans

The information regarding securities authorized for issuance under equity compensation plans is included in Part 2 under Item 4.

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 24, 2013.

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 24, 2013.

102

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 and the financial statements of Alagasco are included in Item 8 of this Form 10-K

(2) Financial Statement Schedules

The financial statement schedules are included in Item 8 of this Form 10-K

(3)Exhibits

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

103

Energen Corporation

Alabama Gas 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
*3(d)	Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated September 27, 1995, which was filed as Exhibit 3(i) to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1995
*3(e)	Bylaws of Alabama Gas Corporation (as amended through October 24, 2007) which was filed as Exhibit 3 to Energen's Quarterly Report on Form 10-Q for the period ended October 31, 2007
*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 October 3, 2003, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 5 percent Notes due October 1, 2013, which was filed as Exhibit 4 to Energen's Current Report on Form 8-K, dated October 3, 2003
*4(a)(v)	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
*4(b)	Indenture dated as of November 1, 1993, between Alabama Gas Corporation and NationsBank of Georgia, National Association, Trustee, ("Alagasco 1993 Indenture"), which was filed as Exhibit 4(k) to Alabama Gas Corporations' Registration Statement on Form S-3 (Registration No. 33-70466)
*4(b)(i)	Officers' Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.70 percent Notes due January 15, 2035, which was filed as Exhibit 4.3 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005

104

*4(b)(ii)	Officers' Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.20 percent Notes due January 15, 2020, which was filed as Exhibit 4.4 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005
*4(b)(iii)	Officers' Certificate, dated November 17, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.368 percent Notes due December 1, 2015, which was filed as Exhibit 4.2 to Alabama Gas Corporations’ Current Report on Form 8-K filed November 17, 2005
*4(b)(iv)	Officers' Certificate, dated January 16, 2007, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.90 percent Notes due January 15, 2037, which was filed as Exhibit 4.2 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 16, 2007
*10(a)	Credit Agreement dated October 30, 2012, by and among Energen Corporation, Energen Resources Corporation, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, Wells Fargo Bank, National Association and Regions Bank, and Co-Syndication Agents and L/C Issuers, Compass Bank and U.S. Bank National Association, as Co-Documentation Agents and L/C Issuers, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities LLC, Regions Capital Markets, a division of Regions Bank, Compass Bank and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 10.1 to Energen's Current Report on Form 8-K filed October 31, 2012
*10(b)	Credit Agreement dated November 29, 2011, with respect to a $300 million term loan, by and among Energen Corporation, as Borrower, Energen Resources Corporation, as Guarantor, Bank of America, N.A., as Administrative Agent, Wells Fargo Bank, National Association, Regions Bank and BBVA Compass, as Co-Syndication Agents, U.S. Bank National Association, as Documentation Agent, and the lenders party thereto, which was filed as Exhibit 10.1 to Energen's Current Report on Form 8-K filed December 5, 2011
*10(c)	Credit Agreement dated October 30, 2012, by and among Alabama Gas Corporation, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, Wells Fargo Bank, National Association and Regions Bank, and Co-Syndication Agents and L/C Issuers, Compass Bank and U.S. Bank National Association, as Co-Documentation Agents and L/C Issuers, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities LLC, Regions Capital Markets, a division of Regions Bank, Compass Bank and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 10.2 to Energen's Current Report on Form 8-K filed October 31, 2012
*10(d)	Note Purchase Agreement, dated December 22, 2011, among Alabama Gas Corporation and the Purchasers thereto (the AIG purchasers) with respect to $25 million 3.86 percent Senior Notes due December 22, 2021, which was filed as Exhibit 10.1 to Alabama Gas Corporation's Current Report on Form 8-K filed December 22, 2011
*10(e)	Note Purchase Agreement, dated December 22, 2011, among Alabama Gas Corporation and the Purchasers thereto (the Prudential purchasers) with respect to $25 million 3.86 percent Senior Notes due December 22, 2021, which was filed as Exhibit 10.2 to Alabama Gas Corporation's Current Report on Form 8-K filed December 22, 2011
*10(f)	Service Agreement Under Rate Schedule CSS (No. SSNG1), between Southern Natural Gas Company and Alabama Gas Corporation, dated as of September 1, 2005, which was filed as Exhibit 10(a) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(g)	Firm Transportation Service Agreement Under Rate Schedule FT and/or FT-NN (No. FSNG1), between Southern Natural Gas Company and Alabama Gas Corporation dated as of September 1, 2005, which was filed as Exhibit 10(b) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(h)	Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and Alabama Gas Corporation, which was filed as Exhibit 10(b) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993
*10(i)	Amended Exhibits A and B, effective June 1, 2009, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas Corporation which was filed as Exhibit 10(c)(i) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2009

105

*10(j)	Amended Exhibits A and B, effective September 1, 2010, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas Corporation which was filed as Exhibit 10(c)(ii) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2009
*10(k)	Service Agreement between Transcontinental Gas Pipeline Corporation and Transco Energy Marketing Company as Agent for Alabama Gas Corporation, dated August 1, 1991 which was filed as Exhibit 3(e) to Energen's Annual Report on Form 10-K for the year ended December 31, 2003
*10(l)	Amendment to Service Agreement between Transcontinental Gas Pipeline Corporation and Alabama Gas Corporation, dated December 2, 2005, which was filed as Exhibit 10(e) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(m)	Occluded Gas Lease, dated January 1, 1986 and First through Seventh Amendments, which was filed as Exhibit 10(f) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(n)	Eighth Amendment to Occluded Gas Lease, dated January 1, 2009, while was filed as Exhibit 10(f)(i) to Energen’s Annual Report on Form 10-k for the year ended December 31, 2008
*10(o)	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(p)	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(q)	Energen Corporation Stock Incentive Plan (as amended effective December 1, 2012) which was filed as Exhibit 10.2 to Energen’s Current Report on Form 8-K filed December 13, 2012
10(r)	Form of Stock Option Agreement under the Energen Corporation Stock Incentive Plan
10(s)	Form of Restricted Stock Agreement under the Energen Corporation Stock Incentive Plan
10(t)	Form of Performance Share Award under the Energen Corporation Stock Incentive Plan
10(u)	Energen Corporation 1997 Deferred Compensation Plan (as amended December 12, 2012)
*10(v)	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(w)	Energen Corporation Annual Incentive Compensation Plan, as amended effective January 1, 2013, which was filed as Exhibit 10.1 to Energen's Current Report on Form 8-K, filed December 13, 2012
21	Subsidiaries of Energen Corporation and Alabama Gas 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)

106

31(c)	Alabama Gas Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a)
31(d)	Alabama Gas Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)
32(a)	Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
32(b)	Alabama Gas 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, 2012 are formatted in XBRL
*Incorporated by reference

107

SIGNATURE

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

ENERGEN CORPORATION

(Registrant)

ALABAMA GAS CORPORATION

(Registrant)

February 28, 2013	By   /s/ J.T. McManus, II
	J.T. McManus, II
	Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation; Director

108

SIGNATURES

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

February 28, 2013	By	/s/ J.T. McManus, II
	J.T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation; Director
February 28, 2013	By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation
February 28, 2013	By	/s/ Russell E. Lynch, Jr.
	Russell E. Lynch, Jr. Vice President and Controller of Energen Corporation
February 28, 2013	By	/s/ William D. Marshall
	William D. Marshall Vice President and Controller of Alabama Gas Corporation
February 28, 2013	*
	Julian W. Banton Director
February 28, 2013	*
	Kenneth W. Dewey Director
February 28, 2013	*
	Judy M. Merritt Director
February 28, 2013	*
	Stephen A. Snider Director
February 28, 2013	*
	David W. Wilson Director
	*By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr., Attorney-in-Fact

109

EX-10.R

Exhibit 10(r)

ENERGEN CORPORATION STOCK INCENTIVE PLAN

STOCK OPTION AGREEMENT

[Incentive Stock Option / Nonqualified Stock Option]

Dated as of ____________,_____

A stock option is hereby granted to the below named Participant. This option is granted under the Energen Corporation Stock Incentive Plan (“the Plan”), as amended, and is subject in all respects to the terms and provisions of the Plan which is incorporated herein by reference. Without limiting the generality of the foregoing, this option is subject to the exercise and transferability restrictions set forth in the Plan. Words defined in the Plan and used in this Agreement shall have the meanings set forth in the Plan. The attributes of this option are as follows:

1)	Incentive Stock Option:  This option is a[n] [ Incentive Stock Option / Nonqualified Stock Option ].
2)	Participant:    «Name»
3)	Shares subject to option:    «Shares»	4)	Grant Date:    ___________
5)	Exercise Price per share:    $_____	6)	Expiration Date:     ___________
7)	Vesting: The option shall become exercisable on [ 100% on a specified date / in increments on specified dates ]. Any exercisable portion of the option may be exercised in full or, from time to time, in increments of at least 100 shares.
8)	SARs: This option [ does / does not ] include stock appreciation rights (see Plan Section 6.2(i)), [but such stock appreciation rights are payable only in shares of stock, they are not payable in cash].
9)	Additional terms and conditions:    [ None / specified additional terms and conditions ].

ENERGEN CORPORATION	The Participant hereby accepts this option and agrees to accept as binding, conclusive, and and final all decisions and interpretations of the Committee and/or the Board, upon any questions arising under the Plan.
By:
Its:
	Participant - «Name»

EX-10.S

Exhibit 10(s)

ENERGEN CORPORATION STOCK INCENTIVE PLAN

RESTRICTED STOCK AGREEMENT

Dated as of _________,______

An Award of Restricted Stock is hereby granted to the below named Participant. This Award is granted under the Energen Corporation Stock Incentive Plan (“the Plan”), dated November 25, 1997, as amended, and is subject in all respects to the terms and provisions of the Plan which is incorporated herein by reference. Without limiting the generality of the foregoing, this Award is subject to the transferability restrictions and forfeiture provisions set forth in the Plan. Words defined in the Plan and used in this Agreement shall have the meanings set forth in the Plan. The attributes of this Award are as follows:

1)	Participant:    «Name»
2)	Number of Restricted Shares:    «Shares»
3)	Grant Date:    ______________
4)	Vesting: Restrictions on the Restricted Shares shall lapse [100% on specified date / in increments on specified dates].
5)	Additional terms and conditions:    [None / specified additional conditions].

ENERGEN CORPORATION

By

Its

The Participant hereby accepts this Restricted Stock Award and agrees to accept as binding, conclusive, and final all decisions and interpretations of the Committee and/or the Board, upon any questions arising under the Plan.

Participant - «Name»

EX-10.T

Exhibit 10(t)

ENERGEN CORPORATION STOCK INCENTIVE PLAN

PERFORMANCE SHARE AWARD

Dated as of _________,______

An Award of Performance Shares is hereby granted to the below named Participant. This Award is granted under the Energen Corporation Stock Incentive Plan (“the Plan”), dated November 25, 1997, as amended, and is subject in all respects to the terms and provisions of the Plan which is incorporated herein by reference. Without limiting the generality of the foregoing, this Award is subject to the transferability restrictions and forfeiture provisions set forth in the Plan. Words defined in the Plan and used in this Agreement shall have the meanings set forth in the Plan. The attributes of this Award are as follows:

1)	Participant:    «Name»
2)	Number of Performance Shares:    «Shares»
3)	Grant Date:    ______________
4)	Award Period:      ____________, ____ to __________, ____.
5)	Performance Conditions: The Award is subject to the following Performance Conditions:
6)	Additional terms and conditions:    [None / specified additional conditions].

ENERGEN CORPORATION

By

Its

The Participant hereby accepts this Performance Share Award and agrees to accept as binding, conclusive, and final all decisions and interpretations of the Committee and/or the Board, upon any questions arising under the Plan.

Participant - «Name»

EX-10.U

Exhibit 10(u)

ENERGEN CORPORATION

1997 DEFERRED COMPENSATION PLAN

As Amended December 12, 2012

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 1.1Definitions. 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 subsidiary of Energen Corporation.

(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.

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(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

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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.

(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

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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)“Officers Review Committee” means the 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.

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(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 2.1Eligibility. 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 2.2Participation 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

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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 2.3Recordkeeping 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 2.4Termination 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 2.5Separate 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 3.1Eligibility. 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 Officers Review 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 Officers Review 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 3.2Participation. 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

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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 3.3Suspension of Eligibility. The Officers Review 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 Officers Review 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 4.1Deferred 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;

(c)    Stock Incentive Plan awards;

(d)    Director Fees;

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

(f)    Such other compensation as the Officers Review 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 4.2Form and Effectiveness of Deferral Election. Elections to defer compensation under the Plan shall be made in writing on the Deferral Election Form. 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

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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 grant. 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 4.3Participant 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 Officers Review 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, 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 4.4Discretionary 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 Company Stock Account with additional amounts. Such additional amounts may be authorized for such purpose or purposes as the Board of Directors may deem appropriate.

ARTICLE V.

VESTING

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

Section 5.2Limitation 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.

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DISTRIBUTIONS.

Section 6.1Distributable 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 events (d) - (f) are subject to Section 6.6:

(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);

(c)    the Participant’s death;

(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), or

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

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 6.2Distribution 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.

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(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. 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 Officers Review 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 Officers Review 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.

Section 6.3Early Withdrawals. Notwithstanding any provision in this Plan to the contrary, a Participant may request, by providing a written request to the Officers Review Committee, a

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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 Officers Review Committee, which decision by the Officers Review 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 Officers Review 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 6.4Hardship 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 Officers Review 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 Officers Review Committee, which decision by the Officers Review 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 6.5Distributions 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 Officers Review 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 6.6No Parachute Payment. An event described in Sections 6.1(d), (e) and (f) shall not constitute a Distributable Event with respect to the portion of a Participant’s Accounts, if any, that the Officers Review Committee in its reasonable discretion following consultation with appropriate tax and/or legal advisors reasonably determines will likely constitute a parachute payment for purposes of Section 280G of the Code.

Section 6.7Distribution 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:

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(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 6.8Delay 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 7.1Company Stock Accounts.

(a)Unit Accounting. Subject to the authority of the Officers Review 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,

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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 7.2Investment 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 Officers Review 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 7.3Hypothetical 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 7.4Allocation 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 7.5Contribution Timing. Subject to the authority of the Officers Review Committee to approve a different schedule, deferred amounts of compensation otherwise payable

13

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 8.1Anti‑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 8.2Incompetent 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 8.3Designated 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 9.1Withholding. 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 Officers Review 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

14

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 10.1Voting 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 11.1Administrator. 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 Officers Review Committee or such other committee, person or persons as it deems necessary or appropriate for the administration and operation of the Plan.

Section 11.2Authority 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 11.3Operation 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

15

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, thenotice 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 protocolsthe 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 ofthe 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 theClaimant (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 11.4Participant’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.

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MISCELLANEOUS PROVISIONS

Section 12.1No 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 12.2Participants 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 12.3Unfunded 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 12.4The 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

17

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

Section 12.6Severability. 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 12.7Applicable 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 13.1Amendment 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 14.1Term 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.

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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.

19

EX-21

Exhibit 21

SUBSIDIARIES OF ENERGEN CORPORATION

Alabama Gas Corporation*

Energen Resources Corporation*

* Incorporated in the State of Alabama

EX-23.A

Exhibit 23(a)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-177815) and Forms S-8 (File No. 33-46641, File No. 333-104726, File No. 33-48505, File No. 333-26111, File No. 333-84170 and File No. 333-178794) of Energen Corporation of our report dated February 28, 2013 relating to the consolidated financial statements, financial statement schedule, and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 28, 2013

EX-23.B

Exhibit 23(b)

CONSENT

We hereby consent to the reference to our firm name and our audit of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2012 which appears in this Form 10-K and the inclusion of our report dated February 6, 2013, 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 Form S-3 (File No. 333-177815) and Forms S-8 (File No. 33-46641, File No. 333-104726, File No. 33-48505, File No. 333-26111, 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 natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2012 which appears in this Form 10-K and our report dated February 6, 2013, which appears as an Exhibit to this Form 10-K.

/s/ Ryder Scott Company, L.P.

Houston, Texas

February 28, 2013

EX-23.C

Exhibit 23(c)

CONSENT

We hereby consent to the reference to our firm name and our audit of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2012 which appears in this Form 10-K and the inclusion of our report dated January 25, 2013, 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 Form S-3 (File No. 333-177815) and Forms S-8 (File No. 33-46641, File No. 333-104726, File No. 33-48505, File No. 333-26111, 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 natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2012 which appears in this Form 10-K and our report dated January 25, 2013, which appears as an Exhibit to this Form 10-K.

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

Midland, Texas

February 28, 2013

EX-24

Exhibit 24

POWER OF ATTORNEY

ENERGEN CORPORATION

ALABAMA GAS CORPORATION

Each of the undersigned directors of Energen Corporation, an Alabama corporation, and Alabama Gas 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, 2012 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 and Alabama Gas Corporation have executed this Power of Attorney as of the 23^rd day of January, 2013.                            

/s/ Stephen D. Ban        

Stephen D. Ban

/s/ Julian W. Banton        

Julian W. Banton

/s/ Kenneth W. Dewey        

Kenneth W. Dewey

/s/ T. Michael Goodrich        

T. Michael Goodrich

/s/ Jay Grinney            

Jay Grinney

/s/ Frances Powell Hawes    

Frances Powell Hawes

/s/ Judy M. Merritt        

Judy M. Merritt

/s/ Stephen A. Snider        

Stephen A. Snider

/s/ David W. Wilson        

David W. Wilson

/s/ Gary C. Youngblood        

Gary C. Youngblood

EX-31.A

Exhibit 31(a)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

February 28, 2013	By	/s/ J. T. McManus, II
		J. T. McManus, II
		Chairman, Chief Executive Officer and President of Energen Corporation

EX-31.B

Exhibit 31(b)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

February 28, 2013	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation

EX-31.C

Exhibit 31(c)

CERTIFICATION

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

1. I have reviewed this report on Form 10-K of Alabama Gas 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.

February 28, 2013	By	/s/ J. T. McManus, II
		J. T. McManus, II
		Chairman and Chief Executive Officer of Alabama Gas Corporation

EX-31.D

Exhibit 31(d)

CERTIFICATION

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

1. I have reviewed this report on Form 10-K of Alabama Gas 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.

February 28, 2013	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Alabama Gas Corporation

EX-32.A

Exhibit 32(a)

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, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of February 28, 2013

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

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

EX-32.B

Exhibit 32(b)

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 Alabama Gas Corporation (the “Registrant”) on Form 10-K for the period ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of February 28, 2013

By	/s/ J. T. McManus, II
	J. T. McManus, II Chairman and Chief Executive Officer of Alabama Gas Corporation
By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Alabama Gas 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 Alabama Gas Corporation and will be retained by Alabama Gas Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.A

Exhibit 99(a)

ENERGEN RESOURCES CORPORATION

Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests

SEC Parameters

As of

December 31, 2012

\s\ Joseph E. Blankenship

Joseph E. Blankenship, P.E.

TBPE License No. 62093

Senior Vice President

[SEAL]

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

February 6, 2013

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, 2012 prepared by Energen’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on January 31, 2013 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, 2012. The properties reviewed by Ryder Scott incorporate 5639 reserve determinations and are located in the states of Alabama, 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, 2012. 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	92	74	85
Proved Developed	90	72	82
Proved Undeveloped	97	82	94

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

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

reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

Based on our review, including the data, technical processes and interpretations presented by Energen, it is our opinion that the overall procedures and methodologies utilized by Energen in preparing their estimates of the proved reserves as of December 31, 2012 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, 2012, they used average prices during the 12-month period prior to the ending date of the period covered in 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 are summarized as follows:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold and Royalty Interests of

Energen Resources Corporation

As of December 31, 2012

	Proved
	Developed			Total
	Producing	Non-Producing	Undeveloped	Proved
Net Reserves of Properties Audited by Ryder Scott
Oil/Condensate - Barrels	94,335,794	9,754,039	49,046,038	153,135,871
Plant Products - Barrels	21,106,460	2,592,477	18,250,771	41,949,708
Gas – MMCF	501,240	11,601	82,579	595,420
Total Equivalent Oil - BOE	198,982,267	14,279,991	81,059,906	294,322,164

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

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

Audit Data, Methodology, Procedure and Assumptions

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 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 2012, 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 2012. 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 and Black Warrior Basins. 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.

To estimate economically recoverable proved oil and gas reserves we consider many factors and assumptions 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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 ending date of the period covered in 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, 2012 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Energen for the geographic area reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

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

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

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$94.71/Bbl	$88.10/Bbl
	NGLs	WTI Cushing	$94.71/Bbl	$34.38/Bbl
	Gas	Henry Hub	$2.76/MMBTU	$2.65/0MCF
		Colorado Interstate	$2.57/MMBTU

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 included herein do not attribute gas consumed in operations as reserves.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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, 2012. 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, political or economic obstacles that would significantly alter their plans. All of Energen’s proved undeveloped reserves are scheduled to be developed within five years from the initial disclosure in an SEC filing.

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

Energen’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend had been established, future production rates were held constant, 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 detailed study 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, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Energen. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by Energen to be appropriate and sufficient for the purpose of our review of Energen’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Energen and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Energen, it is our opinion that the overall procedures and methodologies utilized by Energen in preparing their estimates of the proved reserves as of December 31, 2012 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.

We were in reasonable agreement with Energen's estimates of proved reserves for the properties which we reviewed. As a consequence, 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.

Standards of Independence and Professional Qualification

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Energen. Neither we nor any of our employees have any 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, 2012 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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

[SEAL]

JEB (FWZ)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Joseph E. Blankenship was the primary technical person responsible for overseeing the estimation and evaluation process with respect to the preparation of this report.

Mr. Blankenship, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1982, is 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/Experience/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 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 2012 included training 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.

In 2011, Mr. Blankenship attended classes on Professional Resource Planning, Microsoft Access Utilization in the Area of Reserves Evaluation, Fekete Reservoir Engineering Software Optimization and Utilization, and the Utilization of Correct SEC Reserves and PRMS Resource Evaluation Criteria.

In 2010, Mr. Blankenship presented 1hour of formalized training to the professional staff at Ryder Scott. Mr. Blankenship attended Ryder Scott’s 2010 Reserves Conference, which included a presentation by Dr. John Lee, on the New SEC Regulations Relating to the Definitions and Disclosure Guidelines Contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register; and Mr. Blankenship also attended a class on Deep Water Gulf of Mexico Reserves Evaluation.

Based on his educational background, professional training and more than 35 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 structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.

Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EX-99.B

Exhibit 99(b)

January 25, 2013

Energen Resources Corp.

605 Richard Arrington Jr Boulevard North

Birmingham, AL 35203-2707

Attention Mr. Henry E. Cash

Gentlemen:

Re: Reserve Audit

San Juan Basin, New Mexico (Conventional)

North Louisiana and East Texas

In accordance with your request, T. Scott Hickman & Associates, Inc. (TSH&A) has performed an audit of the Proved oil and gas reserves estimated by Energen Resources Corp. (ERC) from conventional formations for certain properties located in the San Juan Basin of New Mexico, north Louisiana and east Texas (herein referred to as "Subject Areas") in accordance with guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our audit was completed on January 25, 2013.

A reserve audit is the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or reserves information prepared by others and the rendering of an opinion about the methodologies, data and thoroughness of the process that was used, the reserve classification that was assigned and the reserve quantities that were estimated. This letter presents the results of our third party reserve audit based on the guidelines set forth under Section 229.1202(a)(7) and (8) of the SEC regulations. The estimated reserves shown in the following table represent ERC's estimated net Proved reserves attributable to the leasehold interests in certain properties owned by ERC as of December 31, 2012.

	ERC Net "Subject Areas" Audited Reserves
	Oil, MBBL	Gas, MMCF	NGL, MBL	Liquid Eq MBOE
Effective Date	- - - - - - - - - - - - December 31, 2012- - - - - - - - - - - -
Proved Developed
Producing	1,030.7	175,516.6	11,640.8	41,924.3
Nonproducing	0.0	468.8	24.3	102.4
Behind Pipe	0.0	5,812.1	464.7	1,433.4
Proved Undeveloped	24.8	17,500.9	1,372.1	4,313.7
TOTAL PROVED	1,055.5	199,298.4	13,501.9	47,773.8

Energen Resources Corp.

January 25, 2013

Page 2

The total proved reserves for the "Subject Areas" audited by Hickman represent approximately 13.8% of ERC's total proved reserves expressed in MBOE. The liquid reserves include crude oil, condensate and natural gas liquids expressed in standard 42 gallon barrels. Gas volumes are expressed in millions of standard cubic feet (MMCF) at contract temperature and pressure bases. Gas reserves are converted to oil equivalent using a factor of 6 mcf per barrel.

Proved oil and gas reserves are those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. Reserve estimations are based on industry-accepted principles of engineering and evaluation that are predicated on established scientific concepts. However, the application of such principles involves extensive judgment and assumptions and is subject to changes in performance data, existing technical knowledge, economic conditions and/or regulatory provisions. Consequently, reserve estimates are inherently uncertain and will normally require some revisions in the future, particularly on new wells with little production history and for reserve categories other than Proved Developed Producing. ERC's operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

Since reserves have to be economically recoverable, it is necessary to determine the producing rate below which producing operations are no longer profitable (economic limit). Determining the economic limit requires the application of oil and gas prices and operating cost data. The SEC regulations require the use of a constant price that is the unweighted arithmetic average of the first-day-of-the-month price for the twelve months prior to the reporting date, except where the price is based on a contractual arrangement. The product prices which were actually used by ERC to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering fees, and transportation fees referred to herein as "differentials." The differentials used by ERC were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by ERC.

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

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
Subject Areas:
	Oil/Condensate	WTI Cushing	$94.71/Bbl	$83.45/Bbl
	NGLs	Mt. Belvieu	$0.8755/Gal	$0.79/Gal
	Gas	Henry Hub	$2.757/MMBTU	$3.79/MCF

Energen Resources Corp.

January 25, 2013

Page 3

The lease./well operating costs used by ERC were the monthly averages for the most recent twelve month available prior to the reporting date. The operating costs included only expenses directly applicable to the lease/well plus general and administrative costs that were appropriate to allocate back to the lease/well. We spot checked operating costs to satisfy ourselves that they were calculated in a proper manner. In the economic calculations operating costs were held constant unless some scheduled change in operations dictated a change.

Because of the inherent uncertainties in determining reserve quantities, the reserves presented in this report are estimates only and should not be construed as exact quantities. The actual volumes of oil and gas recovered could be more or less than the estimate reserves. The reserves reviewed in this audit are to be produced under primary recovery from conventional formation within the Subject Areas. Our audit covered 46% of ERC's net Proved oil, NGL and gas reserves in the San Juan Basin, east Texas and north Louisiana.

We have accepted without independent verification the accuracy and completeness of the historical production and other data furnished by ERC with respect to ownership interest, oil and gas prices, historical costs of operation and development, and any agreements relating to current and future operations of the properties and sales of production. If, however, in the course of our audit something came to our attention which called into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto.

TSH&A has used all methods and procedures necessary to prepare this report including a detailed review of major properties constituting approximately 70% of the total Proved Developed Producing conventional reserves estimated by ERC in the Subject Areas as of December 31, 2012. A review of the Proved Developed Nonproducing, Proved Developed Behind Pipe and Proved Undeveloped reserves was conducted with ERC's engineers and geologists. This nonproducing/ undeveloped review covered not only the reserve estimations and development costs, but for the undeveloped locations the certainty that they would be drilled in the near future. Drilling schedules, budgets and ERC's recent history of drilling proposed locations were investigated. No PUD locations were included in ERC's December 31, 2012 reported reserves that were not scheduled to be drilled within five years. All of the files and records for the leases/wells in the Subject Areas were available for our use. Performance and available plant accounting data were initially available through July 2012 at the start of our audit. Specific leases/wells performance data were updated as our review progressed.

In general the reserves we reviewed were estimated by decline curve analysis whereby historical performance data (producing rates and pressures) are extrapolated when such data were deemed to be definitive. When performance data was not definitive or little or no performance history was available, reserve estimate were based on analogous well performance and occasionally by volumetric methods. Nonproducing and undeveloped reserves estimates were based on analogy and volumetrics.

We are qualified to perform engineering evaluations and audits, but do not claim any expertise in accounting or legal matters. As is customary in the profession, no field inspection was made of the properties nor have we verified that all operations are in compliance with state and/or federal conservation, pricing and environmental regulations that may apply. No consideration was given to potential environmental liabilities that may exist. It is our understanding that ERC's estimates of reserves do not include adjustments for settlement of any potential gas volume and value imbalances which may have resulted from over- or under-production to ERC's interest. We have not attempted to identify any interest revisions that might exist.

Energen Resources Corp.

January 25, 2013

Page 4

It is our opinion ERC's estimate of net Proved reserve quantities in the "Subject Areas" were prepared in accordance with generally accepted petroleum engineering and evaluation principles as set forth in the 2007 Petroleum Resources Management System sponsored by the SPE, WPC, AAPG and SPEE. TSH&A is satisfied that the assumptions, methods, data and procedures utilized by ERC in the preparation of the reserve estimates are appropriate and that ERC's reserve classifications conform to the SEC reserve definitions contained in 210.4-10(a).

In the aggregate the overall proved reserves estimated by ERC in the Subject Areas are reasonable within the audit tolerance guidelines of 10 percent as set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers (SPE audit guidelines). Therefore it is our opinion that reserves set forth in this report fairly reflect the estimated net Proven reserves owned by the ERC in the Subject Areas.

TSH&A has been providing reserve estimation and evaluation services to industry and investment community for 39 years. All of the Company's engineers are qualified by education, training and experience as Reserves Estimators and Reserves Auditors under the SPE audit guidelines. Each Engineer has at least 25 years of experience as a reserve evaluator. They are all registered engineers and complete a minimum of 15 hours of continuing education annually.

We are independent petroleum engineers with respect to ERC as provided in the SPE audit guidelines. We do not own an interest in any of the audited properties and are not employed on a contingency basis.

ERC is a wholly owned subsidiary of Energen Corporation. Energen Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Energen Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Energen Corporation, which appears in the December 31, 2012 annual report on Form 10-K of Energen Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Energen Corporation.

Yours very truly,

T. SCOTT HICKMAN & ASSOCIATES, INC.

TBPE Firm Registration No. F-106

/s/ J. Louis Moseley

J. Louis Moseley, P.E.

TBPE License No. 32305

XML

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Cash Flow Information [Line Items]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

Supplemental information concerning Energen's cash flow activities was as follows:

Years ended December 31, (in thousands)	2012		2011		2010
Interest paid, net of amount capitalized	$	61,379	$	33,601	$	37,517
Income taxes paid	$	17,170	$	9,432	$	83,894
Noncash investing activities:
Accrued development, exploration costs and other capital	$	120,024	$	72,030	$	75,167
Capitalized depreciation	$	80	$	93	$	116
Capitalized asset retirement obligations costs	$	4,409	$	4,927	$	4,194
Allowance for funds used during construction	$	623	$	807	$	808
Capital lease obligations	$	5,072	$	—	$	—
Noncash financing activities:
Issuance of common stock for employee benefit plans	$	838	$	822	$	5,765
Treasury stock acquired in connection with tax withholdings	$	277	$	713	$	2,894

Alabama Gas Corporation

Supplemental Cash Flow Information [Line Items]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

Supplemental information concerning Alagasco's cash flow activities was as follows:

Years ended December 31, (in thousands)	2012		2011		2010
Interest paid, net of amount capitalized	$	13,513	$	12,385	$	11,653
Income taxes paid	$	16,796	$	5,143	$	13,063
Interest on affiliated company debt, net	$	295	$	376	$	274
Noncash investing activities:
Accrued property, plant and equipment costs	$	3,536	$	2,229	$	2,592
Capitalized depreciation	$	80	$	93	$	116
Capitalized asset retirement obligations costs	$	415	$	300	$	161
Allowance for funds used during construction	$	623	$	807	$	808

XML

Long-Term Debt and Notes Payable (Lines of Credit) (Details) (USD $)			12 Months Ended		0 Months Ended		12 Months Ended			0 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Energen Corporation	Dec. 31, 2011 Energen Corporation	Oct. 30, 2012 Energen Corporation Syndicated Credit Facility	Oct. 29, 2010 Energen Corporation Syndicated Credit Facility	Dec. 31, 2012 Alabama Gas Corporation	Dec. 31, 2011 Alabama Gas Corporation	Dec. 31, 2012 Alabama Gas Corporation APSC Authorized Short-term Line of Credit	Oct. 30, 2012 Alabama Gas Corporation Syndicated Credit Facility	Oct. 29, 2010 Alabama Gas Corporation Syndicated Credit Facility
Line of Credit Facility [Line Items]
Maximum consolidated debt to capitalization ratio	65.00%						65.00%
Cross default provision, minimum debt default amount	$ 50,000,000						$ 50,000,000
Line of Credit Facility [Abstract]
Credit facilities	1,350,000,000	1,019,000,000			1,250,000,000	850,000,000				100,000,000	150,000,000
Credit facilities term (in years)					5 years	3 years				5 years	3 years
Short-term line of credit, authorization to borrow									200,000,000
Notes payable to banks	643,000,000	15,000,000	566,000,000	0			77,000,000	15,000,000
Available for borrowings	707,000,000	1,004,000,000
Maximum amount outstanding at any month-end			643,000,000	363,000,000			77,000,000	70,000,000
Average daily amount outstanding			$ 331,068,000	$ 229,094,000			$ 21,254,000	$ 29,268,000
Average daily amount outstanding, weighted average interest rates			1.82%	2.04%			1.44%	1.72%
Amount outstnding at year-end, weighted average interest rates			1.35%	3.57%			1.11%	3.57%

XML

Summary of Significant Accounting Policies (Cash Equivalents, Short-term Investments, and Stock-Based Compensation) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash equivalent, maturity period	3 months
Reclassification of Outstanding Checks, Effect on Cash and Cash Equivalents		$ 8.0
Reclassification of Outstanding Checks, Effect on Accounts Payable		7.3
Reclassification of Outstanding Checks, Effect on Accounts Receivable		0.7
Decrease in operating cash flows	(8.0)
Excess tax benefit from share-based compensation	0.6	1.0
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Short-term investments, maturity period	3 months
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Short-term investments, maturity period	1 year
Alabama Gas Corporation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Reclassification of Outstanding Checks, Effect on Cash and Cash Equivalents		6.8
Reclassification of Outstanding Checks, Effect on Accounts Payable		6.1
Reclassification of Outstanding Checks, Effect on Accounts Receivable		0.7
Decrease in operating cash flows	$ 6.8

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Common Stock Plans (Stock Options) (Details) (Stock Incentive Plan, USD $)	0 Months Ended			12 Months Ended
	Jan. 25, 2012	Jan. 26, 2011	Jan. 27, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Remaining reserved for issuance				3,418,881
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, vesting period				3 years
Share-based compensation, expiration period				10 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, Beginning of Period, Shares				1,338,241	1,276,043	1,107,809
Outstanding, Beginning of Period, Weighted Average Exercise Price				$ 44.77	$ 40.16	$ 36.83
Granted, Shares	371,040	293,978	281,110	371,040	293,978	281,110
Granted				$ 54.11	$ 54.99	$ 46.69
Exercised, Shares				(58,471)	(227,405)	(111,676)
Exercised, Weighted Average Exercise Price				$ 24.55	$ 32.33	$ 23.83
Forfeited, Shares				(2,335)	(4,375)	(1,200)
Forfeited, Weighted Average Exercise Price				$ 46.45	$ 35.35	$ 13.72
Outstanding, End of Period, Shares				1,648,475	1,338,241	1,276,043
Outstanding, End of Period, Weighted Average Exercise Price				$ 47.58	$ 44.77	$ 40.16
Exercisable, Shares				987,733	677,753	574,992
Exercisable, Weighted Average Exercise Price				$ 43.75	$ 43.72	$ 41.16
Remaining reserved for issuance				3,418,881

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Income Taxes (Components of Income Taxes) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Taxes estimated to be payable currently:
Federal	$ 16,295	$ 11,595	$ 31,920
State	3,125	5,065	1,230
Total current	19,420	16,660	33,150
Taxes deferred:
Federal	119,053	125,622	121,804
State	5,346	3,419	12,036
Total deferred	124,399	129,041	133,840
Total income tax expense	143,819	145,701	166,990
Alabama Gas Corporation
Taxes estimated to be payable currently:
Federal	18,227	(1,280)	859
State	739	(108)	155
Total current	18,966	(1,388)	1,014
Taxes deferred:
Federal	9,066	24,938	25,582
State	2,212	3,120	3,279
Total deferred	11,278	28,058	28,861
Total income tax expense	$ 30,244	$ 26,670	$ 29,875

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Commitments and Contingencies (Commitments and Agreements) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Long-term Purchase Commitment [Line Items]
Number of agreements to secure drilling rigs	3
Agreement Termination
Long-term Purchase Commitment [Line Items]
Possible resulting exposure form discontinue use of drilling rigs	$ 21.9
Crude Oil
Long-term Purchase Commitment [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume	33.4
Alabama Gas Corporation | Natural Gas, Delivery and Storage
Long-term Purchase Commitment [Line Items]
Long-term contracts, amount	59
Long-term contract, period end	September 2024
Long-term contracts expense recognized in financial statements	$ 51	$ 51	$ 52
Alabama Gas Corporation | Natural Gas
Long-term Purchase Commitment [Line Items]
Long-term contract, period end	August 2020
Long-term contracts, minimum quantity commitments	171

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Industry Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012 segment	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information
Number of business segments									2
Segment Reporting Information, Profit (Loss)
Operating revenues	$ 433,046	$ 295,324	$ 470,355	$ 418,444	$ 288,148	$ 378,568	$ 330,399	$ 486,364	$ 1,617,169	$ 1,483,479	$ 1,578,534
Operating Income (Loss)	115,166	19,458	220,598	104,170	31,641	150,412	106,335	159,881	459,392	448,269	493,377
Depreciation, depletion and amortization expense									419,598	283,997	247,865
Interest expense									65,556	44,822	39,222
Income tax expense (benefit)									143,819	145,701	166,990
Captial expenditures									1,363,080	1,189,436	811,348
Identifiable assets	6,175,890				5,237,416				6,175,890	5,237,416	4,363,560
Property, plant and equipment, net	5,541,636				4,620,776				5,541,636	4,620,776	3,719,227
Oil and Gas Operations
Segment Reporting Information, Profit (Loss)
Operating revenues									1,165,580	948,526	958,762
Operating Income (Loss)									367,243	363,131	406,729
Depreciation, depletion and amortization expense									377,328	244,081	203,823
Interest expense									49,972	30,907	25,753
Income tax expense (benefit)									114,375	120,079	138,775
Captial expenditures									1,291,211	1,115,452	717,782
Identifiable assets	4,975,170				4,046,242				4,975,170	4,046,242	3,160,601
Property, plant and equipment, net	4,697,683				3,806,787				4,697,683	3,806,787	2,936,284
Natural Gas Distribution
Segment Reporting Information, Profit (Loss)
Operating revenues									451,589	534,953	619,772
Operating Income (Loss)									93,216	86,216	88,383
Depreciation, depletion and amortization expense									42,270	39,916	44,042
Interest expense									16,284	14,740	13,894
Income tax expense (benefit)									30,244	26,670	29,875
Captial expenditures									71,869	73,984	93,566
Identifiable assets	1,177,134				1,163,959				1,177,134	1,163,959	1,166,899
Property, plant and equipment, net	842,685				813,471				842,685	813,471	782,665
Eliminations and other
Segment Reporting Information, Profit (Loss)
Operating Income (Loss)									(1,067)	(1,078)	(1,735)
Interest expense									(700)	(825)	(425)
Income tax expense (benefit)									(800)	(1,048)	(1,660)
Identifiable assets	23,586				27,215				23,586	27,215	36,060
Property, plant and equipment, net	$ 1,268				$ 518				$ 1,268	$ 518	$ 278

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Summary of Significant Accounting Policies (Utility Plant and Depreciation) (Details) (USD $)						12 Months Ended		1 Months Ended	12 Months Ended		0 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Refundable negative salvage	Dec. 31, 2012 Alabama Gas Corporation	Dec. 31, 2011 Alabama Gas Corporation	Dec. 31, 2012 Alabama Gas Corporation Refundable negative salvage	Dec. 31, 2011 Alabama Gas Corporation Refundable negative salvage	Dec. 31, 2010 Alabama Gas Corporation Refundable negative salvage Reduction in Tariff Rates	Dec. 31, 2012 Alabama Gas Corporation Refundable negative salvage Reduction in Tariff Rates	Dec. 31, 2011 Alabama Gas Corporation Refundable negative salvage Reduction in Tariff Rates	Jun. 01, 2010 Alabama Gas Corporation APSC Approved Reduction in Depreciation Rates, June 1, 2010	Dec. 31, 2011 Alabama Gas Corporation APSC Approved Reduction in Depreciation Rates, June 1, 2010	Dec. 31, 2010 Alabama Gas Corporation APSC Approved Reduction in Depreciation Rates, June 1, 2010	Dec. 31, 2012 Alabama Gas Corporation Depreciation Rate, Prior to APSC Approved Reduction, June 1, 2010	Dec. 31, 2011 Alabama Gas Corporation Depreciation Rate, Prior to APSC Approved Reduction, June 1, 2010	Dec. 31, 2010 Alabama Gas Corporation Depreciation Rate, Prior to APSC Approved Reduction, June 1, 2010
Property, Plant and Equipment [Line Items]
Composite depreciation rate											3.10%			3.20%	3.10%	3.60%
Refunded negative salvage costs								$ 2,700,000	$ 14,200,000	$ 22,200,000	$ 25,600,000
Regulatory Liability, Current	45,116,000	58,279,000	18,300,000	45,116,000	58,279,000	18,265,000	20,269,000
Regulatory Liability, Noncurrent	80,404,000	87,234,000	53,500,000	80,404,000	87,234,000	53,467,000	65,646,000
Refundable negative salvage costs, term						7 years
Total amount refundable to customers, term						9 years
Decrease in depreciation expense												6,800,000	9,200,000
Gas imbalances					$ 500,000

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

Defined Benefit Plan Disclosure [Line Items]

Schedule of benefit obligations

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 the Company’s consolidated financial statements:

As of December 31, (in thousands)	2012			2011			2012			2011
	Pension						Postretirement Benefits
Accumulated benefit obligation	$	269,101		$	211,896
Benefit obligation:
Balance at beginning of period	$	250,619		$	233,772		$	88,064		$	83,748
Service cost	10,527			9,173			1,853			1,769
Interest cost	10,801			10,960			4,248			4,443
Actuarial (gain) loss	65,048			17,024			(5,413		)	1,858
Plan amendments	—			(169		)	—			—
Termination benefit charge	—			414			—			—
Retiree drug subsidy program	—			—			360			302
Benefits paid	(13,455		)	(20,555		)	(3,327		)	(4,056		)
Balance at end of period	$	323,540		$	250,619		$	85,785		$	88,064
Plan assets:
Fair value of plan assets at beginning of period	$	195,659		$	212,454		$	78,121		$	80,118
Actual return (loss) on plan assets	24,841			1,485			8,778			(1,653		)
Employer contributions	2,379			2,275			3,617			3,712
Benefits paid	(13,455		)	(20,555		)	(3,327		)	(4,056		)
Fair value of plan assets at end of period	$	209,424		$	195,659		$	87,189		$	78,121
Funded status of plan	$	(114,116	)	$	(54,960	)	$	1,404		$	(9,943	)
Noncurrent assets	$	—		$	—		$	1,404		$	—
Current liabilities	(3,834		)	(2,371		)	—			—
Noncurrent liabilities	(110,282		)	(52,589		)	—			(9,943		)
Net asset (liability) recognized	$	(114,116	)	$	(54,960	)	$	1,404		$	(9,943	)
Amounts recognized to accumulated other comprehensive income:
Prior service costs, net of taxes	$	528		$	749		$	—		$	—
Net actuarial (gain) loss, net of taxes	52,472			36,976			(715		)	451
Transition obligation, net of taxes	—			—			222			408
Total accumulated other comprehensive income (loss)	$	53,000		$	37,725		$	(493	)	$	859

Schedule of allocation of plan assets

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

	Pension						Postretirement Benefits
As of December 31,	Target		2012		2011		Target		2012		2011
Asset category:
Equity securities	41	%	41	%	39	%	60	%	60	%	60	%
Debt securities	38	%	38	%	40	%	40	%	40	%	40	%
Other	21	%	21	%	21	%	—	%	—	%	—	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

Schedule of net periodic benefit cost

The components of net periodic benefit cost were:

Years ended December 31, (in thousands)	2012			2011			2010
Pension Plans
Components of net periodic benefit cost:
Service cost	$	10,527		$	9,173		$	8,574
Interest cost	10,801			10,960			11,365
Expected long-term return on assets	(14,093		)	(15,471		)	(12,915		)
Prior service cost amortization	517			496			496
Actuarial loss amortization	8,603			6,435			5,773
Termination benefit charge	—			414			—
Net periodic expense	$	16,355		$	12,007		$	13,293
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	1,853		$	1,769		$	2,064
Interest cost	4,248			4,443			4,833
Expected long-term return on assets	(4,438		)	(4,418		)	(3,986		)
Actuarial loss amortization	37			—			—
Transition obligation amortization	1,917			1,917			1,917
Net periodic expense	$	3,617		$	3,711		$	4,828

Schedule of other changes in plan assets and projected benefit obligations recognized in other comprehensive income

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

Years ended December 31, (in thousands)	2012			2011			2010
Pension Plans
Net actuarial loss experienced during the year	$	28,748		$	14,312		$	4,332
Net actuarial loss recognized as expense	(4,908		)	(3,755		)	(3,290		)
Prior service cost recognized as expense	(340		)	(298		)	(298		)
Total recognized in other comprehensive income	23,500			10,259			744
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	(1,787	)	$	2,111		$	(2,094	)
Transition obligation recognized as expense	(294		)	(286		)	(280		)
Total recognized in other comprehensive income (loss)	$	(2,081	)	$	1,825		$	(2,374	)

Schedule of estimated amount to be amortized from accumulated other comprehensive income

Estimated amounts to be amortized from accumulated other comprehensive income into pension cost during 2013 are as follows:

(in thousands)
Amortization of prior service cost	$	313
Amortization of net actuarial loss	$	8,591

Estimated amounts to be amortized from accumulated other comprehensive income into benefit cost during 2013 are as follows:

(in thousands)
Amortization of transition obligation	$	264

Schedule of weighted average rate assumptions

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

Years ended December 31,	2012		2011		2010
Pension Plans
Discount rate	4.52	%	4.89	%	5.49	%
Expected long-term return on plan assets	7.00	%	7.25	%	7.25	%
Rate of compensation increase for pay-related plans	3.59	%	3.75	%	3.95	%
Postretirement Benefit Plans
Discount rate	4.95	%	5.45	%	5.90	%
Expected long-term return on plan assets	7.00	%	7.25	%	7.25	%
Rate of compensation increase	3.55	%	3.61	%	3.69	%

The weighted average rate assumptions used to determine the projected benefit obligations at the measurement date were as follows:

Years ended December 31,	2012		2011
Pension Plans
Discount rate	3.47	%	4.52	%
Rate of compensation increase for pay-related plans	3.71	%	3.59	%
Postretirement Benefit Plans
Discount rate	4.15	%	4.95	%
Rate of compensation increase for pay-related plans	3.70	%	3.55	%

Schedule of assumed post-65 health care cost rend rates

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

As of December 31,	2012		2011
Health care cost trend rate assumed for next year	6.75	%	7.00	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2020		2020

Schedule of effect of 1 percentage point change in assumed health care cost trend rates

Assumed health care cost trend rates used in determining the accumulated postretirement benefit obligation have an effect on the amounts reported. For example, revising the weighted average health care cost trend rate by 1 percentage point would have the following effects:

(in thousands)
	1-Percentage Point Decrease			1-Percentage Point Increase
Effect on total of service and interest cost	$	(381	)	$	456
Effect on net postretirement benefit obligation	$	(3,688	)	$	4,342

Schedule of expected benefit payments

The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows. In addition, the following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy which began in 2007:

(in thousands)	Pension Benefits	Postretirement Benefits	Postretirement Benefits – Prescription Drug Subsidy
2013	$20,354	$4,435	$(243)
2014	$20,982	$4,586	$(248)
2015	$21,679	$4,754	$(252)
2016	$23,155	$4,940	$(258)
2017	$28,139	$5,165	$(260)
2018-2022	$166,646	$28,565	$(1,333)

Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Schedule of allocation of plan assets

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

	December 31, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
United States equities	$	41,907	$	9,072	$	—	$	50,979
Global equities	23,782		10,697		—		34,479
Fixed income	—		78,806		—		78,806
Alternative investments	—		27,659		14,500		42,159
Cash and cash equivalents	—		3,001		—		3,001
Total	$	65,689	$	129,235	$	14,500	$	209,424
	December 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
United States equities	$	37,009	$	8,916	$	—	$	45,925
Global equities	20,064		4,914		4,352		29,330
Fixed income	—		78,443		—		78,443
Alternative investments	—		26,070		13,047		39,117
Cash and cash equivalents	—		2,844		—		2,844
Total	$	57,073	$	121,187	$	17,399	$	195,659

Schedule of reconciliation of plan assets in Level 3 of fair value hierarchy

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

Years ended December 31, (in thousands)	2012			2011
Balance at beginning of period	$	17,399		$	26,841
Unrealized gains (losses)	992			(752		)
Unrealized gains relating to instruments held at the reporting date	242			635
Settlements	(4,948		)	(9,604		)
Purchases	815			279
Balance at end of period	$	14,500		$	17,399

Postretirement Benefit Plans

Defined Benefit Plan Disclosure [Line Items]

Schedule of allocation of plan assets

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

	December 31, 2012
(in thousands)	Level 1		Level 2		Total
United States equities	$	37,482	$	—	$	37,482
Global equities	15,049		—		15,049
Fixed income	—		34,658		34,658
Total	$	52,531	$	34,658	$	87,189

	December 31, 2011
(in thousands)	Level 1		Level 2		Total
United States equities	$	33,649	$	—	$	33,649
Global equities	13,088		—		13,088
Fixed income	—		31,384		31,384
Total	$	46,737	$	31,384	$	78,121

Nonqualified Supplemental Retirement Plans

Defined Benefit Plan Disclosure [Line Items]

Schedule of allocation of plan assets

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

	December 31, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
Insurance contracts	$	—	$	7,399	$	5,600	$	12,999
United States equities	4,741		—		—		4,741
Global equities	2,109		—		—		2,109
Fixed income	—		10,219		—		10,219
Total	$	6,850	$	17,618	$	5,600	$	30,068

	December 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
Insurance contracts	$	—	$	6,620	$	5,332	$	11,952
United States equities	4,546		—		—		4,546
Global equities	1,798		—		—		1,798
Fixed income	—		9,454		—		9,454
Total	$	6,344	$	16,074	$	5,332	$	27,750

Schedule of reconciliation of plan assets in Level 3 of fair value hierarchy

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

Years ended December 31, (in thousands)	2012		2011
Balance at beginning of period	$	5,332	$	5,069
Unrealized gains relating to instruments held at the reporting date	268		263
Balance at end of period	$	5,600	$	5,332

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Commitments and Contingencies (Environmental Matters) (Details) (Alabama Gas Corporation, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 site
Site Contingency [Line Items]
Chain of title, manufactured gas plant sites	9
Chain of title, manufactured gas distribution sites	5
Cost incurred, environmental redediation	$ 5
Sites owned by Alagasco
Site Contingency [Line Items]
Chain of title, manufactured gas plant sites	4
Chain of title, manufactured gas distribution sites	1

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Common Stock Plans (Stock Options, Range of Exercise Prices) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of exercisable options, Weighted Average Remaining Contractual Life (in years)	5 years 9 months 5 days
Stock options | Stock Incentive Plan
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices, Lower Range Limit	14.86
Number of outstanding options, Range of Exercise Prices, Upper Range Limit	60.56
Number of outstanding options, Shares	1,648,475
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	6 years 9 months 29 days
Stock options | Stock Incentive Plan | $14.86
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices	14.86
Number of outstanding options, Shares	16,270
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	29 days
Stock options | Stock Incentive Plan | $21.38
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices	21.38
Number of outstanding options, Shares	5,560
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	1 year 0 months 29 days
Stock options | Stock Incentive Plan | $46.45
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices	46.45
Number of outstanding options, Shares	150,710
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	4 years
Stock options | Stock Incentive Plan | $55.08
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices	55.08
Number of outstanding options, Shares	7,260
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	4 years 6 months
Stock options | Stock Incentive Plan | $60.56
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices	60.56
Number of outstanding options, Shares	184,565
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	5 years
Stock options | Stock Incentive Plan | $29.79
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices	29.79
Number of outstanding options, Shares	333,232
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	6 years
Stock options | Stock Incentive Plan | $43.30
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices	43.30
Number of outstanding options, Shares	4,750
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	6 years 8 months 1 day
Stock options | Stock Incentive Plan | $46.69
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices	46.69
Number of outstanding options, Shares	281,110
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	7 years
Stock options | Stock Incentive Plan | $54.99
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices	54.99
Number of outstanding options, Shares	293,978
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	8 years
Stock options | Stock Incentive Plan | $54.11
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Number of outstanding options, Range of Exercise Prices	54.11
Number of outstanding options, Shares	371,040
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	9 years

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Financial Instruments and Risk Management (Level 3 Fair Value Measurements of Derivative Commodity Instruments) (Details) (Level 3, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Natural Gas | San Juan Basin | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value (in USD)	$ 38,254
Natural Gas | San Juan Basin | 2014
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value (in USD)	21,100
Natural Gas | Permian Basin | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value (in USD)	0
Natural Gas | Permian Basin | 2014
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value (in USD)	(1)
Crude Oil | WTS/WTI Basis Swaps | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value (in USD)	10,338
Crude Oil | WTI/WTI Basis Swaps | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value (in USD)	8,217
Natural Gas Liquids | Liquids Swaps | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Net derivative asset (liability), at fair value (in USD)	$ 11,821
Discounted Cash Flow Valuation Technique [Member] | Minimum | Natural Gas | San Juan Basin | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	(0.15)	[1]
Discounted Cash Flow Valuation Technique [Member] | Minimum | Natural Gas | San Juan Basin | 2014
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	(0.13)	[1]
Discounted Cash Flow Valuation Technique [Member] | Minimum | Natural Gas | Permian Basin | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	(0.13)	[1]
Discounted Cash Flow Valuation Technique [Member] | Minimum | Natural Gas | Permian Basin | 2014
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	(0.12)	[1]
Discounted Cash Flow Valuation Technique [Member] | Minimum | Crude Oil | WTS/WTI Basis Swaps | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per bbl)	(5.19)	[1]
Discounted Cash Flow Valuation Technique [Member] | Minimum | Crude Oil | WTI/WTI Basis Swaps | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per bbl)	(2.92)	[1]
Discounted Cash Flow Valuation Technique [Member] | Minimum | Natural Gas Liquids | Liquids Swaps | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per gal)	0.73	[1]
Discounted Cash Flow Valuation Technique [Member] | Maximum | Natural Gas | San Juan Basin | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	(0.16)	[1]
Discounted Cash Flow Valuation Technique [Member] | Maximum | Natural Gas | San Juan Basin | 2014
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	(0.17)	[1]
Discounted Cash Flow Valuation Technique [Member] | Maximum | Natural Gas | Permian Basin | 2014
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	(0.13)	[1]
Discounted Cash Flow Valuation Technique [Member] | Maximum | Crude Oil | WTI/WTI Basis Swaps | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per bbl)	(3.62)	[1]
Discounted Cash Flow Valuation Technique [Member] | Maximum | Natural Gas Liquids | Liquids Swaps | 2013
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair value inputs, derivative, nonmonetary notional amount (USD per gal)	0.82	[1]

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

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Income Taxes (Effective Income Tax Rate Reconciliation) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Disclosure [Line Items]
Statutory federal income tax rate	35.00%	35.00%	35.00%
Income tax expense at statutory federal income tax rate	$ 139,083	$ 141,864	$ 160,229
State income taxes, net of federal income tax benefit	4,904	5,544	8,398
Qualified Section 199 production activities deduction	(94)	(593)	(1,745)
401(k) stock dividend deduction	(514)	(532)	(565)
Other, net	440	(582)	673
Total income tax expense	143,819	145,701	166,990
Effective income tax rate (%)	36.19%	35.95%	36.48%
Alabama Gas Corporation
Income Tax Disclosure [Line Items]
Statutory federal income tax rate	35.00%	35.00%	35.00%
Income tax expense at statutory federal income tax rate	27,876	25,645	26,865
State income taxes, net of federal income tax benefit	2,238	2,059	2,157
Reversal of tax reserves from audit settlements, net	0	(1,365)	0
Other, net	130	331	853
Total income tax expense	$ 30,244	$ 26,670	$ 29,875
Effective income tax rate (%)	37.97%	36.40%	38.92%

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Common Stock Plans (Other Plans) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012
Stock Equivalent Units | Petrotech Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding, Beginning of Period, Shares	11,061	8,205	32,350	141,243
Exercised/forfeited, Shares	(3,281)	(1,914)	(26,587)
Forfeited	(13,476)	(1,544)
Share-based compensation expense	$ 2.6	$ 0.2	$ 0.2
Stock Equivalent Units | Petrotech Incentive Plan | Three years vesting period
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted	102,349	6,314	2,442
Share-based compensation, vesting period	3 years
Stock Equivalent Units | Petrotech Incentive Plan | Two years vesting period
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted	3,768
Share-based compensation, vesting period	2 years
Stock Equivalent Units | Petrotech Incentive Plan | 18-months vesting period
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted	40,822
Share-based compensation, vesting period	18 months
Management | 1997 Deferred Compensation Plan
Deferred Compensation Arrangements [Abstract]
Deferred compensation, reserved for issuance	701,348			701,348
Director | Stock options | 1992 Energen Corporation Directors Stock Plan
Deferred Compensation Arrangements [Abstract]
Granted, Shares	11,120	12,420	15,400
Number of shares remaining for issuance	151,784

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Financial Instruments and Risk Management (Derivative Instruments, Fair Value) (Details) (USD $)	Dec. 31, 2012		Dec. 31, 2011
Derivative [Line Items]
Noncurrent assets	$ 40,577,000		$ 31,056,000
Noncurrent liabilities	(11,305,000)		(34,663,000)
Expected change in fair value of open Level 3 derviated contracts	27,000,000
Resulting impact upon the results of operations associated with open Level 3 mark-to-market derivative contracts	2,500,000
Fair Value, Measurements, Recurring
Derivative [Line Items]
Current assets	64,792,000		21,792,000
Noncurrent assets	40,577,000		31,056,000
Current liabilities	(2,593,000)		(107,290,000)
Noncurrent liabilities	(9,600,000)		(34,378,000)
Net derivative asset (liability)	93,176,000		(88,820,000)
Level 2 | Fair Value, Measurements, Recurring
Derivative [Line Items]
Current assets	(3,629,000)	[1]	(14,843,000)	[1]
Noncurrent assets	18,899,000	[1]	(8,382,000)	[1]
Current liabilities	(2,593,000)	[1]	(98,468,000)	[1]
Noncurrent liabilities	(8,520,000)	[1]	(32,928,000)	[1]
Net derivative asset (liability)	4,157,000	[1]	(154,621,000)	[1]
Level 3 | Fair Value, Measurements, Recurring
Derivative [Line Items]
Current assets	68,421,000	[1]	36,635,000	[1]
Noncurrent assets	21,678,000	[1]	39,438,000	[1]
Current liabilities	0	[1]	(8,822,000)	[1]
Noncurrent liabilities	(1,080,000)	[1]	(1,450,000)	[1]
Net derivative asset (liability)	89,019,000	[1]	65,801,000	[1]
Alabama Gas Corporation
Derivative [Line Items]
Noncurrent liabilities	0		(3,070,000)
Alabama Gas Corporation | Level 2 | Fair Value, Measurements, Recurring
Derivative [Line Items]
Current liabilities	(2,600,000)		(56,800,000)
Noncurrent liabilities			$ (3,100,000)

[1] Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

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Commitments and Contingencies (Lease Obligations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Leased Assets [Line Items]
Total lease payments	$ 20,900,000	$ 19,100,000	$ 18,600,000
Operating Leases, Future Minimum Payments Due [Abstract]
2013	5,144,000
2014	4,836,000
2015	4,506,000
2016	4,141,000
2017	3,980,000
2018 and thereafter	13,046,000
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2013	1,743,000
2014	1,743,000
2015	145,000
Total minimum lease payments	3,631,000
Less amount representing interest	54,000
Total present value of minimum lease payments	3,577,000
Alabama Gas Corporation
Operating Leased Assets [Line Items]
Leasing term	25 years
Total lease payments	2,100,000	2,300,000	2,100,000
Lease expense paid by parent company	1,000,000
Operating Leases, Future Minimum Payments Due [Abstract]
2013	3,629,000
2014	3,858,000
2015	3,909,000
2016	3,934,000
2017	3,980,000
2018 and thereafter	13,046,000
Alabama Gas Corporation | Company's headquarters
Operating Leased Assets [Line Items]
Payments associated with leasing of Company's headquarters	$ 17,600,000

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Financial Instruments and Risk Management (Derivative Instruments Change in Fair Value of Level 3) (Details) (Derivative Commodity Instruments, USD $)	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Derivative Commodity Instruments
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	$ 65,801,000		$ 42,755,000		$ 64,517,000
Realized gains (losses)	63,720,000		52,716,000		111,107,000
Unrealized gains relating to instruments held at the reporting date	22,160,000	[1]	23,980,000	[1]	(21,521,000)	[1]
Purchases and settlements during period	(62,662,000)		(53,650,000)		(111,348,000)
Balance at end of period	89,019,000		65,801,000		42,755,000
Unrealized gain (loss) on derivatives and commodity contracts	$ 19,900,000		$ 5,200,000

[1] Includes $19.9 million in mark-to-market gains and $5.2 million in mark-to-market losses for the years ended December 31, 2012 and 2011, respectively. There were no Level 3 mark-to-market gains or losses for the year ended December 31, 2010.

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Common Stock Plans (Stock Repurchase Program) (Details) (Common Stock, USD $)	0 Months Ended	12 Months Ended
	May 25, 1994	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Common Stock
Equity, Class of Treasury Stock [Line Items]
Stock repurchase program, authorized amount	$ 12,564,400
Stock repurchase program, remaining authorized repurchase amount		$ 8,992,700
Shares acquired in connection with stock compensation plans		5,459	12,867	62,794

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Common Stock Plans (Stock Options, Valuation Assumptions) (Details) (Stock options, Stock Incentive Plan, USD $)	0 Months Ended			12 Months Ended
	Jan. 25, 2012	Jan. 26, 2011	Jan. 27, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock options | Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	371,040	293,978	281,110	371,040	293,978	281,110
Fair market value of stock option at grant	$ 18.79	$ 19.65	$ 16.47
Expected life of award	5 years 9 months 18 days	5 years 8 months 12 days	5 years 8 months 12 days
Risk-free interest rate	1.07%	2.45%	2.76%
Annualized volatility rate	39.60%	37.80%	37.30%
Dividend yield	1.00%	1.00%	1.10%

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Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Data [Abstract]

Summarized Quarterly Financial Information

SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

The Company's business is seasonal in character. The following data summarizes quarterly operating results.

	Year ended December 31, 2012
(in thousands, except per share amounts)	First		Second		Third		Fourth
Operating revenues	$	418,444	$	470,355	$	295,324	$	433,046
Operating income	$	104,170	$	220,598	$	19,458	$	115,166
Net income	$	57,406	$	131,287	$	2,046	$	62,823
Diluted earnings per average common share	$	0.79	$	1.82	$	0.03	$	0.87
Basic earnings per average common share	$	0.80	$	1.82	$	0.03	$	0.87

	Year ended December 31, 2011
(in thousands, except per share amounts)	First		Second		Third		Fourth
Operating revenues	$	486,364	$	330,399	$	378,568	$	288,148
Operating income	$	159,881	$	106,335	$	150,412	$	31,641
Net income	$	94,268	$	63,325	$	87,599	$	14,432
Diluted earnings per average common share	$	1.30	$	0.87	$	1.21	$	0.20
Basic earnings per average common share	$	1.31	$	0.88	$	1.22	$	0.20

Alagasco's business is seasonal in character and influenced by weather conditions. The following data summarizes Alagasco's quarterly operating results.

	Year ended December 31, 2012
(in thousands)	First		Second		Third			Fourth
Operating revenues	$	194,487	$	70,887	$	61,809		$	124,406
Operating income (loss)	$	78,560	$	4,448	$	(12,743	)	$	22,951
Net income (loss)	$	46,918	$	326	$	(10,039	)	$	12,197

	Year ended December 31, 2011
(in thousands)	First		Second		Third			Fourth
Operating revenues	$	269,572	$	86,309	$	59,616		$	119,456
Operating income (loss)	$	75,059	$	1,163	$	(10,681	)	$	20,675
Net income (loss)	$	44,175	$	262	$	(9,093	)	$	11,258

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Regulatory Matters (Details) (USD $)	1 Months Ended			12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Regulatory Matters [Line Items]
Enahanced stability reserve extension period				7 years
Return on equity, adjustment requirements, description				RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range.
Extraordinary bad debt expense, excluded from CCM calculation				$ 2,500,000
Enahanced stability reserve amortization period				5 years
Enhanced stability reserve refund period				9 years
Municipal gas distribution systems, weighted average remaining life (in years)				13 years
Alabama Gas Corporation
Regulatory Matters [Line Items]
Revenue impact of rate adjustments	7,800,000	13,000,000	(1,300,000)	(6,300,000)	(6,700,000)	(17,400,000)
Adjustment requirement threshold for teturn on equity as percentage of operations and maintenance expenses to consumer price index				0.75
Amortization expense, enhanced stability reserve, annual amount				660,000
Alabama Gas Corporation | Municipal gas distribution systems
Regulatory Matters [Line Items]
Municipal gas distribution systems, net acquisition adjustments	3,800,000	4,400,000		3,800,000	4,400,000
Alabama Gas Corporation | Minimum
Regulatory Matters [Line Items]
Allowed return on average common equity				13.15%
Alabama Gas Corporation | Maximum
Regulatory Matters [Line Items]
Allowed return on average common equity				13.65%
Rate increases as percentage of prior year revenues				4.00%
Limitation on return on equity as percentage of total capitalization				55.00%
Alabama Gas Corporation | APSC Approved Expension of ESR, November 1, 2010
Regulatory Matters [Line Items]
Negative revenue variance, large commercial and industrial customer budget, minimum amount, charged to enhanced stability reserve				350,000
Alabama Gas Corporation | APSC Approved Expension of ESR, November 1, 2010 | Force Majeure Event Costs
Regulatory Matters [Line Items]
Extraordinary Operating and maintenance expenses, minimum smount, charged to enhanced stability reserve				275,000
Alabama Gas Corporation | APSC Approved Expension of ESR, November 1, 2010 | Force Majeure Events Costs
Regulatory Matters [Line Items]
Extraordinary Operating and maintenance expenses, minimum smount, charged to enhanced stability reserve				412,500
Alabama Gas Corporation | APSC Approved Expension of ESR, November 1, 2010 | Environmental Response and Self Insurance Costs
Regulatory Matters [Line Items]
Extraordinary Operating and maintenance expenses, minimum smount, charged to enhanced stability reserve				$ 1,000,000

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Data [Line Items]

Schedule of quarterly operating results

The Company's business is seasonal in character. The following data summarizes quarterly operating results.

	Year ended December 31, 2012
(in thousands, except per share amounts)	First		Second		Third		Fourth
Operating revenues	$	418,444	$	470,355	$	295,324	$	433,046
Operating income	$	104,170	$	220,598	$	19,458	$	115,166
Net income	$	57,406	$	131,287	$	2,046	$	62,823
Diluted earnings per average common share	$	0.79	$	1.82	$	0.03	$	0.87
Basic earnings per average common share	$	0.80	$	1.82	$	0.03	$	0.87

	Year ended December 31, 2011
(in thousands, except per share amounts)	First		Second		Third		Fourth
Operating revenues	$	486,364	$	330,399	$	378,568	$	288,148
Operating income	$	159,881	$	106,335	$	150,412	$	31,641
Net income	$	94,268	$	63,325	$	87,599	$	14,432
Diluted earnings per average common share	$	1.30	$	0.87	$	1.21	$	0.20
Basic earnings per average common share	$	1.31	$	0.88	$	1.22	$	0.20

Alabama Gas Corporation

Quarterly Financial Data [Line Items]

Schedule of quarterly operating results

Alagasco's business is seasonal in character and influenced by weather conditions. The following data summarizes Alagasco's quarterly operating results.

	Year ended December 31, 2012
(in thousands)	First		Second		Third			Fourth
Operating revenues	$	194,487	$	70,887	$	61,809		$	124,406
Operating income (loss)	$	78,560	$	4,448	$	(12,743	)	$	22,951
Net income (loss)	$	46,918	$	326	$	(10,039	)	$	12,197

	Year ended December 31, 2011
(in thousands)	First		Second		Third			Fourth
Operating revenues	$	269,572	$	86,309	$	59,616		$	119,456
Operating income (loss)	$	75,059	$	1,163	$	(10,681	)	$	20,675
Net income (loss)	$	44,175	$	262	$	(9,093	)	$	11,258

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Common Stock Plans (2004 Stock Appreciation Rights Plan) (Details) (Stock Appreciation Rights, 2004 Stock Appreciation Rights Plan, USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended						12 Months Ended
	Jan. 26, 2011	Jan. 27, 2010	Feb. 16, 2009	Jan. 28, 2009	Feb. 04, 2008	Feb. 01, 2007	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock Appreciation Rights | 2004 Stock Appreciation Rights Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Proceeds from Stock Options Exercised							$ 1.0
Share-based compensation expense								$ 4.3	$ 3.4
Remaining requisite service period (in years)							3 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, Beginning of Period, Shares							777,218	656,340	503,215
Granted								189,984	171,749
Exercised/forfeited							(124,188)	(69,106)	(18,624)
Outstanding, End of Period, Shares							653,030	777,218	656,340
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Outstanding, Beginning of Period, Weighted Average Exercise Price							$ 42.00	$ 38.30	$ 35.46
Granted								$ 54.99	$ 46.69
Exercised/forfeited							$ 30.90	$ 41.21	$ 37.65
Outstanding, End of Period, Weighted Average Exercise Price							$ 44.14	$ 42.00	$ 38.30
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Awards granted	189,984	171,749	3,292	305,257	67,093,000	85,906,000
Fair market value of stock option at grant	$ 11.19	$ 11.93	$ 17.57	$ 18.46	$ 5.80	$ 9.25
Expected life of award	4 years 7 months 6 days	3 years 7 months 6 days	3 years	3 years	2 years 7 months 6 days	2 years
Risk-free interest rate	0.63%	0.44%	0.37%	0.37%	0.31%	0.26%
Annualized volatility rate	40.40%	40.40%	40.40%	40.40%	40.40%	40.40%
Dividend yield	1.20%	1.20%	1.20%	1.20%	1.20%	1.20%

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Summarized Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Selected Quarterly Financial Information [Abstract]
Operating revenues	$ 433,046	$ 295,324	$ 470,355	$ 418,444	$ 288,148	$ 378,568	$ 330,399	$ 486,364	$ 1,617,169	$ 1,483,479	$ 1,578,534
Operating income (loss)	115,166	19,458	220,598	104,170	31,641	150,412	106,335	159,881	459,392	448,269	493,377
Net Income	62,823	2,046	131,287	57,406	14,432	87,599	63,325	94,268	253,562	259,624	290,807
Diluted earnings per average common share	$ 0.87	$ 0.03	$ 1.82	$ 0.79	$ 0.20	$ 1.21	$ 0.87	$ 1.30	$ 3.51	$ 3.59	$ 4.04
Basic earnings per average common share	$ 0.87	$ 0.03	$ 1.82	$ 0.80	$ 0.20	$ 1.22	$ 0.88	$ 1.31	$ 3.52	$ 3.60	$ 4.05
Alabama Gas Corporation
Selected Quarterly Financial Information [Abstract]
Operating revenues	124,406	61,809	70,887	194,487	119,456	59,616	86,309	269,572
Operating income (loss)	22,951	(12,743)	4,448	78,560	20,675	(10,681)	1,163	75,059	62,972	59,546	58,508
Net Income	$ 12,197	$ (10,039)	$ 326	$ 46,918	$ 11,258	$ (9,093)	$ 262	$ 44,175	$ 49,402	$ 46,602	$ 46,883

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Reconciliation of Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Schedule of earnings per share reconciliation

Years ended December 31,
(in thousands, except per share amounts)			2012					2011					2010
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	253,562	72,119	$	3.52	$	259,624	72,056	$	3.60	$	290,807	71,845	$	4.05
Effect of dilutive securities
Stock options			196					270					190
Non-vested restricted stock			1					6					16
Diluted EPS	$	253,562	72,316	$	3.51	$	259,624	72,332	$	3.59	$	290,807	72,051	$	4.04

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Long-Term Debt and Notes Payable (Aggregate Maturities) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Maturities of Long-term Debt [Abstract]
2013	$ 50,000
2014	100,000
2015	180,000
2016	100,000
2017	19,000
Alabama Gas Corporation
Maturities of Long-term Debt [Abstract]
2013	0
2014	0
2015	80,000
2016	0
2017	$ 0

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Common Stock Plans (Energen Employee Savings Plan) (Details) (Energen Employee Savings Plan, USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Energen Employee Savings Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of common stock that might be diversified into other investment options	100.00%
Total shares reserved for issuance (in shares)	1,080,108
Expense associated witth contributions to employee savings plan	$ 7.8	$ 6.8	$ 6.2

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Employee Benefit Plans (Net Periodic Benefit Cost) (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Long-term Disability Plan
Components of net periodic benefit cost:
Expense related to long-term disability plan		$ 700,000	$ 500,000	$ 400,000
Pension Plans
Components of net periodic benefit cost:
Service cost		10,527,000	9,173,000	8,574,000
Interest cost		10,801,000	10,960,000	11,365,000
Expected long-term return on assets		(14,093,000)	(15,471,000)	(12,915,000)
Prior service cost amortization		517,000	496,000	496,000
Defined Benefit Plan, Amortization of Gains (Losses)		8,603,000	6,435,000	5,773,000
Termination benefit charge	(400,000)	0	414,000	0
Net periodic expense		16,355,000	12,007,000	13,293,000
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost		1,853,000	1,769,000	2,064,000
Interest cost		4,248,000	4,443,000	4,833,000
Expected long-term return on assets		(4,438,000)	(4,418,000)	(3,986,000)
Defined Benefit Plan, Amortization of Gains (Losses)		37,000	0	0
Termination benefit charge		0	0
Transition obligation amortization		1,917,000	1,917,000	1,917,000
Net periodic expense		3,617,000	3,711,000	4,828,000
Alabama Gas Corporation | Pension Plans
Components of net periodic benefit cost:
Net periodic expense		7,800,000	5,200,000	6,300,000
Alabama Gas Corporation | Postretirement Benefit Plans
Components of net periodic benefit cost:
Net periodic expense		$ 2,700,000	$ 2,800,000	$ 3,600,000

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Summary of Significant Accounting Policies (Taxes on revenues) (Details) (Alabama Gas Corporation, Excise Taxes, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Alabama Gas Corporation | Excise Taxes
Component of Operating Other Cost and Expense [Line Items]
Taxes on revenues	$ 21,479	$ 25,268	$ 30,704

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Activities
Net Income	$ 253,562	$ 259,624	$ 290,807
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	419,598	283,997	247,865
Asset impairment	21,545	0	0
Accretion expense	7,534	6,837	6,178
Deferred income taxes	124,399	129,041	133,840
Bad debt expense	153	2,525	1,565
Change in derivative fair value	(41,819)	36,210	(819)
Gain on sale of assets	(529)	(5,994)	(2,521)
Other, net	15,681	13,298	(568)
Exploratory expense	16,757	10,916	63,668
Net change in:
Accounts receivable	(11,923)	(16,359)	(31,939)
Inventories	10,018	(14,710)	4,022
Increase (decrease) in accounts payable	(16,392)	12,978	18,889
Amounts due customers including gas supply pass-through	(57,747)	(2,597)	20,751
Income tax receivable	679	37,146	(39,937)
Pension and other postretirement benefit contributions	(5,996)	(5,986)	(42,233)
Other current assets and liabilities	217	14,905	1,454
Net cash provided by operating activities	735,737	761,831	671,022
Investing Activities
Additions to property, plant and equipment	(1,184,300)	(889,614)	(434,121)
Acquisitions, net of cash acquired	(139,563)	(310,193)	(410,348)
Proceeds from sale of assets	2,562	7,987	3,155
Purchase of short-term investments	0	0	(154,880)
Sale of short-term investments	0	0	154,965
Other, net	(881)	(1,679)	(1,464)
Net cash used in investing activities	(1,322,182)	(1,193,499)	(842,693)
Financing Activities
Payment of dividends on common stock	(40,392)	(38,922)	(37,377)
Issuance of common stock	1,224	6,415	685
Issuance of long-term debt	0	749,952	0
Reduction of long-term debt	(1,218)	(5,547)	(150,729)
Net change in short-term debt	628,000	(290,000)	305,000
Tax benefit on stock compensation	550	986	907
Other	(1,556)	(4,334)	0
Net cash provided by (used in) financing activities	586,608	418,550	118,486
Increase (decrease) in cash	163	(13,118)	(53,185)
Cash and cash equivalents at beginning of period	9,541	22,659	75,844
Cash and Cash Equivalents at end of period	9,704	9,541	22,659
Alabama Gas Corporation
Operating Activities
Net Income	49,402	46,602	46,883
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	42,270	39,916	44,042
Deferred income taxes	11,278	28,058	28,861
Bad debt expense	146	2,457	1,561
Other, net	10,667	1,560	(10,958)
Net change in:
Accounts receivable	(13,528)	4,862	(26,567)
Inventories	10,544	(7,371)	5,854
Increase (decrease) in accounts payable	(5,906)	(1,499)	2,663
Amounts due customers including gas supply pass-through	(57,747)	(2,597)	20,751
Income tax receivable	7,000	553	(6,846)
Pension and other postretirement benefit contributions	(2,725)	(2,811)	(26,083)
Other current assets and liabilities	(8,654)	(2,802)	14,273
Net cash provided by operating activities	42,747	106,928	94,434
Investing Activities
Additions to property, plant and equipment	(69,860)	(73,447)	(92,099)
Other, net	(3,252)	(2,743)	(1,827)
Net cash used in investing activities	(73,112)	(76,190)	(93,926)
Financing Activities
Payment of dividends on common stock	(33,637)	(29,183)	(37,367)
Issuance of long-term debt	0	50,000	0
Reduction of long-term debt	(218)	(5,547)	(729)
Net decreases in advances from affiliates	0	0	(24,962)
Net change in short-term debt	62,000	(55,000)	70,000
Other	38	101	0
Net cash provided by (used in) financing activities	28,107	(39,831)	6,942
Increase (decrease) in cash	(2,258)	(9,093)	7,450
Cash and cash equivalents at beginning of period	7,817	16,910	9,460
Cash and Cash Equivalents at end of period	$ 5,559	$ 7,817	$ 16,910

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Employee Benefit Plans (Other Comprehensive Income) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net actuarial (gain) loss experienced during the year	$ 28,748	$ 14,312	$ 4,332
Net actuarial loss recognized as expense	(4,908)	(3,755)	(3,290)
Prior service cost recognized as expense	(340)	(298)	(298)
Total recognized in other comprehensive income (loss)	23,500	10,259	744
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Amortization of prior service cost	313
Amortization of net actuarial loss	8,591
Postretirement Benefit Plans
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Net actuarial (gain) loss experienced during the year	(1,787)	2,111	(2,094)
Transition obligation recognized as expense	(294)	(286)	(280)
Total recognized in other comprehensive income (loss)	(2,081)	1,825	(2,374)
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Amortization of transition obligation	$ 264

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Oil and Gas Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of capitalized costs

The following table sets forth capitalized costs:

(in thousands)	December 31, 2012		December 31, 2011
Proved	$	6,241,148	$	4,927,576
Unproved	197,979		238,792
Total capitalized costs	6,439,127		5,166,368
Accumulated depreciation, depletion and amortization	1,765,241		1,382,526
Capitalized costs, net	$	4,673,886	$	3,783,842

Schedule of cost incurred in property acquisition, exploration and development activities

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

Years ended December 31, (in thousands)	2012		2011		2010
Property acquisition:
Proved	$	79,862	$	214,993	$	207,161
Unproved	58,634		91,888		201,881
Exploration	419,284		190,854		37,371
Development	749,256		623,775		332,541
Total costs incurred	$	1,307,036	$	1,121,510	$	778,954

Schedule of results of operations from producing activities

The following table sets forth results of the Company's oil and gas operations from producing activities:

Years ended December 31, (in thousands)	2012		2011		2010
Gross revenues*	$	1,167,183	$	944,908	$	957,371
Production (lifting costs)	306,375		257,045		224,901
Exploration expense	19,363		13,110		64,584
Depreciation, depletion and amortization	394,668		240,232		200,179
Accretion expense	7,534		6,837		6,178
Income tax expense	157,670		154,180		166,750
Results of operations from producing activities	$	281,573	$	273,504	$	294,779

*The years ended December 31, 2012, 2011 and 2010 gross revenues includes a pre-tax non cash mark-to-market gain on derivatives of $58.8 million, a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million and a pre-tax non-cash mark-to-market loss on derivatives of $3,000, respectively.

Schedule of proved developed and undeveloped oil and gas reserves

The independent reservoir engineers have issued reports covering approximately 99 percent of the Company's ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

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

Year ended December 31, 2011	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
Proved reserves at beginning of period	954,387		103,262		40,601		302.9
Revisions of previous estimates	(12,823	)	(4,513	)	841		(5.8	)
Purchases	19,362		12,583		5,055		20.8
Extensions and discoveries	68,160		24,564		9,637		45.6
Production	(71,718	)	(6,318	)	(2,177	)	(20.4	)
Proved reserves at end of period	957,368		129,578		53,957		343.1
Proved developed reserves at end of period	788,812		83,899		33,154		248.5
Proved undeveloped reserves at end of period	168,556		45,679		20,803		94.6

Year ended December 31, 2010	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
Proved reserves at beginning of period	897,546		77,963		30,257		257.8
Revisions of previous estimates	66,679		(2,243	)	2,434		11.3
Purchases	21,700		16,443		5,730		25.8
Extensions and discoveries	39,570		16,234		4,058		26.8
Production	(70,924	)	(5,131	)	(1,880	)	(18.8	)
Sales	(184	)	(4	)	2		—
Proved reserves at end of period	954,387		103,262		40,601		302.9
Proved developed reserves at end of period	786,292		72,030		28,809		231.9
Proved undeveloped reserves at end of period	168,095		31,232		11,792		71.0

Schedule of standardized measure of discounted future net cash flows relating to proved oil and gas reserves

Years ended December 31, (in thousands)	2012		2011		2010
Future gross revenues	$	17,735,363	$	18,196,229	$	13,210,211
Future production costs	5,715,248		5,823,395		4,959,403
Future development costs	1,892,600		1,539,072		1,026,903
Future income tax expense	2,809,411		3,326,382		2,201,742
Future net cash flows	7,318,104		7,507,380		5,022,163
Discount at 10% per annum	3,618,785		3,878,217		2,555,027
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	3,699,319	$	3,629,163	$	2,467,136
Discounted future net cash flows before income taxes	$	4,411,399	$	4,691,086	$	3,155,746

Schedule of principal sources of changes in standardized measure of discounted future net cash flows

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

Years ended December 31, (in thousands)	2012			2011			2010
Balance at beginning of year	$	3,629,163		$	2,467,136		$	1,563,190
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(922,792		)	707,411			945,179
Net changes due to revisions in quantity estimates	(383,755		)	(80,004		)	36,349
Development costs incurred, previously estimated	472,603			392,720			195,269
Accretion of discount	362,916			246,714			156,319
Changes in timing and other	(317,244		)	(25,937		)	15,815
Total revisions	(788,272		)	1,240,904			1,348,931
New field discoveries and extensions, net of future production and development costs	1,025,419			755,977			319,223
Sales of oil and gas produced, net of production costs	(812,781		)	(763,171		)	(576,755		)
Purchases	189,755			232,768			278,384
Sales	—			—			87
Net change in income taxes	456,035			(304,451		)	(465,924		)
Net change in standardized measure of discounted future net cash flows	70,156			1,162,027			903,946
Balance at end of year	$	3,699,319		$	3,629,163		$	2,467,136

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Line Items]

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, principally Energen Resources Corporation and Alabama Gas Corporation (Alagasco), after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years' financial statements to the current-year presentation.

Fair Value Measurements

Fair Value Measurements

The carrying values of cash and cash equivalents, accounts payable and receivable, 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). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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 fair value hierarchy that prioritizes the inputs used to measure fair value is defined 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 assumption that market value 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.

Derivative commodity instruments are over-the-counter derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These 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 the Company is 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 New York Mercantile Exchange natural gas and oil futures. 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. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties' valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.

Pension and postretirement plan assets include mutual and comingled funds and a limited partnership. 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 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.

Income Taxes

Income Taxes

The Company 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. The Company and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.

Accounts Receivalbe and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is the Company's best estimate of the amount of probable credit losses in the existing accounts receivable. The Company determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.

Cash Equivalents

Cash Equivalents

All highly liquid financial instruments with an original maturity of three months or less at the time of purchase are considered to be cash or cash equivalents.

As of December 31, 2012, the Company and Alagasco revised the presentation of outstanding checks in its financial statements. Previously, the Company and Alagasco reflected outstanding checks as a reduction in cash as of the date the checks cleared the bank as opposed to the date the checks were released for payment. Under the revised presentation, as of December 31, 2011, Energen's cash and accounts payable would have been reduced by $8.0 million and $7.3 million, respectively, while accounts receivable would have increased by $0.7 million. Under the revised presentation, as of December 31, 2011, Alagasco's cash and accounts payable would have been reduced by $6.8 million and $6.1 million, respectively, while accounts receivable would have increased by $0.7 million. The Company and Alagasco considered the impact of this adjustment on the December 31, 2011 balance sheets and statements of cash flows for the year then ended and determined that the amounts were not material. The effect of not revising the presentation of cash balances as of December 31, 2011, but presenting the correct cash balances at December 31, 2012, resulted in a decrease of $8.0 million and $6.8 million to Energen and Alagasco's 2012 operating cash flows, respectively. This adjustment caused no impact to Energen or Alagasco's income statements.

Short-term investments

Short-term investments

All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments. As of December 31, 2012 and 2011, Energen had no short-term investments.

Earnings Per Share (EPS)

Earnings Per Share (EPS)

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

Stock-Based Compensation

Stock-Based Compensation

The Company 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. The Company recognizes all stock-based compensation expense in the period of grant for retirement eligible employees. The Company utilizes the long-form method of calculating the available pool of windfall tax benefit. For 2012 and 2011, the Company recognized an excess tax benefit of $0.6 million and $1.0 million, respectively, related to its stock-based compensation.

Estimates

Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, physical quantities of oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that regulatory accounting will continue as the applicable accounting standard for the Company's regulated operations, the Company'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, self insurance reserves and regulatory assets and liabilities. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.

Employee Benefit Plans

Employee Benefit Plans

Energen has two defined benefit non-contributory qualified pension plans. These plans cover substantially all employees. Pension benefits for the majority of the Company’s employees are based on years of service and final earnings; one plan is based on years of service and flat dollar amounts. The Company also has nonqualified supplemental pension plans covering certain officers of the Company. In addition to providing pension benefits, the Company provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. The Company continues to provide these benefits to certain non-salaried employees. Substantially all of the Company's employees may become eligible for certain benefits if they reach normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.

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

Measurement: The Company calculates periodic expense for defined benefit pension plans and other post retirement 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 pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. Alagasco recognizes a regulatory asset for the portion of the obligation to be recovered in rates in future periods and a regulatory liability for the portion of the plan obligation to be provided through rates in the future. The Company measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.

Discount Rate: In selecting each discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company 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.

Long-Term Rate of Return: The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The Company 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

Environmental Costs

Environmental Costs

Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated. As more fully described in Note 2, Regulatory Matters, and as currently approved, the ESR provides deferred treatment and recovery for extraordinary operations and maintenance (O&M) expenses related to environmental response costs.

Investment, Policy

Investment Strategy: The Company employs 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.

The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the Company to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily.

The Company 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 pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

Oil and Gas Operations

Accounting Policies [Line Items]

Property and Related Depletion

Property and Related Depletion: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid 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. 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. 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 Revenue and Gas Costs

Operating Revenue: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids 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 reserves for such property. Energen Resources had no material production imbalances at December 31, 2012 and 2011.

Derivative Commodity Instruments

Derivative Commodity Instruments: Energen Resources recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps and basis hedges typically 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.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of December 31, 2012, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s 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.

The Company periodically enters into derivatives that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change. Open mark-to-market gains (losses) on derivatives included in operating revenues were as follows:

Years ended December 31, (in thousands)	2012		2011			2010
Mark-to-market gain (loss) on derivatives	$	58,750	$	(37,587	)	$	(3	)

All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the cash flow 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 hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness in hedging the exposure to the hedged transaction's variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the cash flow hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge.

Long-Lived Assets and Discontinued Operations

Long-Lived Assets and Discontinued Operations: The Company reports gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for certain held-for-sale properties are reclassified and reported as discontinued operations for prior periods. Energen Resources 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 fair value.

Acquisitions

Acquisitions: Energen Resources recognizes all acquisitions at fair value. Energen Resources estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen Resources 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 Resources 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 operations and maintenance expense on the consolidated income statements.

Natural Gas Distribution

Accounting Policies [Line Items]

Inventories

Inventories: Inventories, which consist primarily of gas stored underground, are stated at average cost. Liquified natural gas is stated at base cost.

Natural Gas Distribution | Alabama Gas Corporation

Accounting Policies [Line Items]

Operating Revenue and Gas Costs

Operating Revenue and Gas Costs: Alagasco records natural gas distribution revenues in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material gas imbalances at December 31, 2012. Alagasco had gas imbalances of $0.5 million at December 31, 2011.

Derivative Commodity Instruments

Derivative Commodity Instruments: In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet at fair value. Any realized gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco's APSC approved tariff and are recognized as a regulatory asset or regulatory liability. 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 Alagasco.

Regulatory Accounting

Regulatory Accounting: Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) with respect to rates, accounting and various other matters. In general, Alagasco capitalizes or defers certain costs or revenues, based on the approvals received from the APSC, to be recovered from or refunded to customers in future periods. These costs or revenues are recorded as regulatory assets or liabilities.

Property and Related Depletion, and Utility Plant and Depreciation

Utility Plant and Depreciation: Property, plant and equipment are stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. Gains and losses on all dispositions of land are recognized at time of disposal. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets are charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the APSC. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $14.2 million, $22.2 million and $2.7 million for the period January through December 2012, January through December 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $18.3 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $53.5 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a seven year period beginning January 1, 2013. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the Enhanced Stability Reserve (ESR) and other commission-approved charges. The refunds as of December 2012 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates. Approved depreciation rates averaged approximately 3.2 percent, 3.1 percent and 3.6 percent in the years ended December 31, 2012, 2011 and 2010, respectively. The revised depreciation rates decreased depreciation expense by approximately $6.8 million and $9.2 million for the years ended December 31, 2011 and 2010, respectively, from expense amounts calculated using the prior depreciation rate.

Taxes on Revenue

Taxes on revenues: The collection and payment of revenue taxes such as utility license taxes and fees, franchise fees and taxes imposed by other governmental authorities are reported on a gross basis. These amounts are included in taxes other than income taxes on the consolidated statements of income as follows:

Years ended December 31, (in thousands)	2012		2011		2010
Taxes on revenues	$	21,479	$	25,268	$	30,704

The collection and payment of utility gross receipts tax is presented on a net basis.

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2012

Valuation and Qualifying Accounts [Abstract]

Valuation and Qualifying Accounts

VALUATION AND QUALIFYING ACCOUNTS

Energen Corporation

Years ended December 31, (in thousands)	2012			2011			2010
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$	12,946		$	15,048		$	17,251
Additions:
Charged to income	1,415			4,269			2,665
Recoveries and adjustments	(1,262		)	(1,744		)	(1,100		)
Net additions	153			2,525			1,565
Less uncollectible accounts written off	(6,550		)	(4,627		)	(3,768		)
Balance at end of year	$	6,549		$	12,946		$	15,048

Alabama Gas Corporation

Years ended December 31, (in thousands)	2012			2011			2010
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$	12,100		$	14,200		$	16,400
Additions:
Charged to income	1,409			4,202			2,655
Recoveries and adjustments	(1,263		)	(1,745		)	(1,094		)
Net additions	146			2,457			1,561
Less uncollectible accounts written off	(6,546		)	(4,557		)	(3,761		)
Balance at end of year	$	5,700		$	12,100		$	14,200

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Oil and Gas Operations (Unaudited) (Results of Operations) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Gross revenues	$ 1,167,183	[1]	$ 944,908	[1]	$ 957,371	[1]
Production (lifting costs)	306,375		257,045		224,901
Exploration expense	19,363		13,110		64,584
Depreciation, depletion and amortization	394,668		240,232		200,179
Accretion expense	7,534		6,837		6,178
Income tax expense	157,670		154,180		166,750
Results of operations from producing activities	281,573		273,504		294,779
Mark-to-market gain (loss) on derivatives	$ 58,750		$ (37,587)		$ (3)

[1] The years ended December 31, 2012, 2011 and 2010 gross revenues includes a pre-tax non cash mark-to-market gain on derivatives of $58.8 million, a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million and a pre-tax non-cash mark-to-market loss on derivatives of $3,000, respectively.

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Income Taxes (Deferred Tax Assets and Liabilities) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Line Items]
Full valuation allowance	$ 3,100,000
Deferred tax assets:
Total deferred tax assets, Current	33,455,000	50,557,000
Total deferred tax assets, Noncurrent	22,760,000	15,850,000
Valuation allowance, Current	(268,000)	(270,000)
Valuation allowance, Noncurrent	(2,793,000)	(2,752,000)
Total deferred tax assets, net, Current	33,187,000	50,287,000
Total deferred tax assets, net, Noncurrent	19,967,000	13,098,000
Deferred tax liabilities:
Total deferred tax liabilities, Current	24,667,000	1,469,000
Total deferred tax liabilities, Noncurrent	925,568,000	819,225,000
Net deferred tax assets (liabilities), Current	8,520,000	48,818,000
Net deferred tax assets (liabilities), Noncurrent	(905,601,000)	(806,127,000)
Alabama Gas Corporation
Deferred tax assets:
Total deferred tax assets, net, Current	20,200,000	23,334,000
Total deferred tax assets, net, Noncurrent	2,000	4,000
Deferred tax liabilities:
Total deferred tax liabilities, Current	1,401,000	1,348,000
Total deferred tax liabilities, Noncurrent	189,383,000	181,496,000
Net deferred tax assets (liabilities), Current	18,799,000	21,986,000
Net deferred tax assets (liabilities), Noncurrent	(189,381,000)	(181,492,000)
Oil and Gas Operations
Income Tax Disclosure [Line Items]
State net operating loss carryforwards, subject to expiration	12,200,000
Deferred tax assets, Current
Deferred tax assets:
Unbilled and deferred revenue	10,137,000	9,582,000
Allowance for doubtful accounts	2,408,000	4,848,000
Insurance accruals	2,021,000	2,562,000
Compensation accruals	13,116,000	11,181,000
Inventories	1,664,000	1,438,000
Other comprehensive income	0	2,799,000
Gas supply adjustment related accruals	969,000	1,196,000
Derivative instruments	0	13,167,000
State net operating losses and other carryforwards	0	987,000
Other	3,140,000	2,797,000
Deferred tax assets, Current | Alabama Gas Corporation
Deferred tax assets:
Unbilled and deferred revenue	10,137,000	9,582,000
Allowance for doubtful accounts	2,155,000	4,575,000
Insurance accruals	1,856,000	2,358,000
Compensation accruals	2,645,000	2,274,000
Inventories	1,664,000	1,438,000
Gas supply adjustment related accruals	969,000	1,196,000
State net operating losses and other carryforwards	0	987,000
Other	774,000	924,000
Deferred tax assets, Noncurrent
Income Tax Disclosure [Line Items]
Deferred Tax Assets, State Operating Loss Carryforwards and Other Tax Carryforwards, Portion About To Expire	500,000
Deferred tax assets:
Unbilled and deferred revenue	0	0
Allowance for doubtful accounts	0	0
Insurance accruals	0	0
Compensation accruals	0	0
Inventories	0	0
Other comprehensive income	19,158,000	12,801,000
Gas supply adjustment related accruals	0	0
Derivative instruments	0	0
State net operating losses and other carryforwards	3,577,000	3,022,000
Other	25,000	27,000
Deferred tax assets, Noncurrent | Alabama Gas Corporation
Deferred tax assets:
Unbilled and deferred revenue	0	0
Allowance for doubtful accounts	0	0
Insurance accruals	0	0
Compensation accruals	0	0
Inventories	0	0
Gas supply adjustment related accruals	0	0
State net operating losses and other carryforwards	0	0
Other	2,000	4,000
Deferred tax liabilities, Current
Deferred tax liabilities:
Depreciation and basis differences	0	0
Pension and other costs	0	0
Derivative instruments	4,272,000	0
Other comprehensive income	18,133,000	0
Other	2,262,000	1,469,000
Deferred tax liabilities, Current | Alabama Gas Corporation
Deferred tax liabilities:
Depreciation and basis differences	0	0
Pension and other costs	0	0
Other	1,401,000	1,348,000
Deferred tax liabilities, Noncurrent
Deferred tax liabilities:
Depreciation and basis differences	898,625,000	791,073,000
Pension and other costs	20,143,000	25,685,000
Derivative instruments	3,162,000	0
Other comprehensive income	0	0
Other	3,638,000	2,467,000
Deferred tax liabilities, Noncurrent | Alabama Gas Corporation
Deferred tax liabilities:
Depreciation and basis differences	167,329,000	156,121,000
Pension and other costs	22,054,000	25,375,000
Other	$ 0	$ 0

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Industry Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

Schedule of segment information

Years ended December 31,(in thousands)	2012			2011			2010
Operating revenues
Oil and gas operations	$	1,165,580		$	948,526		$	958,762
Natural gas distribution	451,589			534,953			619,772
Total	$	1,617,169		$	1,483,479		$	1,578,534
Operating income (loss)
Oil and gas operations	$	367,243		$	363,131		$	406,729
Natural gas distribution	93,216			86,216			88,383
Eliminations and corporate expenses	(1,067		)	(1,078		)	(1,735		)
Total	$	459,392		$	448,269		$	493,377
Depreciation, depletion and amortization expense
Oil and gas operations	$	377,328		$	244,081		$	203,823
Natural gas distribution	42,270			39,916			44,042
Total	$	419,598		$	283,997		$	247,865
Interest expense
Oil and gas operations	$	49,972		$	30,907		$	25,753
Natural gas distribution	16,284			14,740			13,894
Eliminations and other	(700		)	(825		)	(425		)
Total	$	65,556		$	44,822		$	39,222
Income tax expense (benefit)
Oil and gas operations	$	114,375		$	120,079		$	138,775
Natural gas distribution	30,244			26,670			29,875
Other	(800		)	(1,048		)	(1,660		)
Total	$	143,819		$	145,701		$	166,990
Capital expenditures
Oil and gas operations	$	1,291,211		$	1,115,452		$	717,782
Natural gas distribution	71,869			73,984			93,566
Total	$	1,363,080		$	1,189,436		$	811,348
Identifiable assets
Oil and gas operations	$	4,975,170		$	4,046,242		$	3,160,601
Natural gas distribution	1,177,134			1,163,959			1,166,899
Eliminations and other	23,586			27,215			36,060
Total	$	6,175,890		$	5,237,416		$	4,363,560
Property, plant and equipment, net
Oil and gas operations	$	4,697,683		$	3,806,787		$	2,936,284
Natural gas distribution	842,685			813,471			782,665
Other	1,268			518			278
Total	$	5,541,636		$	4,620,776		$	3,719,227

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

Open mark-to-market gains (losses) on derivatives included in operating revenues were as follows:

Years ended December 31, (in thousands)	2012		2011			2010
Mark-to-market gain (loss) on derivatives	$	58,750	$	(37,587	)	$	(3	)

Schedule of taxes other than income taxes

The collection and payment of revenue taxes such as utility license taxes and fees, franchise fees and taxes imposed by other governmental authorities are reported on a gross basis. These amounts are included in taxes other than income taxes on the consolidated statements of income as follows:

Years ended December 31, (in thousands)	2012		2011		2010
Taxes on revenues	$	21,479	$	25,268	$	30,704

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Long-Term Debt and Notes Payable (Tables)

12 Months Ended

Dec. 31, 2012

Debt Instrument [Line Items]

Schedule of long-term debt

Long-term debt consisted of the following:

(in thousands)	December 31, 2012		December 31, 2011
Energen Corporation:
Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.6%, for notes due July 24, 2017 to February 15, 2028	$	154,000	$	155,000
5% Notes, due October 1, 2013	50,000		50,000
4.625% Notes, due September 1, 2021	400,000		400,000
Senior Term Loans, (floating rate interest LIBOR plus 1.375%; 1.59% at December 31, 2012), due March 31, 2014 to November 29, 2016	300,000		300,000
Alabama Gas Corporation:
5.20% Notes, due January 15, 2020	40,000		40,000
5.70% Notes, due January 15, 2035	35,028		35,246
5.368% Notes, due December 1, 2015	80,000		80,000
5.90% Notes, due January 15, 2037	45,000		45,000
3.86% Notes, due December 21, 2021	50,000		50,000
Total	1,154,028		1,155,246
Less amounts due within one year	50,000		1,000
Less unamortized debt discount	500		546
Total	$	1,103,528	$	1,153,700

Schedule of aggregate maturities of long-term debt

The aggregate maturities of Energen's long-term debt for the next five years are as follows:

Years ending December 31, (in thousands)
2013	2014	2015	2016	2017
$50,000	$100,000	$180,000	$100,000	$19,000

Schedule of credit facilities

The following is a summary of information relating to the credit facilities:

(in thousands)	December 31, 2012			December 31, 2011
Energen outstanding	$	566,000		$	—
Alagasco outstanding	77,000			15,000
Notes payable to banks	643,000			15,000
Available for borrowings	707,000			1,004,000
Total	$	1,350,000		$	1,019,000
Energen maximum amount outstanding at any month-end	$	643,000		$	363,000
Energen average daily amount outstanding	$	331,068		$	229,094
Energen weighted average interest rates based on:
Average daily amount outstanding	1.82		%	2.04		%
Amount outstanding at year-end	1.35		%	3.58		%
Alagasco maximum amount outstanding at any month-end	$	77,000		$	70,000
Alagasco average daily amount outstanding	$	21,254		$	29,268
Alagasco weighted average interest rates based on:
Average daily amount outstanding	1.44		%	1.72		%
Amount outstanding at year-end	1.11		%	3.58		%

Alabama Gas Corporation

Debt Instrument [Line Items]

Schedule of aggregate maturities of long-term debt

he aggregate maturities of Alagasco's long-term debt for the next five years are as follows:

Years ending December 31, (in thousands)
2013	2014	2015	2016	2017
—	—	$80,000	—	—

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY Consolidated Statements of Shareholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Common Stock, Dividends, Per Share, Cash Paid	$ 0.56	$ 0.54	$ 0.52

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Line Items]

Schedule of components of Income taxes

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

Years ended December 31, (in thousands)	2012		2011		2010
Taxes estimated to be payable currently:
Federal	$	16,295	$	11,595	$	31,920
State	3,125		5,065		1,230
Total current	19,420		16,660		33,150
Taxes deferred:
Federal	119,053		125,622		121,804
State	5,346		3,419		12,036
Total deferred	124,399		129,041		133,840
Total income tax expense	$	143,819	$	145,701	$	166,990

Schedule of deferred tax assets and liabilities

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

(in thousands)	December 31, 2012						December 31, 2011
	Current			Noncurrent			Current			Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	10,137		$	—		$	9,582		$	—
Allowance for doubtful accounts	2,408			—			4,848			—
Insurance accruals	2,021			—			2,562			—
Compensation accruals	13,116			—			11,181			—
Inventories	1,664			—			1,438			—
Other comprehensive income	—			19,158			2,799			12,801
Gas supply adjustment related accruals	969			—			1,196			—
Derivative instruments	—			—			13,167			—
State net operating losses and other carryforwards	—			3,577			987			3,022
Other	3,140			25			2,797			27
Total deferred tax assets	33,455			22,760			50,557			15,850
Valuation allowance	(268		)	(2,793		)	(270		)	(2,752		)
Total deferred tax assets	33,187			19,967			50,287			13,098
Deferred tax liabilities:
Depreciation and basis differences	—			898,625			—			791,073
Pension and other costs	—			20,143			—			25,685
Derivative instruments	4,272			3,162			—			—
Other comprehensive income	18,133			—			—			—
Other	2,262			3,638			1,469			2,467
Total deferred tax liabilities	24,667			925,568			1,469			819,225
Net deferred tax assets (liabilities)	$	8,520		$	(905,601	)	$	48,818		$	(806,127	)

Schedule of effective income tax tate reconciliation

Total income tax expense for the Company 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)	2012			2011			2010
Income tax expense at statutory federal income tax rate	$	139,083		$	141,864		$	160,229
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	4,904			5,544			8,398
Qualified Section 199 production activities deduction	(94		)	(593		)	(1,745		)
401(k) stock dividend deduction	(514		)	(532		)	(565		)
Other, net	440			(582		)	673
Total income tax expense	$	143,819		$	145,701		$	166,990
Effective income tax rate (%)	36.19			35.95			36.48

Schedule of reconciliation of unrecognized tax benefits

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

(in thousands)
Balance as of December 31, 2009	$	17,797
Additions based on tax positions related to the current year	1,436
Additions for tax positions of prior years	11,703
Reductions for tax positions of prior years	(3,624		)
Lapse of statute of limitations	(1,313		)
Settlements	(1,409		)
Balance as of December 31, 2010	24,590
Additions based on tax positions related to the current year	3,644
Additions for tax positions of prior years	2,324
Reductions for tax positions of prior years	(39		)
Lapse of statute of limitations	(1,482		)
Settlements	(18,444		)
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

Alabama Gas Corporation

Income Tax Disclosure [Line Items]

Schedule of components of Income taxes

The components of Alagasco's income taxes consisted of the following:

Years ended December 31, (in thousands)	2012		2011			2010
Taxes estimated to be payable currently:
Federal	$	18,227	$	(1,280	)	$	859
State	739		(108		)	155
Total current	18,966		(1,388		)	1,014
Taxes deferred:
Federal	9,066		24,938			25,582
State	2,212		3,120			3,279
Total deferred	11,278		28,058			28,861
Total income tax expense	$	30,244	$	26,670		$	29,875

Schedule of deferred tax assets and liabilities

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

(in thousands)	December 31, 2012					December 31, 2011
	Current		Noncurrent			Current		Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	10,137	$	—		$	9,582	$	—
Allowance for doubtful accounts	2,155		—			4,575		—
Insurance accruals	1,856		—			2,358		—
Compensation accruals	2,645		—			2,274		—
Inventories	1,664		—			1,438		—
Gas supply adjustment related accruals	969		—			1,196		—
State net operating losses and other carryforwards	—		—			987		—
Other	774		2			924		4
Total deferred tax assets	20,200		2			23,334		4
Deferred tax liabilities:
Depreciation and basis differences	—		167,329			—		156,121
Pension and other costs	—		22,054			—		25,375
Other	1,401		—			1,348		—
Total deferred tax liabilities	1,401		189,383			1,348		181,496
Net deferred tax assets (liabilities)	$	18,799	$	(189,381	)	$	21,986	$	(181,492	)

Schedule of effective income tax tate reconciliation

Total income tax expense for Alagasco 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)	2012		2011			2010
Income tax expense at statutory federal income tax rate	$	27,876	$	25,645		$	26,865
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	2,238		2,059			2,157
Reversal of tax reserves from audit settlements, net	—		(1,365		)	—
Other, net	130		331			853
Total income tax expense	$	30,244	$	26,670		$	29,875
Effective income tax rate (%)	37.97		36.40			38.92

Schedule of reconciliation of unrecognized tax benefits

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

(in thousands)
Balance as of December 31, 2009	$	7,621
Additions based on tax positions related to the current year	9
Additions for tax positions of prior years	11,645
Reductions for tax positions of prior years (lapse of statute of limitations)	(90		)
Settlements	(244		)
Balance as of December 31, 2010	18,941
Additions based on tax positions related to the current year	13
Additions for tax positions of prior years	1
Reductions for tax positions of prior years (lapse of statute of limitations)	(409		)
Settlements	(18,444		)
Balance as of December 31, 2011	102
Additions based on tax positions related to the current year	62
Additions for tax positions of prior years	201
Reductions for tax positions of prior years (lapse of statute of limitations)	(58		)
Balance as of December 31, 2012	$	307

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Financial Instruments and Risk Management (Risk Management) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Derivative, Fair Value, Net [Abstract]
Derivative, Fair Value, Net	$ 93,176,000	$ (88,820,000)
Deferred Tax Assets (Liabilities), Net [Abstract]
Deferred tax assets (liabilities), net	(28,400,000)	(5,700,000)
Designated as Hedging Instrument
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	125,468,000	149,618,000
Derivative Liability, Fair Value, Net	(52,862,000)	(141,971,000)
Derivative, Fair Value, Net	72,606,000	7,647,000
Designated as Hedging Instrument | Accounts receivable
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	87,514,000	73,636,000
Derivative Liability, Fair Value, Gross Asset	(37,326,000)	(48,174,000)
Designated as Hedging Instrument | Other Assets
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	37,954,000	75,982,000
Derivative Liability, Fair Value, Gross Asset	(6,810,000)	(36,341,000)
Designated as Hedging Instrument | Accounts Payable
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability		(37,070,000)
Designated as Hedging Instrument | Other Liabilities
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability	(8,726,000)	(20,386,000)
Not Designated as Hedging Instrument
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	24,037,000	(12,255,000)
Derivative Liability, Fair Value, Gross Liability	(3,467,000)	(84,212,000)
Derivative, Fair Value, Net	20,570,000	(96,467,000)
Not Designated as Hedging Instrument | Accounts receivable
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	14,604,000	(3,670,000)
Not Designated as Hedging Instrument | Other Assets
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	9,433,000	(8,585,000)
Not Designated as Hedging Instrument | Accounts Payable
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability	(2,593,000)	(70,220,000)
Not Designated as Hedging Instrument | Other Liabilities
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability	(874,000)	(13,992,000)
Oil and Gas Operations
Derivative, Fair Value, Net [Abstract]
Derivative, Fair Value, Net	95,769,000	(28,946,000)
Oil and Gas Operations | Designated as Hedging Instrument
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	125,468,000	149,618,000
Derivative Liability, Fair Value, Net	(52,862,000)	(141,971,000)
Derivative, Fair Value, Net	72,606,000	7,647,000
Oil and Gas Operations | Designated as Hedging Instrument | Accounts receivable
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	87,514,000	73,636,000
Derivative Liability, Fair Value, Gross Asset	(37,326,000)	(48,174,000)	[1]
Oil and Gas Operations | Designated as Hedging Instrument | Other Assets
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	37,954,000	75,982,000
Derivative Liability, Fair Value, Gross Asset	(6,810,000)	(36,341,000)	[1]
Oil and Gas Operations | Designated as Hedging Instrument | Accounts Payable
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability		(37,070,000)
Oil and Gas Operations | Designated as Hedging Instrument | Other Liabilities
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability	(8,726,000)	(20,386,000)
Oil and Gas Operations | Not Designated as Hedging Instrument
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	24,037,000	(12,255,000)
Derivative Liability, Fair Value, Gross Liability	(874,000)	(24,338,000)
Derivative, Fair Value, Net	23,163,000	(36,593,000)
Oil and Gas Operations | Not Designated as Hedging Instrument | Accounts receivable
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	14,604,000	(3,670,000)	[1]
Oil and Gas Operations | Not Designated as Hedging Instrument | Other Assets
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	9,433,000	(8,585,000)	[1]
Oil and Gas Operations | Not Designated as Hedging Instrument | Accounts Payable
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	(13,416,000)
Oil and Gas Operations | Not Designated as Hedging Instrument | Other Liabilities
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability	(874,000)	(10,922,000)
Natural Gas Distribution
Derivative, Fair Value, Net [Abstract]
Derivative, Fair Value, Net	(2,593,000)	(59,874,000)
Natural Gas Distribution | Designated as Hedging Instrument
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Net	0	0
Derivative, Fair Value, Net	0	0
Natural Gas Distribution | Designated as Hedging Instrument | Accounts receivable
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Asset	0	0
Natural Gas Distribution | Designated as Hedging Instrument | Other Assets
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Asset	0	0
Natural Gas Distribution | Designated as Hedging Instrument | Accounts Payable
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability		0
Natural Gas Distribution | Designated as Hedging Instrument | Other Liabilities
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Natural Gas Distribution | Not Designated as Hedging Instrument
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	(2,593,000)	(59,874,000)
Derivative, Fair Value, Net	(2,593,000)	(59,874,000)
Natural Gas Distribution | Not Designated as Hedging Instrument | Accounts receivable
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Natural Gas Distribution | Not Designated as Hedging Instrument | Other Assets
Derivative, Fair Value, Net [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Natural Gas Distribution | Not Designated as Hedging Instrument | Accounts Payable
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability	(2,593,000)	(56,804,000)
Natural Gas Distribution | Not Designated as Hedging Instrument | Other Liabilities
Derivative, Fair Value, Net [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	(3,070,000)
Cash Flow Hedges | Macquarie Bank Limited
Derivatives, Fair Value [Line Items]
Derivative, Net Loss Position	20,000,000
Cash Flow Hedges | J Aron & Company
Derivatives, Fair Value [Line Items]
Derivative, Net Gain Position	16,600,000
Cash Flow Hedges | BP Corporation North America Inc
Derivatives, Fair Value [Line Items]
Derivative, Net Gain Position	13,600,000
Cash Flow Hedges | Shell Energy North America US, L.P.
Derivatives, Fair Value [Line Items]
Derivative, Net Gain Position	$ 10,300,000

[1] Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

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Acquisition and Dispositions of Oil and Gas Properties (Tables)

12 Months Ended

Dec. 31, 2012

Acquisition and Dispositions of Oil and Gas Properties [Abstract]

Schedule of consideration paid and amounts of assets acquired and liabilities assumed

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 15, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	73,630
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	41,066
Unproved leasehold properties	32,500
Accounts receivable	143
Asset retirement obligation	(79		)
Total identifiable net assets	$	73,630

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	161,967
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,544
Unproved leasehold properties	7,883
Accounts receivable	3,070
Accounts payable	(388		)
Asset retirement obligation	(142		)
Total identifiable net assets	$	161,967

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

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of September 30, 2010, (including the effects of closing adjustment).

(in thousands)
Consideration given
Cash (net)	$	188,314
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,747
Unproved leasehold properties	35,360
Accounts receivable	1,461
Asset retirement obligation	(142		)
Accounts payable	(112		)
Total identifiable net assets	$	188,314

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011 (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	60,017
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	36,068
Unproved leasehold properties	23,686
Accounts receivable	680
Accounts payable	(244		)
Asset retirement obligation	(173		)
Total identifiable net assets	$	60,017

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Long-Term Debt and Notes Payable (Textual) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Debt Instrument [Line Items]
Debt secured under sale-leaseback arrangement	$ 4,000,000
Cross default provision, minimum threshold amount	10,000,000
Interest expense	65,556,000	44,822,000	39,222,000
Interest expense, capitalized	500,000
Senior Term Loans | Swap
Debt Instrument [Line Items]
Fixed interest rate exchanged for variable interest rate under swap agreement	2.4175%
Senior Term Loans | Swap | Level 2
Debt Instrument [Line Items]
Interest rate swap liability, fair value	3,300,000	1,500,000
Senior Term Loans | Senior Term Loans, (floating rate interest LIBOR plus 1.375%; 1.59% at December 31, 2012), due March 31, 2014 to November 29, 2016
Debt Instrument [Line Items]
Long-term debt	300,000,000
Senior Term Loans | Senior Term Loans, (floating rate interest LIBOR plus 1.375%; 1.59% at December 31, 2012), due March 31, 2014 to November 29, 2016 | Swap
Debt Instrument [Line Items]
Long-term debt	200,000,000
Senior Notes | 4.625% Notes, due September 1, 2021
Debt Instrument [Line Items]
Long-term debt	400,000,000
Debt instrument, interest rate	4.625%
Alabama Gas Corporation
Debt Instrument [Line Items]
Cross default provision, minimum threshold amount	10,000,000
Interest expense	16,284,000	14,740,000	13,894,000
Alabama Gas Corporation | Notes | 3.86% Notes, due December 21, 2021
Debt Instrument [Line Items]
Long-term debt	$ 50,000,000
Debt instrument, interest rate	3.86%

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Common Stock Plans (Stock Options, Textual) (Details) (Stock Incentive Plan, USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 7,000,000	$ 5,600,000	$ 4,600,000
Tax benefit related to stock-based compensation	2,600,000	2,100,000	1,700,000
Intrinsic value of stock options exercied during period	1,100,000
Cash received from exercise of stock options	1,500,000
Intrinsic value for outstanding options	5,700,000
Intrinsic value for exercisable options	5,700,000
Fair value of vested options	5,100,000
Unrecognized compensation cost	1,900,000
Stock Appreciation Rights
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of stock options exercied during period	2,600,000
Cash paid for settlement of stock apprciation rights	$ 1,800,000

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Revenues
Oil and gas operations	$ 1,165,580	$ 948,526	$ 958,762
Natural gas distribution	451,589	534,953	619,772
Total operating revenues	1,617,169	1,483,479	1,578,534
Operating Expenses
Cost of gas	142,228	233,523	316,988
Operations and maintenance	477,883	419,119	429,165
Depreciation, depletion and amortization	419,598	283,997	247,865
Asset impairment	21,545	0	0
Income taxes
Current	19,420	16,660	33,150
Deferred	124,399	129,041	133,840
Taxes, other than income taxes	88,989	91,734	84,961
Accretion expense	7,534	6,837	6,178
Total operating expenses	1,157,777	1,035,210	1,085,157
Operating Income (Expense)	459,392	448,269	493,377
Other Income (Expense)
Interest expense	65,556	44,822	39,222
Other income	4,448	2,334	4,285
Other expense	(903)	(456)	(643)
Total other income (expense)	(62,011)	(42,944)	(35,580)
Interest Charges
Income Before Income Taxes	397,381	405,325	457,797
Income tax expense	143,819	145,701	166,990
Net income	253,562	259,624	290,807
Diluted earnings per average common share	$ 3.51	$ 3.59	$ 4.04
Basic earnings per average common share	$ 3.52	$ 3.60	$ 4.05
Dividends Per Common Share (dollars per share)	$ 0.56	$ 0.54	$ 0.52
Diluted Average Common Shares Outstanding	72,316,214	72,332,369	72,050,997
Basic Average Common Shares Outstanding	72,119,021	72,055,661	71,845,463
Alabama Gas Corporation
Operating Revenues
Natural gas distribution	451,589	534,953	619,772
Operating Expenses
Cost of gas	142,228	233,523	316,988
Operations and maintenance	141,334	139,030	128,830
Depreciation, depletion and amortization	42,270	39,916	44,042
Income taxes
Current	18,966	(1,388)	1,014
Deferred	11,278	28,058	28,861
Taxes, other than income taxes	32,541	36,268	41,529
Total operating expenses	388,617	475,407	561,264
Operating Income (Expense)	62,972	59,546	58,508
Other Income (Expense)
Interest expense	16,284	14,740	13,894
Allowance for funds used during construction	623	807	808
Other income	2,382	1,309	1,923
Other expense	(291)	(320)	(462)
Total other income (expense)	2,714	1,796	2,269
Interest Charges
Interest on long-term debt	13,744	12,100	11,907
Other interest charges	2,540	2,640	1,987
Income tax expense	30,244	26,670	29,875
Net income	$ 49,402	$ 46,602	$ 46,883

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Summary of Significant Accounting Policies (Derivative Commodity Instruments) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounting Policies [Abstract]
Mark-to-market gain (loss) on derivatives	$ 58,750	$ (37,587)	$ (3)

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Transactions with Related Parties (Details) (Alabama Gas Corporation, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Alabama Gas Corporation
Related Party Transaction [Line Items]
Net trade receivables from affiliates	$ 5.7	$ 2.8
Interest expense in affiliated company	$ 0.3	$ 0.4	$ 0.3

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CONSOLIDATED BALANCE SHEETS Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Allowance for doubtful accounts	$ 6,549	$ 12,946
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	75,067,760	75,007,412
Treasury stock, shares	2,998,620	3,036,549
Alabama Gas Corporation
Allowance for doubtful accounts	$ 5,700	$ 12,100
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	120,000	120,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	3,000,000	3,000,000
Common stock, shares issued	1,972,052	1,972,052

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Acquisition and Dispositions of Oil and Gas Properties (Details) (USD $)	3 Months Ended								12 Months Ended				12 Months Ended		0 Months Ended		12 Months Ended	0 Months Ended					0 Months Ended										0 Months Ended					0 Months Ended	12 Months Ended	0 Months Ended
	Dec. 31, 2012 MMBoe	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011 MMBoe	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012 MMBoe	Dec. 31, 2011 MMBoe	Dec. 31, 2010 MMBoe	Dec. 31, 2009 MMBoe	Dec. 31, 2011 Alabama Shale	Dec. 31, 2011 Alabama Shale Well	Feb. 21, 2012 Feb 21, 2012, Reeves County well acre	Feb. 14, 2012 Feb 14, 2012, Permian Basin MMBoe	Dec. 31, 2012 Feb 14, 2012, Permian Basin	Feb. 14, 2012 Feb 14, 2012, Permian Basin Oil Reserves	Feb. 14, 2012 Feb 14, 2012, Permian Basin Natural Gas Liquids Reserves	Feb. 14, 2012 Feb 14, 2012, Permian Basin Natural Gas Reserves	Dec. 31, 2012 December 2012, Permian Basin	Dec. 31, 2012 Unproved Leasehold Properties	Dec. 27, 2011 Dec 27, 2011, Permian Basin MMBoe	Dec. 27, 2011 Dec 27, 2011, Permian Basin Oil Reserves	Dec. 27, 2011 Dec 27, 2011, Permian Basin Natural Gas Liquids Reserves	Dec. 27, 2011 Dec 27, 2011, Permian Basin Natural Gas Reserves	Nov. 16, 2011 Nov 16, 2011, Permian Basin MMBoe	Nov. 16, 2011 Nov 16, 2011, Permian Basin Oil Reserves	Nov. 16, 2011 Nov 16, 2011, Permian Basin Natural Gas Liquids Reserves	Nov. 16, 2011 Nov 16, 2011, Permian Basin Natural Gas Reserves	Dec. 31, 2012 July 2011, Permian Basin	Dec. 31, 2012 April 2011, Permian Basin acre	Dec. 15, 2010 Dec 15, 2010, Permian Basin MMBoe	Dec. 15, 2010 Dec 15, 2010, Permian Basin Oil Reserves	Dec. 15, 2010 Dec 15, 2010, Permian Basin Natural Gas Liquids Reserves	Dec. 15, 2010 Dec 15, 2010, Permian Basin Natural Gas Reserves	Dec. 09, 2010 Dec 9, 2010, Permian Basin MMBoe	Sep. 30, 2010 Sep 30, 2010, Permian Basin MMBoe	Dec. 31, 2011 Sep 30, 2010, Permian Basin	Sep. 30, 2010 Sep 30, 2010, Permian Basin Oil Reserves	Sep. 30, 2010 Sep 30, 2010, Permian Basin Natural Gas Liquids Reserves	Sep. 30, 2010 Sep 30, 2010, Permian Basin Natural Gas Reserves	May 01, 2012 Contingent Sales Agreement Feb 21, 2012, Reeves County acre
Significant Acquisitions and Disposals [Line Items]
Impairment of oil and gas properties									$ 21,545,000
Discount rate assumed for valuation (in percent)									10.00%
Significant Acquisitions and Disposals, Percentage of Undivided Interest, Sale															50.00%																												50.00%
Acquisition Oil and Gas Properties, Number of Wells															3
Cash received from sale of oil properties															18,000,000
Net acres															4,829																	11,000											51,720
Consideration - Purchase Price																67,615,000					18,723,000	18,000,000	60,017,000				161,967,000				20,000,000	37,000,000	73,630,000				103,000,000	188,314,000
Proved reserves acquired	346.4				343.1				346.4	343.1	302.9	257.8				8.2							3.4				13.6						7.6				0	18
Percentage of undeveloped portion of proved reserves									59.00%	69.00%	77.00%					81.00%							77.00%				76.00%						92.00%					89.00%
Acquired proved reserves by type of reserve, percentage																		64.00%	22.00%	14.00%				61.00%	24.00%	15.00%		59.00%	25.00%	16.00%				62.00%	24.00%	14.00%				65.00%	22.00%	13.00%
Exploration Abandonment and Impairment Expense													39,700,000	15,500,000
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties																65,581,000							36,068,000				151,544,000						41,066,000					151,747,000
Unproved leasehold properties																911,000							23,686,000				7,883,000						32,500,000					35,360,000
Accounts receivable																1,358,000							680,000				3,070,000						143,000					1,461,000
Accounts payable																(25,000)							(244,000)				(388,000)											(112,000)
Asset retirement obligation																(210,000)							(173,000)				(142,000)						(79,000)					(142,000)
Total identifiable net assets																67,615,000							60,017,000				161,967,000						73,630,000					188,314,000
Revenue, Net	433,046,000	295,324,000	470,355,000	418,444,000	288,148,000	378,568,000	330,399,000	486,364,000	1,617,169,000	1,483,479,000	1,578,534,000						11,700,000																						5,000,000
Operating Income (Loss)	$ 115,166,000	$ 19,458,000	$ 220,598,000	$ 104,170,000	$ 31,641,000	$ 150,412,000	$ 106,335,000	$ 159,881,000	$ 459,392,000	$ 448,269,000	$ 493,377,000						$ 3,100,000																						$ 2,100,000

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Employee Benefit Plans (Benefit Obligations) (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Amounts recognized in balance sheet
Noncurrent assets		$ 1,404,000	$ 0
Noncurrent liabilities		(110,282,000)	(62,532,000)
Amounts recognized to accumulated other comprehensive income:
Total accumulated other comprehensive income (loss)		52,507,000	38,584,000
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation		269,101,000	211,896,000
Projected benefit obligation:
Balance at beginning of period	233,772,000	250,619,000	233,772,000
Service cost		10,527,000	9,173,000	8,574,000
Interest cost		10,801,000	10,960,000	11,365,000
Actuarial (gain) loss		65,048,000	17,024,000
Plan amendments		0	(169,000)
Termination benefit charge	(400,000)	0	414,000	0
Retiree drug subsidy program		0	0
Benefits paid		(13,455,000)	(20,555,000)
Balance at end of period		323,540,000	250,619,000	233,772,000
Plan assets:
Fair value of plan assets at beginning of period	212,454,000	195,659,000	212,454,000
Actual return (loss) on plan assets		24,841,000	1,485,000
Employer contributions		2,379,000	2,275,000
Benefits paid		(13,455,000)	(20,555,000)
Fair value of plan assets at end of period		209,424,000	195,659,000	212,454,000
Funded status of plan
Funded status of plan		(114,116,000)	(54,960,000)
Amounts recognized in balance sheet
Noncurrent assets		0	0
Current liabilities		(3,834,000)	(2,371,000)
Noncurrent liabilities		(110,282,000)	(52,589,000)
Net asset (liability) recognized		(114,116,000)	(54,960,000)
Amounts recognized to accumulated other comprehensive income:
Prior service costs, net of taxes		528,000	749,000
Net actuarial (gain) loss, net of taxes		52,472,000	36,976,000
Transition obligation, net of taxes		0	0
Total accumulated other comprehensive income (loss)		53,000,000	37,725,000
Postretirement Benefit Plans
Projected benefit obligation:
Balance at beginning of period	83,748,000	88,064,000	83,748,000
Service cost		1,853,000	1,769,000	2,064,000
Interest cost		4,248,000	4,443,000	4,833,000
Actuarial (gain) loss		(5,413,000)	1,858,000
Plan amendments		0	0
Termination benefit charge		0	0
Retiree drug subsidy program		360,000	302,000
Benefits paid		(3,327,000)	(4,056,000)
Balance at end of period		85,785,000	88,064,000	83,748,000
Plan assets:
Fair value of plan assets at beginning of period	80,118,000	78,121,000	80,118,000
Actual return (loss) on plan assets		8,778,000	(1,653,000)
Employer contributions		3,617,000	3,712,000
Benefits paid		(3,327,000)	(4,056,000)
Fair value of plan assets at end of period		87,189,000	78,121,000	80,118,000
Funded status of plan
Funded status of plan		1,404,000	(9,943,000)
Amounts recognized in balance sheet
Noncurrent assets		1,404,000	0
Current liabilities		0	0
Noncurrent liabilities		0	(9,943,000)
Net asset (liability) recognized		1,404,000	(9,943,000)
Amounts recognized to accumulated other comprehensive income:
Prior service costs, net of taxes		0	0
Net actuarial (gain) loss, net of taxes		(715,000)	451,000
Transition obligation, net of taxes		222,000	408,000
Total accumulated other comprehensive income (loss)		(493,000)	859,000
Alabama Gas Corporation
Amounts recognized in balance sheet
Noncurrent assets		848,000	0
Noncurrent liabilities		(43,611,000)	(21,383,000)
Alabama Gas Corporation | Pension Plans
Amounts recognized to accumulated other comprehensive income:
Regulatory Assets		89,500,000	67,800,000
Alabama Gas Corporation | Postretirement Benefit Plans
Amounts recognized to accumulated other comprehensive income:
Regulatory Assets			8,400,000
Regulatory Liabilities		$ 1,200,000

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Oil and Gas Operations (Unaudited) (Costs Incurred) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property acquisition:
Proved	$ 79,862	$ 214,993	$ 207,161
Unproved	58,634	91,888	201,881
Exploration	419,284	190,854	37,371
Development	749,256	623,775	332,541
Total costs incurred	$ 1,307,036	$ 1,121,510	$ 778,954

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Operating Leased Assets [Line Items]

Schedule of minimum future rental payments

Minimum future rental payments required after 2012 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2013	2014	2015	2016	2017	2018 and thereafter
$5,144	$4,836	$4,506	$4,141	$3,980	$13,046

Schedule of future minimum lease payments for capital leases

The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2012:

(in thousands)
2013	$	1,743
2014	1,743
2015	145
Total minimum lease payments	3,631
Less amount representing interest	54
Total present value of minimum lease payments	$	3,577

Alabama Gas Corporation

Operating Leased Assets [Line Items]

Schedule of minimum future rental payments

Minimum future rental payments required after 2012 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2013	2014	2015	2016	2017	2018 and thereafter
$3,629	$3,858	$3,909	$3,934	$3,980	$13,046

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Employee Benefit Plans (Fair Value of Plan Assets) (Details) (USD $) In Thousands, unless otherwise specified								12 Months Ended
	Dec. 31, 2012 Pension Plans	Dec. 31, 2011 Pension Plans	Dec. 31, 2010 Pension Plans	Dec. 31, 2012 Pension Plans Level 1	Dec. 31, 2011 Pension Plans Level 1	Dec. 31, 2012 Pension Plans Level 2	Dec. 31, 2011 Pension Plans Level 2	Dec. 31, 2012 Pension Plans Level 3	Dec. 31, 2011 Pension Plans Level 3	Dec. 31, 2012 Pension Plans United States equities	Dec. 31, 2011 Pension Plans United States equities	Dec. 31, 2012 Pension Plans United States equities Level 1	Dec. 31, 2011 Pension Plans United States equities Level 1	Dec. 31, 2012 Pension Plans United States equities Level 2	Dec. 31, 2011 Pension Plans United States equities Level 2	Dec. 31, 2012 Pension Plans United States equities Level 3	Dec. 31, 2011 Pension Plans United States equities Level 3	Dec. 31, 2012 Pension Plans Global equities	Dec. 31, 2011 Pension Plans Global equities	Dec. 31, 2012 Pension Plans Global equities Level 1	Dec. 31, 2011 Pension Plans Global equities Level 1	Dec. 31, 2012 Pension Plans Global equities Level 2	Dec. 31, 2011 Pension Plans Global equities Level 2	Dec. 31, 2012 Pension Plans Global equities Level 3	Dec. 31, 2011 Pension Plans Global equities Level 3	Dec. 31, 2012 Pension Plans Fixed income	Dec. 31, 2011 Pension Plans Fixed income	Dec. 31, 2012 Pension Plans Fixed income Level 1	Dec. 31, 2011 Pension Plans Fixed income Level 1	Dec. 31, 2012 Pension Plans Fixed income Level 2	Dec. 31, 2011 Pension Plans Fixed income Level 2	Dec. 31, 2012 Pension Plans Fixed income Level 3	Dec. 31, 2011 Pension Plans Fixed income Level 3	Dec. 31, 2012 Pension Plans Alternative investments	Dec. 31, 2011 Pension Plans Alternative investments	Dec. 31, 2012 Pension Plans Alternative investments Level 1	Dec. 31, 2011 Pension Plans Alternative investments Level 1	Dec. 31, 2012 Pension Plans Alternative investments Level 2	Dec. 31, 2011 Pension Plans Alternative investments Level 2	Dec. 31, 2012 Pension Plans Alternative investments Level 3	Dec. 31, 2011 Pension Plans Alternative investments Level 3	Dec. 31, 2012 Pension Plans Cash and cash equivalents	Dec. 31, 2011 Pension Plans Cash and cash equivalents	Dec. 31, 2012 Pension Plans Cash and cash equivalents Level 1	Dec. 31, 2011 Pension Plans Cash and cash equivalents Level 1	Dec. 31, 2012 Pension Plans Cash and cash equivalents Level 2	Dec. 31, 2011 Pension Plans Cash and cash equivalents Level 2	Dec. 31, 2012 Pension Plans Cash and cash equivalents Level 3	Dec. 31, 2011 Pension Plans Cash and cash equivalents Level 3	Dec. 31, 2012 Postretirement Benefit Plans	Dec. 31, 2011 Postretirement Benefit Plans	Dec. 31, 2010 Postretirement Benefit Plans	Dec. 31, 2012 Postretirement Benefit Plans Level 1	Dec. 31, 2011 Postretirement Benefit Plans Level 1	Dec. 31, 2012 Postretirement Benefit Plans Level 2	Dec. 31, 2011 Postretirement Benefit Plans Level 2	Dec. 31, 2012 Postretirement Benefit Plans United States equities	Dec. 31, 2011 Postretirement Benefit Plans United States equities	Dec. 31, 2012 Postretirement Benefit Plans United States equities Level 1	Dec. 31, 2011 Postretirement Benefit Plans United States equities Level 1	Dec. 31, 2012 Postretirement Benefit Plans United States equities Level 2	Dec. 31, 2011 Postretirement Benefit Plans United States equities Level 2	Dec. 31, 2012 Postretirement Benefit Plans Global equities	Dec. 31, 2011 Postretirement Benefit Plans Global equities	Dec. 31, 2012 Postretirement Benefit Plans Global equities Level 1	Dec. 31, 2011 Postretirement Benefit Plans Global equities Level 1	Dec. 31, 2012 Postretirement Benefit Plans Global equities Level 2	Dec. 31, 2011 Postretirement Benefit Plans Global equities Level 2	Dec. 31, 2012 Postretirement Benefit Plans Fixed income	Dec. 31, 2011 Postretirement Benefit Plans Fixed income	Dec. 31, 2012 Postretirement Benefit Plans Fixed income Level 1	Dec. 31, 2011 Postretirement Benefit Plans Fixed income Level 1	Dec. 31, 2012 Postretirement Benefit Plans Fixed income Level 2	Dec. 31, 2011 Postretirement Benefit Plans Fixed income Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 209,424	$ 195,659	$ 212,454	$ 65,689	$ 57,073	$ 129,235	$ 121,187	$ 14,500	$ 17,399	$ 50,979	$ 45,925	$ 41,907	$ 37,009	$ 9,072	$ 8,916	$ 0	$ 0	$ 34,479	$ 29,330	$ 23,782	$ 20,064	$ 10,697	$ 4,914	$ 0	$ 4,352	$ 78,806	$ 78,443	$ 0	$ 0	$ 78,806	$ 78,443	$ 0	$ 0	$ 42,159	$ 39,117	$ 0	$ 0	$ 27,659	$ 26,070	$ 14,500	$ 13,047	$ 3,001	$ 2,844	$ 0	$ 0	$ 3,001	$ 2,844	$ 0	$ 0	$ 87,189	$ 78,121	$ 80,118	$ 52,531	$ 46,737	$ 34,658	$ 31,384	$ 37,482	$ 33,649	$ 37,482	$ 33,649	$ 0	$ 0	$ 15,049	$ 13,088	$ 15,049	$ 13,088	$ 0	$ 0	$ 34,658	$ 31,384	$ 0	$ 0	$ 34,658	$ 31,384
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	209,424	195,659	212,454	65,689	57,073	129,235	121,187	17,399	26,841	50,979	45,925	41,907	37,009	9,072	8,916	0	0	34,479	29,330	23,782	20,064	10,697	4,914	0	4,352	78,806	78,443	0	0	78,806	78,443	0	0	42,159	39,117	0	0	27,659	26,070	14,500	13,047	3,001	2,844	0	0	3,001	2,844	0	0	87,189	78,121	80,118	52,531	46,737	34,658	31,384	37,482	33,649	37,482	33,649	0	0	15,049	13,088	15,049	13,088	0	0	34,658	31,384	0	0	34,658	31,384
Unrealized gains (losses)								992	(752)
Unrealized gains relating to instruments held at the reporting date								242	635
Settlements								(4,948)	(9,604)
Purchases								815	279
Fair value of plan assets at end of period	$ 209,424	$ 195,659	$ 212,454	$ 65,689	$ 57,073	$ 129,235	$ 121,187	$ 14,500	$ 17,399	$ 50,979	$ 45,925	$ 41,907	$ 37,009	$ 9,072	$ 8,916	$ 0	$ 0	$ 34,479	$ 29,330	$ 23,782	$ 20,064	$ 10,697	$ 4,914	$ 0	$ 4,352	$ 78,806	$ 78,443	$ 0	$ 0	$ 78,806	$ 78,443	$ 0	$ 0	$ 42,159	$ 39,117	$ 0	$ 0	$ 27,659	$ 26,070	$ 14,500	$ 13,047	$ 3,001	$ 2,844	$ 0	$ 0	$ 3,001	$ 2,844	$ 0	$ 0	$ 87,189	$ 78,121	$ 80,118	$ 52,531	$ 46,737	$ 34,658	$ 31,384	$ 37,482	$ 33,649	$ 37,482	$ 33,649	$ 0	$ 0	$ 15,049	$ 13,088	$ 15,049	$ 13,088	$ 0	$ 0	$ 34,658	$ 31,384	$ 0	$ 0	$ 34,658	$ 31,384

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2012

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETS AND LIABILITIES

The following table details regulatory assets and liabilities on the consolidated balance sheets:

(in thousands)	December 31, 2012				December 31, 2011
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	90,708	$	170	$	77,587
Accretion and depreciation for asset retirement obligation	—		16,536		—		13,981
Risk management activities	2,593		—		56,804		3,070
Rate recovery of asset removal costs, net	—		3,322		—		994
Gas supply adjustment	42,726		—		—		—
Other	26		—		169		1
Total regulatory assets	$	45,515	$	110,566	$	57,143	$	95,633
Regulatory liabilities:
RSE adjustment	$	1,740	$	—	$	2,931	$	—
Unbilled service margin	25,078		—		22,419		—
Postretirement liabilities	—		1,237		—		—
Gas supply adjustment	—		—		12,626		—
Refundable negative salvage	18,265		53,467		20,269		65,646
Asset retirement obligation	—		24,930		—		20,785
Other	33		770		34		803
Total regulatory liabilities	$	45,116	$	80,404	$	58,279	$	87,234

As described in Note 2, Regulatory Matters, Alagasco's rates are established under the RSE rate-setting process and are based on average equity for the period. Alagasco's rates are not adjusted to exclude a return on its investment in regulatory assets during the recovery period.

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Financial Instruments and Risk Management (Tables)

12 Months Ended

Dec. 31, 2012

Derivative [Line Items]

Schedule of changes in allowance for credit losses on Financing Receivables

The following table sets forth a summary of changes in the allowance for credit losses as follows:

(in thousands)
Allowance for credit losses as of December 31, 2010	$	447
Provision	(26		)
Allowance for credit losses as of December 31, 2011	421
Provision	49
Allowance for credit losses as of December 31, 2012	$	470

Schedule of fair values of commodity contracts by business segment on balance sheet

The following table details the fair values of commodity contracts by business segment on the balance sheets:

(in thousands)	December 31, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	87,514			$	—		$	87,514
Long-term asset derivative instruments	37,954				—			37,954
Total derivative assets	125,468				—			125,468
Accounts receivable	(37,326		)	*	—			(37,326		)
Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
Long-term liability derivative instruments	(8,726		)		—			(8,726		)
Total derivative liabilities	(52,862		)		—			(52,862		)
Total derivatives designated	72,606				—			72,606
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,604				—			14,604
Long-term asset derivative instruments	9,433				—			9,433
Total derivative assets	24,037				—			24,037
Accounts payable	—				(2,593		)	(2,593		)
Long-term liability derivative instruments	(874		)		—			(874		)
Total derivative liabilities	(874		)		(2,593		)	(3,467		)
Total derivatives not designated	23,163				(2,593		)	20,570
Total derivatives	$	95,769			$	(2,593	)	$	93,176

(in thousands)	December 31, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	73,636			$	—		$	73,636
Long-term asset derivative instruments	75,982				—			75,982
Total derivative assets	149,618				—			149,618
Accounts receivable	(48,174		)	*	—			(48,174		)
Long-term asset derivative instruments	(36,341		)	*	—			(36,341		)
Accounts payable	(37,070		)		—			(37,070		)
Long-term liability derivative instruments	(20,386		)		—			(20,386		)
Total derivative liabilities	(141,971		)		—			(141,971		)
Total derivatives designated	7,647				—			7,647
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(3,670		)	*	—			(3,670		)
Long-term asset derivative instruments	(8,585		)	*	—			(8,585		)
Total derivative assets	(12,255		)		—			(12,255		)
Accounts payable	(13,416		)		(56,804		)	(70,220		)
Long-term liability derivative instruments	(10,922		)		(3,070		)	(13,992		)
Total derivative liabilities	(24,338		)		(59,874		)	(84,212		)
Total derivatives not designated	(36,593		)		(59,874		)	(96,467		)
Total derivatives	$	(28,946	)		$	(59,874	)	$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

Schedule of cash flow hedging relationships on financial statements

The following table details the effect of derivative commodity instruments designated as hedging instruments on the financial statements:

Years ended December 31, (in thousands)	Location on Income Statement	2012			2011			2010
Net gain recognized in OCI on derivative (effective portion), net of tax of $40.7 million, $41.4 million and $19.5 million	—	$	66,438		$	67,547		$	31,801
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	52,694		$	26,326		$	200,324
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(5,340	)	$	(2,767	)	$	1,082

Schedule of derivatives not designated as hedging instruments on income statements

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

Years ended December 31, (in thousands)	Location on Income Statement	2012		2011			2010
Gain (loss) recognized in income on derivative	Operating revenues	$	61,841	$	(37,587	)	$	(3	)

Schedule of hedging transactions

As of December 31, 2012, Energen Resources entered into the following transactions for 2013 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Oil
2013	8,858	MBbl	$90.95 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
Oil Basis Differential
2013	3,592	MBbl	$(3.03) Bbl	WTS/WTI Basis Swaps*
	2,760	MBbl	$(1.01) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Schedule of fair value, assets and liabilities measured on recurring basis

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	December 31, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(3,629	)	$	68,421		$	64,792
Noncurrent assets	18,899			21,678			40,577
Current liabilities	(2,593		)	—			(2,593		)
Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
Net derivative asset	$	4,157		$	89,019		$	93,176

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

Schedule of changes in fair value of derivative instruments classified as level 3

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

Years ended December 31, (in thousands)	2012			2011			2010
Balance at beginning of period	$	65,801		$	42,755		$	64,517
Realized gains (losses)	63,720			52,716			111,107
Unrealized gains relating to instruments held at the reporting date*	22,160			23,980			(21,521		)
Purchases and settlements during period	(62,662		)	(53,650		)	(111,348		)
Balance at end of period	$	89,019		$	65,801		$	42,755

Schedule of level three fair value measurements of derivative commodity instruments

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

(in thousands)	Fair Value as of December 31, 2012			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	38,254		Discounted Cash Flow	Forward Basis	($0.15 - $0.16) Mcf
2014	$	21,100		Discounted Cash Flow	Forward Basis	($0.13 - $0.17) Mcf
Natural Gas Basis - Permian
2013	$	160		Discounted Cash Flow	Forward Basis	($0.13) Mcf
2014	$	(871	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.13) Mcf
Oil Basis - WTS/WTI
2013	$	10,338		Discounted Cash Flow	Forward Basis	($5.19) Bbl
Oil Basis - WTI/WTI
2013	$	8,217		Discounted Cash Flow	Forward Basis	($2.92 - $3.62) Bbl
Natural Gas Liquids
2013	$	11,821		Discounted Cash Flow	Forward Price	$0.73 - $0.82 Gal

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

Alabama Gas Corporation

Derivative [Line Items]

Schedule of hedging transactions

Alagasco entered into the following natural gas transactions for 2013:

Production Period	Total Hedged Volumes	Description
2013	1.5 Bcf	NYMEX Swaps

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Oil and Gas Operations (Unaudited) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Proved	$ 6,241,148	$ 4,927,576
Unproved	197,979	238,792
Total capitalized costs	6,439,127	5,166,368
Accumulated depreciation, depletion and amortization	1,765,241	1,382,526
Capitalized costs, net	$ 4,673,886	$ 3,783,842

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Recently Issued Accounting Standards

12 Months Ended

Dec. 31, 2012

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recently Issued Accounting Standards

RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The Company is currently evaluating the impact of the ASU but does not expect this update to have a material impact on its results of operations. In January 2013, the FASB issued Accounting Standard Update (ASU) No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remain unchanged.

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. This update requires entities to present the components of net income and other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. This amendment was effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Adoption of this update did not have a material impact on the consolidated financial statements or results of operations.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment is effective for annual and interim reporting periods beginning after December 15, 2012. The Company is currently evaluating the impact of the ASU but does not expect this update to have a material impact on its consolidated financial statements or results of operations.

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirement in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments in this update result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRSs. The amendments are effective during interim and annual periods beginning after December 15, 2011. This standard did not have a material impact on the consolidated condensed financial statements of the Company. The additional fair value disclosures are included in Note 8, Financial Instruments.

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Common Stock Plans (Stock Incentive Plan) (Details) (Stock Incentive Plan)	Dec. 31, 2012	Apr. 27, 2011
Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for issuance		8,600,000
Number of shares remaining for issuance	3,418,881

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (USD $) In Thousands, except Share data, unless otherwise specified	Total	Common Stock	Premimum on Capital Stock [Member]	Capital Surplus [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Deferred Compensation Plan	Treasury Stock	Alabama Gas Corporation	Alabama Gas Corporation Common Stock	Alabama Gas Corporation Premimum on Capital Stock [Member]	Alabama Gas Corporation Capital Surplus [Member]	Alabama Gas Corporation Retained Earnings [Member]
BALANCE at Dec. 31, 2009	$ 1,988,243	$ 746	$ 461,661	$ 2,802	$ 1,626,753	$ 17,615	$ 3,121	$ (124,455)	$ 317,803	$ 20	$ 31,682	$ 2,802	$ 283,299
BALANCE, shares at Dec. 31, 2009		74,593,431								1,972,052
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	290,807				290,807				46,883				46,883
Comprehensive Income	(92,012)					(92,012)
Purchase of treasury shares, net	(2,893)							(2,893)
Shares issued for employee benefit plans, shares		192,945
Shares issued for employee benefit plans	6,451	2	6,449
Deferred compensation obligation	0						167	(167)
Stock based compensation	(83)		(83)
Tax benefit from employee stock plans	907		907
Cash dividends, per share - ($0.50 in 2009, $0.52 in 2010, $0.54 in 2011)	(37,377)				(37,377)				(37,367)				(37,367)
BALANCE at Dec. 31, 2010	2,154,043	748	468,934	2,802	1,880,183	(74,397)	3,288	(127,515)	327,319	20	31,682	2,802	292,815
BALANCE, shares at Dec. 31, 2010		74,786,376								1,972,052
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	94,268								44,175
BALANCE at Mar. 31, 2011
BALANCE at Dec. 31, 2010	2,154,043	748	468,934	2,802	1,880,183	(74,397)	3,288	(127,515)	327,319	20	31,682	2,802	292,815
BALANCE, shares at Dec. 31, 2010		74,786,376								1,972,052
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	259,624				259,624				46,602				46,602
Comprehensive Income	44,145					44,145
Purchase of treasury shares, net	(713)							(713)
Shares issued for employee benefit plans, shares		221,036
Shares issued for employee benefit plans	7,237	2	7,235
Deferred compensation obligation	0						223	(223)
Stock based compensation	5,763		5,763
Tax benefit from employee stock plans	986		986
Cash dividends, per share - ($0.50 in 2009, $0.52 in 2010, $0.54 in 2011)	(38,922)				(38,922)				(29,183)				(29,183)
BALANCE at Dec. 31, 2011	2,432,163	750	482,918	2,802	2,100,885	(30,252)	3,511	(128,451)	344,738	20	31,682	2,802	310,234
BALANCE, shares at Dec. 31, 2011	75,007,412	75,007,412							1,972,052	1,972,052
BALANCE at Sep. 30, 2011
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	14,432								11,258
BALANCE at Dec. 31, 2011	2,432,163			2,802					344,738	20	31,682	2,802
BALANCE, shares at Dec. 31, 2011	75,007,412								1,972,052	1,972,052
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	57,406								46,918
BALANCE at Mar. 31, 2012
BALANCE at Dec. 31, 2011	2,432,163	750	482,918	2,802	2,100,885	(30,252)	3,511	(128,451)	344,738	20	31,682	2,802	310,234
BALANCE, shares at Dec. 31, 2011	75,007,412	75,007,412							1,972,052	1,972,052
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	253,562				253,562				49,402				49,402
Comprehensive Income	21,941					21,941
Purchase of treasury shares, net	(277)							(277)
Shares issued for employee benefit plans, shares		60,348
Shares issued for employee benefit plans	2,061	1	2,060
Deferred compensation obligation	0						(737)	737
Stock based compensation	7,082		6,580					502
Tax benefit from employee stock plans	550		550
Cash dividends, per share - ($0.50 in 2009, $0.52 in 2010, $0.54 in 2011)	(40,392)				(40,392)				(33,637)				(33,637)
BALANCE at Dec. 31, 2012	2,676,690	751	492,108	2,802	2,314,055	(8,311)	2,774	(127,489)	360,503	20	31,682	2,802	325,999
BALANCE, shares at Dec. 31, 2012	75,067,760	75,067,760							1,972,052	1,972,052
BALANCE at Sep. 30, 2012
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	62,823								12,197
BALANCE at Dec. 31, 2012	$ 2,676,690			$ 2,802					$ 360,503	$ 20	$ 31,682	$ 2,802
BALANCE, shares at Dec. 31, 2012	75,067,760								1,972,052	1,972,052

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net Income	$ 253,562	$ 259,624	$ 290,807
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $100, $96 and $98, respectively	186	177	182
Amortization of prior service cost, net of taxes of $119, $104 and $104, respectively	221	194	194
Amortization of net loss, net of taxes of $1,676, $1,270 and $1,152, respectively	3,113	2,359	2,139
Current period change in fair value of pension and postretirement plans, net of taxes of ($9,393), ($5,699), and ($783), respectively	(17,443)	(10,584)	(1,455)
Total pension and postretirement plans	(13,923)	(7,854)	1,060
Comprehensive Income	275,503	303,769	198,795
Commodity Contract
Other comprehensive income (loss):
Reclassification adjustment for derivative instruments, net of tax	(29,359)	(14,607)	(124,873)
Pension and postretirement plans:
Reclassification adjustment for derivative instruments, net of tax	66,438	67,547	31,801
Interest Rate Swap
Other comprehensive income (loss):
Reclassification adjustment for derivative instruments, net of tax	1,066	0	0
Pension and postretirement plans:
Reclassification adjustment for derivative instruments, net of tax	$ (2,281)	$ (941)	$ 0

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Financial Instruments and Risk Management

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Financial Instruments and Risk Management

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Financial Instruments: The stated value of cash and cash equivalents, short-term investments, trade 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, approximates $1,255.8 million and $1,214.9 million and has a carrying value of $1,154.0 million and $1,155.2 million at December 31, 2012 and 2011, respectively. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $284.7 million and $274.9 million and has a carrying value of $250.0 million and $250.2 million at December 31, 2012 and 2011, 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.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers' current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At December 31, 2012, the fixed price purchases under these guarantees had a maximum term outstanding through March 2013 with an aggregate purchase price of $0.3 million and a market value of $0.3 million.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At December 31, 2012 and 2011, Alagasco’s finance receivable totaled approximately $10.7 million and $10.5 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.5 million and $0.4 million as of December 31, 2012 and 2011, respectively.

The following table sets forth a summary of changes in the allowance for credit losses as follows:

(in thousands)
Allowance for credit losses as of December 31, 2010	$	447
Provision	(26		)
Allowance for credit losses as of December 31, 2011	421
Provision	49
Allowance for credit losses as of December 31, 2012	$	470

Risk Management: At December 31, 2012, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with twelve of its active counterparties and in a net loss position with the remaining two at December 31, 2012. The four largest counterparty net gain positions at December 31, 2012, Macquarie Bank Limited, J Aron & Company, BP Corporation North America Inc. and Shell Energy North America (US), L.P., constituted approximately $20.0 million, $16.6 million, $13.6 million and $10.3 million gain, respectively, of Energen Resources' net gain on fair value of derivatives.

The following table details the fair values of commodity contracts by business segment on the balance sheets:

(in thousands)	December 31, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	87,514			$	—		$	87,514
Long-term asset derivative instruments	37,954				—			37,954
Total derivative assets	125,468				—			125,468
Accounts receivable	(37,326		)	*	—			(37,326		)
Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
Long-term liability derivative instruments	(8,726		)		—			(8,726		)
Total derivative liabilities	(52,862		)		—			(52,862		)
Total derivatives designated	72,606				—			72,606
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,604				—			14,604
Long-term asset derivative instruments	9,433				—			9,433
Total derivative assets	24,037				—			24,037
Accounts payable	—				(2,593		)	(2,593		)
Long-term liability derivative instruments	(874		)		—			(874		)
Total derivative liabilities	(874		)		(2,593		)	(3,467		)
Total derivatives not designated	23,163				(2,593		)	20,570
Total derivatives	$	95,769			$	(2,593	)	$	93,176

(in thousands)	December 31, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	73,636			$	—		$	73,636
Long-term asset derivative instruments	75,982				—			75,982
Total derivative assets	149,618				—			149,618
Accounts receivable	(48,174		)	*	—			(48,174		)
Long-term asset derivative instruments	(36,341		)	*	—			(36,341		)
Accounts payable	(37,070		)		—			(37,070		)
Long-term liability derivative instruments	(20,386		)		—			(20,386		)
Total derivative liabilities	(141,971		)		—			(141,971		)
Total derivatives designated	7,647				—			7,647
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(3,670		)	*	—			(3,670		)
Long-term asset derivative instruments	(8,585		)	*	—			(8,585		)
Total derivative assets	(12,255		)		—			(12,255		)
Accounts payable	(13,416		)		(56,804		)	(70,220		)
Long-term liability derivative instruments	(10,922		)		(3,070		)	(13,992		)
Total derivative liabilities	(24,338		)		(59,874		)	(84,212		)
Total derivatives not designated	(36,593		)		(59,874		)	(96,467		)
Total derivatives	$	(28,946	)		$	(59,874	)	$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

The Company had a net $28.4 million and a net $5.7 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in other comprehensive income as of December 31, 2012 and 2011, respectively.

The following table details the effect of derivative commodity instruments designated as hedging instruments on the financial statements:

Years ended December 31, (in thousands)	Location on Income Statement	2012			2011			2010
Net gain recognized in OCI on derivative (effective portion), net of tax of $40.7 million, $41.4 million and $19.5 million	—	$	66,438		$	67,547		$	31,801
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	52,694		$	26,326		$	200,324
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(5,340	)	$	(2,767	)	$	1,082

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

Years ended December 31, (in thousands)	Location on Income Statement	2012		2011			2010
Gain (loss) recognized in income on derivative	Operating revenues	$	61,841	$	(37,587	)	$	(3	)

As of December 31, 2012, $32.7 million of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, net of tax, are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of December 31, 2012, the Company had 5.6 billion and 9.7 billion cubic feet (Bcf) of natural gas hedges which expire during 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 9.7 million and 5.4 million barrels (MMBbl) of oil and oil basis hedges which expire during 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2013 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. During 2011, the Company had a discontinuance of hedge accounting when Energen Resources determined it was probable certain forecasted volumes would not occur, which resulted in $63,000 after-tax gain being recognized into operating revenues during the year ended December 31, 2012.

As of December 31, 2012, Energen Resources entered into the following transactions for 2013 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Oil
2013	8,858	MBbl	$90.95 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
Oil Basis Differential
2013	3,592	MBbl	$(3.03) Bbl	WTS/WTI Basis Swaps*
	2,760	MBbl	$(1.01) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Alagasco entered into the following natural gas transactions for 2013:

Production Period	Total Hedged Volumes	Description
2013	1.5 Bcf	NYMEX Swaps

As of December 31, 2012, the maximum term over which Energen Resources and Alagasco has hedged exposures to the variability of cash flows is through December 31, 2014 and March 31, 2013, respectively. Alagasco has not entered into any new cash flow derivative transactions on its gas supply since 2010. 

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	December 31, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(3,629	)	$	68,421		$	64,792
Noncurrent assets	18,899			21,678			40,577
Current liabilities	(2,593		)	—			(2,593		)
Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
Net derivative asset	$	4,157		$	89,019		$	93,176

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. As of December 31, 2011, Alagasco had $56.8 million and $3.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012 and 2011.

The Company 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 derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $27 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $2.5 million associated with open Level 3 mark-to-market derivative contracts. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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

Years ended December 31, (in thousands)	2012			2011			2010
Balance at beginning of period	$	65,801		$	42,755		$	64,517
Realized gains (losses)	63,720			52,716			111,107
Unrealized gains relating to instruments held at the reporting date*	22,160			23,980			(21,521		)
Purchases and settlements during period	(62,662		)	(53,650		)	(111,348		)
Balance at end of period	$	89,019		$	65,801		$	42,755

*Includes $19.9 million in mark-to-market gains and $5.2 million in mark-to-market losses for the years ended December 31, 2012 and 2011, respectively. There were no Level 3 mark-to-market gains or losses for the year ended December 31, 2010.

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

(in thousands)	Fair Value as of December 31, 2012			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	38,254		Discounted Cash Flow	Forward Basis	($0.15 - $0.16) Mcf
2014	$	21,100		Discounted Cash Flow	Forward Basis	($0.13 - $0.17) Mcf
Natural Gas Basis - Permian
2013	$	160		Discounted Cash Flow	Forward Basis	($0.13) Mcf
2014	$	(871	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.13) Mcf
Oil Basis - WTS/WTI
2013	$	10,338		Discounted Cash Flow	Forward Basis	($5.19) Bbl
Oil Basis - WTI/WTI
2013	$	8,217		Discounted Cash Flow	Forward Basis	($2.92 - $3.62) Bbl
Natural Gas Liquids
2013	$	11,821		Discounted Cash Flow	Forward Price	$0.73 - $0.82 Gal

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

Concentration of Credit Risk:Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil 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 the Company's overall exposure to credit risk, either positively or negatively, in that the Company's oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources 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 oil and gas purchasers accounted for approximately 29 percent and 13 percent of Energen Resources’ accounts receivable for commodity sales as of December 31, 2012. Energen Resources’ other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2012. During the year ended December 31, 2012, the two largest oil and gas purchasers accounted for approximately 27 percent and 12 percent of Energen Resources’ total operating revenues.

Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 425,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.

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Oil and Gas Operations (Unaudited) (Standardized Measure of Discounted Future Net Cash Flows) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Deferred hedgin gain (loss) excluded from calculation of standardized measure of future net cash flows	$ 74,800,000	$ 15,000,000	$ 70,400,000
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future gross revenues	17,735,363,000	18,196,229,000	13,210,211,000
Future production costs	5,715,248,000	5,823,395,000	4,959,403,000
Future development costs	1,892,600,000	1,539,072,000	1,026,903,000
Future income tax expense	2,809,411,000	3,326,382,000	2,201,742,000
Future net cash flows	7,318,104,000	7,507,380,000	5,022,163,000
Discount at 10% per annum	3,618,785,000	3,878,217,000	2,555,027,000
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	3,699,319,000	3,629,163,000	2,467,136,000
Discounted future net cash flows before income taxes	4,411,399,000	4,691,086,000	3,155,746,000
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Balance at beginning of year	3,629,163,000	2,467,136,000	1,563,190,000
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(922,792,000)	707,411,000	945,179,000
Net changes due to revisions in quantity estimates	(383,755,000)	(80,004,000)	36,349,000
Development costs incurred, previously estimated	472,603,000	392,720,000	195,269,000
Accretion of discount	362,916,000	246,714,000	156,319,000
Changes in timing and other	(317,244,000)	(25,937,000)	15,815,000
Total revisions	(788,272,000)	1,240,904,000	1,348,931,000
New field discoveries and extensions, net of future production and development costs	1,025,419,000	755,977,000	319,223,000
Sales of oil and gas produced, net of production costs	(812,781,000)	(763,171,000)	(576,755,000)
Purchases	189,755,000	232,768,000	278,384,000
Sales	0	0	87,000
Net change in income taxes	456,035,000	(304,451,000)	(465,924,000)
Net change in standardized measure of discounted future net cash flows	70,156,000	1,162,027,000	903,946,000
Balance at end of year	$ 3,699,319,000	$ 3,629,163,000	$ 2,467,136,000

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Supplemental Cash Flow Information (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental Cash Flow Information [Line Items]
Interest paid, net of amount capitalized	$ 61,379	$ 33,601	$ 37,517
Income taxes paid	17,170	9,432	83,894
Noncash investing activities:
Accrued development, exploration costs and other capital	120,024	72,030	75,167
Capitalized depreciation	80	93	116
Capitalized asset retirement obligations costs	4,409	4,927	4,194
Allowance for funds used during construction	623	807	808
Capital lease obligations	5,072	0	0
Issuance of common stock for employee benefit plans	838	822	5,765
Treasury stock acquired in connection with tax withholdings	277	713	2,894
Accretion expense	7,534	6,837	6,178
Alabama Gas Corporation
Supplemental Cash Flow Information [Line Items]
Interest paid, net of amount capitalized	13,513	12,385	11,653
Income taxes paid	16,796	5,143	13,063
Interest on affiliated company debt, net	295	376	274
Noncash investing activities:
Accrued development, exploration costs and other capital	3,536	2,229	2,592
Capitalized depreciation	80	93	116
Capitalized asset retirement obligations costs	415	300	161
Allowance for funds used during construction	$ 623	$ 807	$ 808

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Reconciliation of Earnings Per Share (Antidilutive Securities) (Details) (Stock options)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of diluted EPS (in options or shares)	849,583	293,978	479,820

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Document and Entity Information Document (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Feb. 15, 2013	Jun. 30, 2012
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Entity Registrant Name	ENERGEN CORP
Entity Central Index Key	0000277595
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		72,222,552
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 3,193,878
Alabama Gas Corporation
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Entity Registrant Name	ALABAMA GAS CORP
Entity Central Index Key	0000003146
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,972,052

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Reconciliation of Earnings Per Share

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Reconciliation of Earnings Per Share

RECONCILIATION OF EARNINGS PER SHARE

Years ended December 31,
(in thousands, except per share amounts)			2012					2011					2010
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	253,562	72,119	$	3.52	$	259,624	72,056	$	3.60	$	290,807	71,845	$	4.05
Effect of dilutive securities
Stock options			196					270					190
Non-vested restricted stock			1					6					16
Diluted EPS	$	253,562	72,316	$	3.51	$	259,624	72,332	$	3.59	$	290,807	72,051	$	4.04

For the years ended December 31, 2012, 2011 and 2010, the Company had 849,583, 293,978 and 479,820 options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the years ended December 31, 2012, 2011 and 2011, the Company had no shares of non-restricted stock that were excluded from the computation of diluted EPS.

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Commitments and Contingencies (Legal Matters and New Mexico Audits) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012
Pending or threatened legal proceedings
Loss Contingencies [Line Items]
Accrued provision for estimated liability	$ 100,000
Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Order for payment of additional royalties	142,000
Preliminary estimates of order maximum liabilities for additional royalties	$ 23,000,000
Loss contingency, inestimable loss description	The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department's findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of December 31, 2011.

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Reconciliation of Earnings Per Share (Reconciliation) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share Reconciliation
Net Income, Basic EPS	$ 62,823	$ 2,046	$ 131,287	$ 57,406	$ 14,432	$ 87,599	$ 63,325	$ 94,268	$ 253,562	$ 259,624	$ 290,807
Basic Shares Oustanding (in shares)									72,119,021	72,055,661	71,845,463
Earnings Per Share, Basic (dollars per share)	$ 0.87	$ 0.03	$ 1.82	$ 0.80	$ 0.20	$ 1.22	$ 0.88	$ 1.31	$ 3.52	$ 3.60	$ 4.05
Effect of dilutive securities
Net Income, Diluted EPS	$ 62,823	$ 2,046	$ 131,287	$ 57,406	$ 14,432	$ 87,599	$ 63,325	$ 94,268	$ 253,562	$ 259,624	$ 290,807
Diluted Shares Outstanding (in shares)									72,316,214	72,332,369	72,050,997
Earnings Per Share, Diluted (dollars per share)	$ 0.87	$ 0.03	$ 1.82	$ 0.79	$ 0.20	$ 1.21	$ 0.87	$ 1.30	$ 3.51	$ 3.59	$ 4.04
Stock options
Effect of dilutive securities
Incremental Common Shares Attributable to Share-based Payment Arrangements									196,000	270,000	190,000
Non-vested restricted stock
Effect of dilutive securities
Incremental Common Shares Attributable to Share-based Payment Arrangements									1,000	6,000	16,000

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Amortization of net obligation at transition, tax	$ 100	$ 96	$ 98
Amortization of prior service cost, tax	119	104	104
Amortization of net loss, tax	1,676	1,270	1,152
Current period change in fair value of pension and postretirement plans, tax	(9,393)	(5,699)	(783)
Commodity Contract
Reclassification adjustment for derivative instruments, tax	(17,994)	(8,953)	(76,535)
Current period change in fair value of interest rate swap, tax	40,720	41,399	19,491
Interest Rate Swap
Reclassification adjustment for derivative instruments, tax	574	0	0
Current period change in fair value of interest rate swap, tax	$ (1,228)	$ (507)	$ 0

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Long-Term Debt and Notes Payable

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Long-Term Debt and Notes Payable

LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:

(in thousands)	December 31, 2012		December 31, 2011
Energen Corporation:
Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.6%, for notes due July 24, 2017 to February 15, 2028	$	154,000	$	155,000
5% Notes, due October 1, 2013	50,000		50,000
4.625% Notes, due September 1, 2021	400,000		400,000
Senior Term Loans, (floating rate interest LIBOR plus 1.375%; 1.59% at December 31, 2012), due March 31, 2014 to November 29, 2016	300,000		300,000
Alabama Gas Corporation:
5.20% Notes, due January 15, 2020	40,000		40,000
5.70% Notes, due January 15, 2035	35,028		35,246
5.368% Notes, due December 1, 2015	80,000		80,000
5.90% Notes, due January 15, 2037	45,000		45,000
3.86% Notes, due December 21, 2021	50,000		50,000
Total	1,154,028		1,155,246
Less amounts due within one year	50,000		1,000
Less unamortized debt discount	500		546
Total	$	1,103,528	$	1,153,700

The aggregate maturities of Energen's long-term debt for the next five years are as follows:

Years ending December 31, (in thousands)
2013	2014	2015	2016	2017
$50,000	$100,000	$180,000	$100,000	$19,000

The aggregate maturities of Alagasco's long-term debt for the next five years are as follows:

Years ending December 31, (in thousands)
2013	2014	2015	2016	2017
—	—	$80,000	—	—

In August 2011, the Company issued $400 million in Senior Notes with an interest rate of 4.625 percent due September 1, 2021. In November 2011, the Company issued $300 million in Senior Term Loans (Senior Term Loans) with a floating interest rate due March 31, 2014 through November 29, 2016. The Company used the long-term debt proceeds to replace short-term obligations, enhance liquidity and to finance the property acquisition program at Energen Resources. In December 2011, Alagasco issued $50 million of long-term debt with an interest rate of 3.86 percent due December 21, 2021 to replace short-term obligations.

In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company's interest rate swap was a $3.3 million and a $1.5 million liability at December 31, 2012 and 2011, respectively, and is classified as a Level 2 fair value.

The long-term debt and short-term debt agreements of Energen and Alagasco 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 covenants or events of default based on credit ratings, the interest rates applicable to the Senior Term Loans and the Energen and Alagasco syndicated credit facilities discussed below may adjust based on credit rating changes. All of the Company's debt is unsecured; however, approximately $4 million of the Company's indebtedness is effectively secured through a sale-leaseback arrangement.

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, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s Indenture dated November 1, 1993 with The Bank of New York as Trustee, a cross default provision provides that any debt default by Alagasco of more than $10 million will constitute an event of default by Alagasco. Neither Indenture includes a restriction on the payment of dividends.

Energen and Alagasco Credit Facilities: On October 30, 2012, Energen and Alagasco entered into $1,250 million and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. These syndicated credit facilities replace Energen's $850 million and Alagasco's $150 million three-year syndicated credit facilities. Borrowings under these credit facilities are subject to the execution of individual note agreements each with maturity dates of less than one year. Accordingly, outstanding amounts due under these credit facilities are classified as short term obligations in the accompanying consolidated financial statements. Alagasco has been authorized by the APSC to borrow up to $200 million at any one time under the short-term credit facilities.

Energen’s obligations under the $1,250 million syndicated credit facility are unconditionally guaranteed by Energen Resources. The financial covenants of the Energen credit facility limit Energen to a maximum consolidated debt to capitalization ratio of no more than 65 percent as of the end of any fiscal quarter. Energen may not pay dividends during an event of default or if the payment would result in an event of default.

Similarly, the financial covenants of the Alagasco credit facility limit Alagasco to a maximum consolidated debt to capitalization ratio of no more than 65 percent as of the end of any fiscal quarter. Alagasco may not pay dividends during an event of default or if the payment would result in an event of default.

Under the Energen credit facility, a cross default provision provides that any debt default of more than $50 million by Energen, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s credit facility, a cross default provision provides that any debt default by Alagasco of more than $50 million will constitute an event of default by Alagasco.

Upon an uncured event of default under either of the credit facilities, all amounts owing under the defaulted 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 and Alagasco were in compliance with the terms of their respective credit facilities as of December 31, 2012.

The following is a summary of information relating to the credit facilities:

(in thousands)	December 31, 2012			December 31, 2011
Energen outstanding	$	566,000		$	—
Alagasco outstanding	77,000			15,000
Notes payable to banks	643,000			15,000
Available for borrowings	707,000			1,004,000
Total	$	1,350,000		$	1,019,000
Energen maximum amount outstanding at any month-end	$	643,000		$	363,000
Energen average daily amount outstanding	$	331,068		$	229,094
Energen weighted average interest rates based on:
Average daily amount outstanding	1.82		%	2.04		%
Amount outstanding at year-end	1.35		%	3.58		%
Alagasco maximum amount outstanding at any month-end	$	77,000		$	70,000
Alagasco average daily amount outstanding	$	21,254		$	29,268
Alagasco weighted average interest rates based on:
Average daily amount outstanding	1.44		%	1.72		%
Amount outstanding at year-end	1.11		%	3.58		%

Energen's total interest expense was $65.6 million, $44.8 million and $39.2 million for the years ended December 31, 2012, 2011 and 2010, respectively. Energen's total interest expense for the year ended December 31, 2012 included capitalized interest expense of $0.5 million. Total interest expense for Alagasco was $16.3 million, $14.7 million and $13.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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Regulatory Matters

12 Months Ended

Dec. 31, 2012

Regulated Operations [Abstract]

Regulatory Matters

REGULATORY MATTERS

Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period through December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for Securities and Exchange Commission reporting purposes.

Alagasco's allowed range of return on average common equity is 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the years ended December 31, 2012, 2011 and 2010, Alagasco had net pre-tax reductions in revenues of $6.3 million, $6.7 million and $17.4 million, respectively, to bring the return on average equity to midpoint within the allowed range of return. Under the provisions of RSE, a $7.8 million annual increase, $13.0 million annual increase and $1.3 million annual decrease in revenues became effective December 1, 2012, 2011, and 2010, respectively.

RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. In the rate year ended September 30, 2010, $2.5 million of extraordinary bad debt expense was excluded from the CCM calculation.  Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2012, 2011 and 2010.

Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

The APSC approved an Enhanced Stability Reserve in 1998 which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year.

Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco anticipates recovering underfunded ESR balances over a five year amortization period with an annual limitation of $660,000. Amounts in excess of this limitation are deferred for recovery in future years.

The excess of total acquisition costs over book value of net assets of acquired municipal gas distribution systems is included in utility plant and is being amortized through Alagasco's rate-setting mechanism on a straight-line basis with a weighted average remaining life of approximately 13 years. At December 31, 2012 and 2011, the net unamortized acquisition adjustments were $3.8 million and $4.4 million, respectively.

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Transactions with Related Parties

12 Months Ended

Dec. 31, 2012

Due to Related Parties [Abstract]

Transactions with Related Parties

TRANSACTIONS WITH RELATED PARTIES

The Company allocates certain corporate costs to Energen Resources and Alagasco based on the nature of the expense to be allocated using various factors including, but not limited to, total assets, earnings, or number of employees. The Company's cash management program seeks to minimize borrowing from outside sources through inter-company lending. Under this program, Alagasco may borrow from but does not lend to affiliates. Alagasco had net trade receivables from affiliates of $5.7 million and $2.8 million at December 31, 2012 and 2011, respectively. Interest income and expense between affiliates is calculated monthly based on the market weighted average interest rate. Alagasco had $0.3 million, $0.4 million and $0.3 million in affiliated company interest expense during the years ended December 31, 2012, 2011 and 2010, respectively.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the period incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company. Revisions in estimates to the ARO result from revisions to the estimated timing or amount of the underlying cash flows. In 2012, 2011 and 2010, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2009	$	88,298
Liabilities incurred	4,033
Liabilities settled	(1,094		)
Accretion expense	6,178
Balance of ARO as of December 31, 2010	97,415
Liabilities incurred	4,627
Liabilities settled	(1,539		)
Accretion expense	6,837
Balance of ARO as of December 31, 2011	107,340
Liabilities incurred	3,994
Liabilities settled	(845		)
Accretion expense	7,534
Balance of ARO as of December 31, 2012	$	118,023

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $24.9 million and $20.8 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of December 31, 2012 and 2011, respectively. Regulatory assets for accumulated asset removal costs of $3.3 million and $1.0 million as of December 31, 2012 and 2011, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

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Financial Instruments and Risk Management (Derivative Instruments by Income Statement Location) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Tax	$ 40,720,000	$ 41,399,000	$ 19,491,000
Deferred net gains (losses) on derivative instruments recoreded in AOCI, net of tax, expected to be reclasses during next 12 months	(32,700,000)
Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Net gain recognized in OCI on derivative (effective portion), net of tax of $40.7 million, $41.4 million and $19.5 million	66,438,000	67,547,000	31,801,000
Designated as Hedging Instrument | Operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain reclassified from accumulated OCI into income (effective portion)	52,694,000	26,326,000	200,324,000
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	(5,340,000)	(2,767,000)	1,082,000
Not Designated as Hedging Instrument | Operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on derivative	$ 61,841,000	$ (37,587,000)	$ (3,000)

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Common Stock Plans

12 Months Ended

Dec. 31, 2012

Share-based Compensation [Abstract]

Common Stock Plans

COMMON STOCK PLANS

Energen Employee Savings Plan (ESP): A majority of Company employees are eligible to participate in the ESP by electing to contribute a portion of their compensation to the ESP. The Company may match a percentage of the contributions and make these contributions in Company common stock or in funds for the purchase of Company common stock. Employees may diversify 100 percent of their ESP Company stock account into other ESP investment options. The ESP also contains employee stock ownership plan provisions. At December 31, 2012, total shares reserved for issuance equaled 1,080,108. Expense associated with Company contributions to the ESP was $7.8 million, $6.8 million and $6.2 million for the years ended December 31, 2012, 2011 and 2010, 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. The Company 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 Company common stock were reserved for issuance with 3,418,881 remaining for issuance as of December 31, 2012.

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 Company 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 Company common stock.

No performance share awards were granted in 2012, 2011 or 2010. A summary of performance share award activity is presented below:

	Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2009	111,143		$	43.81
Vested and paid	(111,143	)	43.81
Nonvested at December 31, 2010	—		$	—

During the years ended December 31, 2012, 2011 and 2010, the Company recorded no expense for performance share awards.

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 Company common stock at not less than the fair market value on the date the option is 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, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 are presented below:

	Stock Incentive Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2009	1,107,809		$	36.83
Granted	281,110		46.69
Exercised	(111,676	)	23.83
Forfeited	(1,200	)	13.72
Outstanding at December 31, 2010	1,276,043		40.16
Granted	293,978		54.99
Exercised	(227,405	)	32.33
Forfeited	(4,375	)	35.35
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
Exercisable at December 31, 2010	574,992		$	41.16
Exercisable at December 31, 2011	677,753		$	43.72
Exercisable at December 31, 2012	987,733		$	43.75
Remaining reserved for issuance at December 31, 2012	3,418,881		—

The Company 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	1/25/2012		1/26/2011		1/27/2010
Awards granted	371,040		293,978		281,110
Fair market value of stock option at grant	$18.79		$19.65		$16.47
Expected life of award	5.8 years		5.8 years		5.7 years
Risk-free interest rate	1.07	%	2.45	%	2.76	%
Annualized volatility rate	39.6	%	37.8	%	37.3	%
Dividend yield	1.0	%	1.0	%	1.1	%

The Company recorded stock option expense of $7.0 million, $5.6 million and $4.6 million during the years ended December 31, 2012, 2011 and 2010, respectively, with a related deferred tax benefit of $2.6 million, $2.1 million and $1.7 million respectively.

The total intrinsic value of stock options exercised during the year ended December 31, 2012, was $1.1 million. During the year ended December 31, 2012, the Company received cash of $1.5 million from the exercise of stock options and paid $1.8 million in settlement of stock appreciation rights. Total intrinsic value for outstanding options as of December 31, 2012, was $5.7 million and $5.7 million for exercisable options. The fair value of options vested for the year ended December 31, 2012 was $5.1 million. As of December 31, 2012, there was $1.9 million of unrecognized compensation cost related to outstanding nonvested stock options.

The following table summarizes options outstanding as of December 31, 2012:

Stock Incentive Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
$14.86	16,270	.08 years
$21.38	5,560	1.08 years
$46.45	150,710	4.00 years
$55.08	7,260	4.50 years
$60.56	184,565	5.00 years
$29.79	333,232	6.00 years
$43.30	4,750	6.67 years
$46.69	281,110	7.00 years
$54.99	293,978	8.00 years
$54.11	371,040	9.00 years
$14.86-$60.56	1,648,475	6.83 years

The weighted average remaining contractual life of currently exercisable stock options is 5.76 years as of December 31, 2012.

Restricted Stock: In addition, the Stock Incentive Plan provided for the grant of restricted stock which have been valued based on the quoted market price of the Company’s common stock at the date of grant. Restricted stock awards have a three year vesting period. A summary of restricted stock activity as of December 31, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 is presented below:

	Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2009	53,005		$	32.66
Vested	(28,855	)	30.30
Nonvested at December 31, 2010	24,150		35.49
Vested	(14,875	)	30.81
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

The Company recorded expense of $0.1 million, $0.1 million and $0.2 million for the years ended December 31, 2012, 2011 and 2010, respectively, related to restricted stock, with a related deferred income tax benefit of $31,000, $47,000 and $70,000, respectively. As of December 31, 2012, there was $0.5 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 2.96 years.

2004 Stock Appreciation Rights Plan: The Energen 2004 Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Company stock. Officers of the Company are not eligible to participate in this Plan. These awards are liability awards which settle in cash and are re-measured 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, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 are presented below:

	2004 Stock Appreciation Rights Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2009	503,215		$	35.46
Granted	171,749		46.69
Exercised/forfeited	(18,624	)	37.65
Outstanding at December 31, 2010	656,340		38.30
Granted	189,984		54.99
Exercised/forfeited	(69,106	)	41.21
Outstanding at December 31, 2011	777,218		42.00
Exercised/forfeited	(124,188	)	30.90
Outstanding at December 31, 2012	653,030		$	44.14

The Company issued the following awards with stock appreciation rights. The Company 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 as of December 31, 2012:

Grant date	1/26/2011	1/27/2010	2/13-16/2009	1/28/2009	2/4/2008	2/1/2007
Awards granted	189,984	171,749	3,292	305,257	67,093	85,906
Fair market value of award	$11.19	$11.93	$17.57	$18.46	$5.80	$9.25
Expected life of award	4.6 years	3.6 years	3.0 years	3.0 years	2.6 years	2.0 years
Risk-free interest rate	0.63%	0.44%	0.37%	0.37%	0.31%	0.26%
Annualized volatility rate	40.4%	40.4%	40.4%	40.4%	40.4%	40.4%
Dividend yield	1.2%	1.2%	1.2%	1.2%	1.2%	1.2%

Income associated with stock appreciation rights of $1.0 million was recorded for the year ended December 31, 2012. Expense associated with stock appreciation rights of $4.3 million and $3.4 million was recorded for the years ended December 31, 2011 and 2010, respectively. During the year ended December 31, 2012, the total intrinsic value of stock appreciation rights exercised was $2.6 million. During the year ended December 31, 2012, the Company paid $1.8 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 the Company are not eligible to participate in this Plan. These awards are liability awards which are re-measured each reporting period and settle in cash at completion of the vesting period. Stock equivalent units with service conditions were valued based on the Company’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, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 are presented below:

	Petrotech Incentive Plan
	Shares
Outstanding at December 31, 2009	32,350
Granted (three-year vesting period)	2,442
Paid	(26,587	)
Outstanding at December 31, 2010	8,205
Granted (three-year vesting period)	6,314
Paid	(1,914	)
Forfeited	(1,544	)
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

None of the awards issued included a market condition. Energen Resources recognized expense of $2.6 million, $0.2 million and $0.2 million during 2012, 2011 and 2010, 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 the Company's common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company 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 the Company's creditors. Amounts earned under the Deferred Compensation Plan and invested in Company 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, 2012 there were 701,348 shares reserved for issuance from the 1997 Deferred Compensation Plan.

1992 Energen Corporation Directors Stock Plan: In 1992 the Company adopted the Energen Corporation Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Company common stock. Under the Plan, 11,120 shares, 12,420 shares and 15,400 shares were awarded during the years ended December 31, 2012, 2011 and 2010, respectively, leaving 151,784 shares reserved for issuance as of December 31, 2012.

Stock Repurchase Program: By resolution adopted May 25, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board authorized the Company to repurchase up to 12,564,400 shares of the Company's common stock. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2012, 2011 and 2010. As of December 31, 2012, a total of 8,992,700 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Company's stock compensation plans. For the years ended December 31, 2012, 2011 and 2010, the Company acquired 5,459 shares, 12,867 shares and 62,794 shares, respectively, in connection with its stock compensation plans.

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Employee Benefit Plans (Other Investment Assets) (Details) (Nonqualified Supplemental Retirement Plans, Deferred Costs, Noncurrent, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 30,068	$ 27,750
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	30,068	27,750
Insurance contracts
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,999	11,952
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	12,999	11,952
United States equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,741	4,546
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	4,741	4,546
Global equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,109	1,798
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	2,109	1,798
Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10,219	9,454
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	10,219	9,454
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,850	6,344
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	6,850	6,344
Level 1 | Insurance contracts
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	0	0
Level 1 | United States equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,741	4,546
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	4,741	4,546
Level 1 | Global equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,109	1,798
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	2,109	1,798
Level 1 | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	0	0
Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	17,618	16,074
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	17,618	16,074
Level 2 | Insurance contracts
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	7,399	6,620
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	7,399	6,620
Level 2 | United States equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	0	0
Level 2 | Global equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	0	0
Level 2 | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	10,219	9,454
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	10,219	9,454
Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,600	5,332
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	5,600	5,332
Level 3 | Insurance contracts
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5,600	5,332
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at beginning of period	5,332	5,069
Unrealized gains relating to instruments held at the reporting date	268	263
Fair value of plan assets at end of period	5,600	5,332
Level 3 | United States equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	0	0
Level 3 | Global equities
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	0	0
Level 3 | Fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Fair value of plan assets at end of period	$ 0	$ 0

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

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

Years ended December 31, (in thousands)	2012		2011		2010
Taxes estimated to be payable currently:
Federal	$	16,295	$	11,595	$	31,920
State	3,125		5,065		1,230
Total current	19,420		16,660		33,150
Taxes deferred:
Federal	119,053		125,622		121,804
State	5,346		3,419		12,036
Total deferred	124,399		129,041		133,840
Total income tax expense	$	143,819	$	145,701	$	166,990

The components of Alagasco's income taxes consisted of the following:

Years ended December 31, (in thousands)	2012		2011			2010
Taxes estimated to be payable currently:
Federal	$	18,227	$	(1,280	)	$	859
State	739		(108		)	155
Total current	18,966		(1,388		)	1,014
Taxes deferred:
Federal	9,066		24,938			25,582
State	2,212		3,120			3,279
Total deferred	11,278		28,058			28,861
Total income tax expense	$	30,244	$	26,670		$	29,875

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

(in thousands)	December 31, 2012						December 31, 2011
	Current			Noncurrent			Current			Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	10,137		$	—		$	9,582		$	—
Allowance for doubtful accounts	2,408			—			4,848			—
Insurance accruals	2,021			—			2,562			—
Compensation accruals	13,116			—			11,181			—
Inventories	1,664			—			1,438			—
Other comprehensive income	—			19,158			2,799			12,801
Gas supply adjustment related accruals	969			—			1,196			—
Derivative instruments	—			—			13,167			—
State net operating losses and other carryforwards	—			3,577			987			3,022
Other	3,140			25			2,797			27
Total deferred tax assets	33,455			22,760			50,557			15,850
Valuation allowance	(268		)	(2,793		)	(270		)	(2,752		)
Total deferred tax assets	33,187			19,967			50,287			13,098
Deferred tax liabilities:
Depreciation and basis differences	—			898,625			—			791,073
Pension and other costs	—			20,143			—			25,685
Derivative instruments	4,272			3,162			—			—
Other comprehensive income	18,133			—			—			—
Other	2,262			3,638			1,469			2,467
Total deferred tax liabilities	24,667			925,568			1,469			819,225
Net deferred tax assets (liabilities)	$	8,520		$	(905,601	)	$	48,818		$	(806,127	)

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

(in thousands)	December 31, 2012					December 31, 2011
	Current		Noncurrent			Current		Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	10,137	$	—		$	9,582	$	—
Allowance for doubtful accounts	2,155		—			4,575		—
Insurance accruals	1,856		—			2,358		—
Compensation accruals	2,645		—			2,274		—
Inventories	1,664		—			1,438		—
Gas supply adjustment related accruals	969		—			1,196		—
State net operating losses and other carryforwards	—		—			987		—
Other	774		2			924		4
Total deferred tax assets	20,200		2			23,334		4
Deferred tax liabilities:
Depreciation and basis differences	—		167,329			—		156,121
Pension and other costs	—		22,054			—		25,375
Other	1,401		—			1,348		—
Total deferred tax liabilities	1,401		189,383			1,348		181,496
Net deferred tax assets (liabilities)	$	18,799	$	(189,381	)	$	21,986	$	(181,492	)

The Company files a consolidated federal income tax return with all of its subsidiaries. The Company has a noncurrent deferred tax asset of $0.5 million relating to Energen Resources’ $12.2 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. The Company has a full valuation allowance recorded against a noncurrent deferred tax asset of $3.1 million arising from certain state net operating loss and charitable contribution carryforwards. The Company 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 the Company 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 for the Company 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)	2012			2011			2010
Income tax expense at statutory federal income tax rate	$	139,083		$	141,864		$	160,229
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	4,904			5,544			8,398
Qualified Section 199 production activities deduction	(94		)	(593		)	(1,745		)
401(k) stock dividend deduction	(514		)	(532		)	(565		)
Other, net	440			(582		)	673
Total income tax expense	$	143,819		$	145,701		$	166,990
Effective income tax rate (%)	36.19			35.95			36.48

Total income tax expense for Alagasco 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)	2012		2011			2010
Income tax expense at statutory federal income tax rate	$	27,876	$	25,645		$	26,865
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	2,238		2,059			2,157
Reversal of tax reserves from audit settlements, net	—		(1,365		)	—
Other, net	130		331			853
Total income tax expense	$	30,244	$	26,670		$	29,875
Effective income tax rate (%)	37.97		36.40			38.92

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

(in thousands)
Balance as of December 31, 2009	$	17,797
Additions based on tax positions related to the current year	1,436
Additions for tax positions of prior years	11,703
Reductions for tax positions of prior years	(3,624		)
Lapse of statute of limitations	(1,313		)
Settlements	(1,409		)
Balance as of December 31, 2010	24,590
Additions based on tax positions related to the current year	3,644
Additions for tax positions of prior years	2,324
Reductions for tax positions of prior years	(39		)
Lapse of statute of limitations	(1,482		)
Settlements	(18,444		)
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

The reduction for settlements in 2011 and the increase in the additions for tax positions of prior years in 2010 are primarily related to Alagasco's tax accounting method change for the recovery of its gas distribution property that was in dispute under an Internal Revenue Service (IRS) examination of the Company's 2007-2008 federal consolidated income tax returns. In September 2010, the IRS made certain assessments primarily related to Alagasco's tax accounting method change for the recovery of its gas distribution property. The Company subsequently filed a petition in United States Tax Court challenging the IRS assessment. During the second quarter of 2011, the Company entered into a settlement agreement with the IRS. Under this settlement, Alagasco was allowed the full repair tax deductions as originally claimed in the 2007 and 2008 federal income tax returns. The Chief Judge of the United States Tax Court signed and entered the Decision putting this settlement agreement into effect on June 16, 2011.

During 2010, the Company had a gross reduction of $3.6 million and recognized in its effective income tax rate a $2.4 million net benefit associated with the release of an unrecognized income tax benefit liability. The Company reassessed its measurement due to recent developments related to the issue and believed that the full amount of the tax benefit has a greater than 50 percent chance of being fully realized. During 2011, the Company had a gross addition of $5.9 million and recognized in its effective income tax rate $2.9 million of income tax expense for additional unrecognized tax benefit liabilities. These liabilities were partially

offset by a $1.5 million benefit for the release of the unrecognized income tax benefit liability due to the Company's settlement with the IRS discussed above.

The amount of unrecognized tax benefits at December 31, 2012 that would favorably impact the Company's effective tax rate, if recognized, is $5.1 million. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2012, 2011, and 2010, the Company recognized approximately $25,000 of income, $1.4 million of income and $0.8 million of expense for interest (net of tax benefit) and penalties, respectively. The Company had approximately $0.2 million and $0.2 million for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2012 and 2011, respectively.

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

(in thousands)
Balance as of December 31, 2009	$	7,621
Additions based on tax positions related to the current year	9
Additions for tax positions of prior years	11,645
Reductions for tax positions of prior years (lapse of statute of limitations)	(90		)
Settlements	(244		)
Balance as of December 31, 2010	18,941
Additions based on tax positions related to the current year	13
Additions for tax positions of prior years	1
Reductions for tax positions of prior years (lapse of statute of limitations)	(409		)
Settlements	(18,444		)
Balance as of December 31, 2011	102
Additions based on tax positions related to the current year	62
Additions for tax positions of prior years	201
Reductions for tax positions of prior years (lapse of statute of limitations)	(58		)
Balance as of December 31, 2012	$	307

The reduction for settlements in 2011 and the increase in the additions for tax positions of prior years in 2010 are primarily related to Alagasco's tax accounting method change for the recovery of its gas distribution property discussed above. None of Alagasco's unrecognized tax benefits at December 31, 2012 would impact the Company's effective tax rate, if recognized. Alagasco recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2012, 2011, and 2010, Alagasco recognized approximately $1,000 of income, $1.4 million of income and $1.0 million of expense for interest (net of tax benefit) and penalties, respectively. Alagasco had approximately $4,000 and $5,000 for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2012 and 2011, respectively.

The Company and Alagasco's tax returns for years 2009-2011 remain open to examination by the IRS and major state taxing jurisdictions. The Company and Alagasco have on-going income tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of the completion of various audits and the expiration of statute of limitations. Although the timing and outcome of these tax examinations is highly uncertain, the Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2012

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

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 the Company’s consolidated financial statements:

As of December 31, (in thousands)	2012			2011			2012			2011
	Pension						Postretirement Benefits
Accumulated benefit obligation	$	269,101		$	211,896
Benefit obligation:
Balance at beginning of period	$	250,619		$	233,772		$	88,064		$	83,748
Service cost	10,527			9,173			1,853			1,769
Interest cost	10,801			10,960			4,248			4,443
Actuarial (gain) loss	65,048			17,024			(5,413		)	1,858
Plan amendments	—			(169		)	—			—
Termination benefit charge	—			414			—			—
Retiree drug subsidy program	—			—			360			302
Benefits paid	(13,455		)	(20,555		)	(3,327		)	(4,056		)
Balance at end of period	$	323,540		$	250,619		$	85,785		$	88,064
Plan assets:
Fair value of plan assets at beginning of period	$	195,659		$	212,454		$	78,121		$	80,118
Actual return (loss) on plan assets	24,841			1,485			8,778			(1,653		)
Employer contributions	2,379			2,275			3,617			3,712
Benefits paid	(13,455		)	(20,555		)	(3,327		)	(4,056		)
Fair value of plan assets at end of period	$	209,424		$	195,659		$	87,189		$	78,121
Funded status of plan	$	(114,116	)	$	(54,960	)	$	1,404		$	(9,943	)
Noncurrent assets	$	—		$	—		$	1,404		$	—
Current liabilities	(3,834		)	(2,371		)	—			—
Noncurrent liabilities	(110,282		)	(52,589		)	—			(9,943		)
Net asset (liability) recognized	$	(114,116	)	$	(54,960	)	$	1,404		$	(9,943	)
Amounts recognized to accumulated other comprehensive income:
Prior service costs, net of taxes	$	528		$	749		$	—		$	—
Net actuarial (gain) loss, net of taxes	52,472			36,976			(715		)	451
Transition obligation, net of taxes	—			—			222			408
Total accumulated other comprehensive income (loss)	$	53,000		$	37,725		$	(493	)	$	859

Alagasco recognized a regulatory asset of $89.5 million and $67.8 million as of December 31, 2012 and 2011, respectively, for the portion of the pension plan obligation to be recovered through rates in future periods. Alagasco also recognized a regulatory liability of $1.2 million as of December 31, 2012 for the portion of the postretirement health care and life insurance benefit obligation to be refunded through rates in future periods. Alagasco recognized a regulatory asset of $8.4 million as of December 31, 2011 for the portion of the postretirement health care and life insurance benefit obligation to be recovered through rates in future periods.

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

	December 31, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
Insurance contracts	$	—	$	7,399	$	5,600	$	12,999
United States equities	4,741		—		—		4,741
Global equities	2,109		—		—		2,109
Fixed income	—		10,219		—		10,219
Total	$	6,850	$	17,618	$	5,600	$	30,068

	December 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
Insurance contracts	$	—	$	6,620	$	5,332	$	11,952
United States equities	4,546		—		—		4,546
Global equities	1,798		—		—		1,798
Fixed income	—		9,454		—		9,454
Total	$	6,344	$	16,074	$	5,332	$	27,750

While intended for payment of the nonqualified supplemental retirement plan benefits, these assets remain subject to the claims of the Company’s creditors and are not recognized in the funded status of the plan. These assets are recorded at fair value and included in Deferred Charges and Other 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)	2012		2011
Balance at beginning of period	$	5,332	$	5,069
Unrealized gains relating to instruments held at the reporting date	268		263
Balance at end of period	$	5,600	$	5,332

The components of net periodic benefit cost were:

Years ended December 31, (in thousands)	2012			2011			2010
Pension Plans
Components of net periodic benefit cost:
Service cost	$	10,527		$	9,173		$	8,574
Interest cost	10,801			10,960			11,365
Expected long-term return on assets	(14,093		)	(15,471		)	(12,915		)
Prior service cost amortization	517			496			496
Actuarial loss amortization	8,603			6,435			5,773
Termination benefit charge	—			414			—
Net periodic expense	$	16,355		$	12,007		$	13,293
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	1,853		$	1,769		$	2,064
Interest cost	4,248			4,443			4,833
Expected long-term return on assets	(4,438		)	(4,418		)	(3,986		)
Actuarial loss amortization	37			—			—
Transition obligation amortization	1,917			1,917			1,917
Net periodic expense	$	3,617		$	3,711		$	4,828

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

Years ended December 31, (in thousands)	2012			2011			2010
Pension Plans
Net actuarial loss experienced during the year	$	28,748		$	14,312		$	4,332
Net actuarial loss recognized as expense	(4,908		)	(3,755		)	(3,290		)
Prior service cost recognized as expense	(340		)	(298		)	(298		)
Total recognized in other comprehensive income	23,500			10,259			744
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	(1,787	)	$	2,111		$	(2,094	)
Transition obligation recognized as expense	(294		)	(286		)	(280		)
Total recognized in other comprehensive income (loss)	$	(2,081	)	$	1,825		$	(2,374	)

Net retirement expense for Alagasco was $7.8 million, $5.2 million and $6.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. In the first quarter of 2011, the Company recognized a termination benefit charge of $0.4 million to provide for early retirement of certain non-highly compensated employees. Net periodic postretirement benefit expense for Alagasco was $2.7 million, $2.8 million and $3.6 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Estimated amounts to be amortized from accumulated other comprehensive income into pension cost during 2013 are as follows:

(in thousands)
Amortization of prior service cost	$	313
Amortization of net actuarial loss	$	8,591

Estimated amounts to be amortized from accumulated other comprehensive income into benefit cost during 2013 are as follows:

(in thousands)
Amortization of transition obligation	$	264

The Company has a long-term disability plan covering most employees. The Company had expense for the years ended December 31, 2012, 2011 and 2010 of $0.7 million, $0.5 million and $0.4 million, respectively.

Assumptions:

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

Years ended December 31,	2012		2011		2010
Pension Plans
Discount rate	4.52	%	4.89	%	5.49	%
Expected long-term return on plan assets	7.00	%	7.25	%	7.25	%
Rate of compensation increase for pay-related plans	3.59	%	3.75	%	3.95	%
Postretirement Benefit Plans
Discount rate	4.95	%	5.45	%	5.90	%
Expected long-term return on plan assets	7.00	%	7.25	%	7.25	%
Rate of compensation increase	3.55	%	3.61	%	3.69	%

The weighted average rate assumptions used to determine the projected benefit obligations at the measurement date were as follows:

Years ended December 31,	2012		2011
Pension Plans
Discount rate	3.47	%	4.52	%
Rate of compensation increase for pay-related plans	3.71	%	3.59	%
Postretirement Benefit Plans
Discount rate	4.15	%	4.95	%
Rate of compensation increase for pay-related plans	3.70	%	3.55	%

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,	2012		2011
Health care cost trend rate assumed for next year	6.75	%	7.00	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2020		2020

Assumed health care cost trend rates used in determining the accumulated postretirement benefit obligation have an effect on the amounts reported. For example, revising the weighted average health care cost trend rate by 1 percentage point would have the following effects:

(in thousands)
	1-Percentage Point Decrease			1-Percentage Point Increase
Effect on total of service and interest cost	$	(381	)	$	456
Effect on net postretirement benefit obligation	$	(3,688	)	$	4,342

Investment Strategy: The Company employs 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.

The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the Company to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily.

The Company 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 pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, 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		2012		2011		Target		2012		2011
Asset category:
Equity securities	41	%	41	%	39	%	60	%	60	%	60	%
Debt securities	38	%	38	%	40	%	40	%	40	%	40	%
Other	21	%	21	%	21	%	—	%	—	%	—	%
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, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
United States equities	$	41,907	$	9,072	$	—	$	50,979
Global equities	23,782		10,697		—		34,479
Fixed income	—		78,806		—		78,806
Alternative investments	—		27,659		14,500		42,159
Cash and cash equivalents	—		3,001		—		3,001
Total	$	65,689	$	129,235	$	14,500	$	209,424
	December 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
United States equities	$	37,009	$	8,916	$	—	$	45,925
Global equities	20,064		4,914		4,352		29,330
Fixed income	—		78,443		—		78,443
Alternative investments	—		26,070		13,047		39,117
Cash and cash equivalents	—		2,844		—		2,844
Total	$	57,073	$	121,187	$	17,399	$	195,659

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 asset investments consist of limited partnerships and commingled and mutual funds with varying investment strategies. Alternative assets 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)	2012			2011
Balance at beginning of period	$	17,399		$	26,841
Unrealized gains (losses)	992			(752		)
Unrealized gains relating to instruments held at the reporting date	242			635
Settlements	(4,948		)	(9,604		)
Purchases	815			279
Balance at end of period	$	14,500		$	17,399

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

	December 31, 2012
(in thousands)	Level 1		Level 2		Total
United States equities	$	37,482	$	—	$	37,482
Global equities	15,049		—		15,049
Fixed income	—		34,658		34,658
Total	$	52,531	$	34,658	$	87,189

	December 31, 2011
(in thousands)	Level 1		Level 2		Total
United States equities	$	33,649	$	—	$	33,649
Global equities	13,088		—		13,088
Fixed income	—		31,384		31,384
Total	$	46,737	$	31,384	$	78,121

The Company had no Level 3 postretirement benefit plan assets. United States equities consisted 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: There are no required contributions to the qualified pension plans during 2013. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $9.0 million to the qualified pension plans in January 2013. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2013. The Company expects to make benefit payments of approximately $3.8 million during 2013 to retirees with respect to the nonqualified supplemental retirement plans. The Company expects to make discretionary contributions of $1.6 million to the postretirement health care and life insurance benefit plans during 2013.

The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows. In addition, the following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy which began in 2007:

(in thousands)	Pension Benefits	Postretirement Benefits	Postretirement Benefits – Prescription Drug Subsidy
2013	$20,354	$4,435	$(243)
2014	$20,982	$4,586	$(248)
2015	$21,679	$4,754	$(252)
2016	$23,155	$4,940	$(258)
2017	$28,139	$5,165	$(260)
2018-2022	$166,646	$28,565	$(1,333)

In March 2010, The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (collectively, Health Care Reform) was signed into law. The impact of the legislation has been estimated and is first reflected in the December 31, 2011 measurement of the post retirement benefit obligation.  Energen has applied and been approved for the Early Retiree Reinsurance Program (ERRP). Energen is currently evaluating the application of the ERRP receipts and, therefore, the post retirement benefit obligations have not been reduced to reflect actual or expected receipts under the program.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources 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 33.4 million barrels of oil equivalent (MMBOE) through November 2021.

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources' total resulting exposure could be as much as $21.9 million depending on the contractor's ability to remarket the drilling rigs.

Certain of Alagasco's long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $59 million through September 2024. During the years ended December 31, 2012, 2011 and 2010, Alagasco recognized approximately $51 million, $51 million and $52 million, respectively, of current-year commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 171 Bcf through August 2020.

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

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns and is the subject of a recent inquiry discussed below. Also discussed below is the recent completion of a removal action at the Huntsville, Alabama manufactured gas plant site. An investigation of the sites does not indicate the present need for other remediation activities and management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the financial position of Alagasco.

In May 2012, Alagasco received from the United States Environmental Protection Agency (EPA) a Request for information Pursuant to Section 104 of CERCLA relating to the EPA's investigation of a site which it refers to as the 35^th Avenue Superfund Site in and around Birmingham, Jefferson County, Alabama. The inquiry requests information about a parcel owned by Alagasco and located in the vicinity of the 35^th Avenue site. The parcel is the former site of a manufactured gas distribution facility. Alagasco has responded to the inquiry.

In June 2009, Alagasco received a General Notice Letter from the EPA identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949. While Alagasco no longer owns the Huntsville site, the Company and the current site owner entered into a Consent Order, and developed and completed during 2011 an action plan for the site. Alagasco has incurred costs associated with the site of approximately $5 million. As of December 31, 2012, the expected remaining costs are not expected to be material to the Company. Alagasco has recorded a corresponding amount, subject to APSC review guidelines, against the refundable negative salvage costs being refunded to customers.

Legal Matters: 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. 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 Energen and its affiliates conduct business in jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

Various pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability. This provision was increased by $0.1 million during the year ended December 31, 2012.

On November 2, 2011 Energen Resources spudded the Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. During the drilling phase, Chesapeake Exploration, LLC, notified Energen Resources that it believed it was the owner of the lease from which the Cadenhead Well was producing. Shortly thereafter, Energen Resources filed a declaratory judgment action in the District Court of Ward County, Texas to resolve the title dispute. Energen Resources has a fifty percent working interest in the Cadenhead Well. The Cadenhead Well produced approximately 63 net MBOE in 2012 and is expected to produce approximately 42 net MBOE in 2013. On January 18, 2013, a judgment was entered which was adverse to Energen Resources' claim of ownership. The Company believes the adverse ruling was incorrect, and plans to vigorously pursue all available avenues of appeal.

New Mexico Audits: During the third quarter of 2011, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted 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 ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company's New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department's findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of December 31, 2012.

Lease Obligations: Alagasco leases the Company's headquarters building over a 25-year term ending January 31, 2024 and the related lease is accounted for as an operating lease. Under the terms of the lease, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Energen's total lease payments included as operating lease expense were $20.9 million, $19.1 million and $18.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. Minimum future rental payments required after 2012 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2013	2014	2015	2016	2017	2018 and thereafter
$5,144	$4,836	$4,506	$4,141	$3,980	$13,046

Alagasco's total payments related to leases included as operating expense, net of approximately $1.0 million of lease expense paid by Energen each year, were $2.1 million, $2.3 million and $2.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. Minimum future rental payments required after 2012 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2013	2014	2015	2016	2017	2018 and thereafter
$3,629	$3,858	$3,909	$3,934	$3,980	$13,046

Included in the table above are approximately $17.6 million of payments associated with leasing of the Company’s headquarters, which are expected to be reimbursed to Alagasco by Energen through the remaining term of the related lease. Such amounts are subject to intercompany allocations but are not subject to contractual agreements.

Capital Lease Obligations: During the first quarter of 2012, the Company entered into capital leases related to certain equipment. The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 2012:

(in thousands)
2013	$	1,743
2014	1,743
2015	145
Total minimum lease payments	3,631
Less amount representing interest	54
Total present value of minimum lease payments	$	3,577

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Employee Benefit Plans (Allocation of Plan Assets) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Pension Plans
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation, Equity securities	100.00%
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Postretirement Benefit Plans
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation, Equity securities	100.00%
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Equity Securities | Pension Plans
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation, Equity securities	41.00%
Defined Benefit Plan, Actual Plan Asset Allocations	41.00%	39.00%
Equity Securities | Postretirement Benefit Plans
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation, Equity securities	60.00%
Defined Benefit Plan, Actual Plan Asset Allocations	60.00%	60.00%
Debt Securities | Pension Plans
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation, Equity securities	38.00%
Defined Benefit Plan, Actual Plan Asset Allocations	38.00%	40.00%
Debt Securities | Postretirement Benefit Plans
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation, Equity securities	40.00%
Defined Benefit Plan, Actual Plan Asset Allocations	40.00%	40.00%
Other Securities | Pension Plans
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation, Equity securities	21.00%
Defined Benefit Plan, Actual Plan Asset Allocations	21.00%	21.00%
Other Securities | Postretirement Benefit Plans
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation, Equity securities	0.00%
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%

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Financial Instruments and Risk Management (Derivative Instruments, Notional Amounts) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net [Abstract]
Discontinued hedge accounting and reclass of gains (losses) after-tax, due to probability that ceraint forecasted volumes would not occur	$ 63
Fair Value Hedging | Expires during 2013 | Crude Oil
Derivative [Line Items]
Total hedged Volumes	9,700,000.0
Fair Value Hedging | Expires during 2014 | Natural Gas
Derivative [Line Items]
Total hedged Volumes	9,700,000,000.0
Fair Value Hedging | Expires during 2014 | Crude Oil
Derivative [Line Items]
Total hedged Volumes	5,400,000.0
Cash Flow Hedges | 2013 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	12.7
Average Contract Price, Per Mcf	4.82
Cash Flow Hedges | 2013 | Natural Gas | San Juan Basin
Derivative [Line Items]
Total hedged Volumes	32.8
Average Contract Price, Per Mcf	4.56
Cash Flow Hedges | 2013 | Natural Gas | Permian Basin
Derivative [Line Items]
Total hedged Volumes	4.6
Average Contract Price, Per Mcf	3.45
Cash Flow Hedges | 2013 | Crude Oil | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	8,858.0
Average Contract Price, Per Bbl	90.95
Cash Flow Hedges | 2013 | Crude Oil | WTS/WTI Basis Swaps
Derivative [Line Items]
Total hedged Volumes	3,592.0
Average Contract Price, Per Bbl	(3.03)
Cash Flow Hedges | 2013 | Crude Oil | WTI/WTI Basis Swaps
Derivative [Line Items]
Total hedged Volumes	2,760.0
Average Contract Price, Per Bbl	(1.01)
Cash Flow Hedges | 2013 | Natural Gas Liquids | Liquids Swaps
Derivative [Line Items]
Total hedged Volumes	44.5
Average Contract Price, Per Gal	1.02
Cash Flow Hedges | 2014 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	10.6
Average Contract Price, Per Mcf	4.55
Cash Flow Hedges | 2014 | Natural Gas | San Juan Basin
Derivative [Line Items]
Total hedged Volumes	25.7
Average Contract Price, Per Mcf	4.72
Cash Flow Hedges | 2014 | Natural Gas | Permian Basin
Derivative [Line Items]
Total hedged Volumes	9.7
Average Contract Price, Per Mcf	3.81
Cash Flow Hedges | 2014 | Crude Oil | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	9,796.0
Average Contract Price, Per Bbl	92.64
Alabama Gas Corporation | Cash Flow Hedges | 2013 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	1.5

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Employee Benefit Plans (Cash Flows) (Details) (USD $)		12 Months Ended						1 Months Ended
	Dec. 31, 2012	Dec. 31, 2012 Pension Plans	Dec. 31, 2011 Pension Plans	Dec. 31, 2012 Postretirement Benefit Plans	Dec. 31, 2011 Postretirement Benefit Plans	Dec. 31, 2012 Nonqualified Supplemental Retirement Plans	Dec. 31, 2012 Postretirement health care and life insurance benefit plan	Jan. 31, 2013 Defined Benefit Plan Discretionary Contribution [Member] Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions		$ 2,379,000	$ 2,275,000	$ 3,617,000	$ 3,712,000			$ 9,000,000
Anticipated required or discretionary contributions during in next fiscal year						3,800,000	1,600,000
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
2013		20,354,000		4,435,000
2014		20,982,000		4,586,000
2015		21,679,000		4,754,000
2016		23,155,000		4,940,000
2017		28,139,000		5,165,000
2018-2022		166,646,000		28,565,000
Disclosure of Expected Gross Prescription Drug Subsidy Receipts [Abstract]
Postretirement Benefits - Prescription Drug Subsidy, 2013	(243,000)
Postretirement Benefits - Prescription Drug Subsidy, 2014	(248,000)
Postretirement Benefits - Prescription Drug Subsidy, 2015	(252,000)
Postretirement Benefits - Prescription Drug Subsidy, 2016	(258,000)
Postretirement Benefits - Prescription Drug Subsidy, 2017	(260,000)
Prescription Drug Subsidy Receipts, after Year Five	$ (1,333,000)

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Oil and Gas Operations (Unaudited) (Oil and Gas Operations, Activites) (Details)	12 Months Ended
	Dec. 31, 2012 MMBoe	Dec. 31, 2011 MMBoe	Dec. 31, 2010 MMBoe
Reserve Quantities [Line Items]
Revisions of previous estimates	42.1	5.8	(11.3)
Purchases	12.4	20.8	25.8
Extensions and discoveries	57.1	45.6	26.8
Percentage of undeveloped portion of proved reserves	59.00%	69.00%	77.00%
Percentage of developed portion of proved reserves	41.00%	31.00%	23.00%
Extension Drilling
Reserve Quantities [Line Items]
Extensions and discoveries	45.6	41.1	26.6
Exploratory Drilling
Reserve Quantities [Line Items]
Extensions and discoveries	11.5	4.5	0.3
Black Warrior Basin
Reserve Quantities [Line Items]
Revisions of previous estimates	5.1	0.3	(0.6)
Black Warrior Basin | Price Related Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates		0.7
Black Warrior Basin | Other Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates		(0.4)	0.7
Black Warrior Basin | Change in Year-End Pricing Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates	5.9		(1.3)
San Juan Basin
Reserve Quantities [Line Items]
Revisions of previous estimates	19.7	2.6	(11.0)
Extensions and discoveries	0.9	5.9	6.4
Number of well locations	6	53	36
Number of sidetrack wells			1
San Juan Basin | Sidetrack Drilling
Reserve Quantities [Line Items]
Extensions and discoveries			1.1
San Juan Basin | Price Related Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates		(1.3)
San Juan Basin | Change in Year-End Pricing Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates	22.5		(7.6)
San Juan Basin | Well Performance
Reserve Quantities [Line Items]
Revisions of previous estimates		3.9	(8.2)
San Juan Basin | SEC Five-Year Development Rule Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates			5.3
Permian Basin
Reserve Quantities [Line Items]
Revisions of previous estimates	15.8	3.1	1.3
Extensions and discoveries	56.1	39.6	22.1
Number of well locations	422	395	271
Permian Basin | Price Related Revisions
Reserve Quantities [Line Items]
Revisions of previous estimates	1.0	(1.4)	(3.0)

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Employee Benefit Plans (Assumptions) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year	6.75%	7.00%
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Effect on total service and interest cost, 1-Percentage Point Decrease	(381)
Effect on total service and interest cost, 1-Percentage Point Increase	456
Effect on net postretirement benefit obligation, 1-Percentage Point Decrease	(3,688)
Effect on net postretirement benefit obligation, 1-Percentage Point Increase	4,342
Pension Plans
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.52%	4.89%	5.49%
Expected long-term return on plan assets	7.00%	7.25%	7.25%
Rate of compensation increase for pay-related plans	3.59%	3.75%	3.95%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.47%	4.52%
Rate of compensation increase for pay-related plans	3.71%	3.59%
Postretirement Benefit Plans
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.95%	5.45%	5.90%
Expected long-term return on plan assets	7.00%	7.25%	7.25%
Rate of compensation increase for pay-related plans	3.55%	3.61%	3.69%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	4.15%	4.95%
Rate of compensation increase for pay-related plans	3.70%	3.55%

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning	$ 107,340	$ 97,415	$ 88,298
Liabilities incurred	3,994	4,627	4,033
Liabilities settled	(845)	(1,539)	(1,094)
Accretion expense	7,534	6,837	6,178
Balance of ARO, end	118,023	107,340	97,415
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets, Noncurrent	110,566	95,633
Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, end	24,900	20,800
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets, Noncurrent	110,566	95,633
Alabama Gas Corporation | Asset removal costs
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets, Noncurrent	$ 3,322	$ 994

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Common Stock Plans (Tables)

12 Months Ended

Dec. 31, 2012

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of performance share award activity

No performance share awards were granted in 2012, 2011 or 2010. A summary of performance share award activity is presented below:

	Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2009	111,143		$	43.81
Vested and paid	(111,143	)	43.81
Nonvested at December 31, 2010	—		$	—

Schedule of stock option activity and transactions

A summary of stock option activity as of December 31, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 are presented below:

	Stock Incentive Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2009	1,107,809		$	36.83
Granted	281,110		46.69
Exercised	(111,676	)	23.83
Forfeited	(1,200	)	13.72
Outstanding at December 31, 2010	1,276,043		40.16
Granted	293,978		54.99
Exercised	(227,405	)	32.33
Forfeited	(4,375	)	35.35
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
Exercisable at December 31, 2010	574,992		$	41.16
Exercisable at December 31, 2011	677,753		$	43.72
Exercisable at December 31, 2012	987,733		$	43.75
Remaining reserved for issuance at December 31, 2012	3,418,881		—

Schedule of stock options valuation assumptions

The Company 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	1/25/2012		1/26/2011		1/27/2010
Awards granted	371,040		293,978		281,110
Fair market value of stock option at grant	$18.79		$19.65		$16.47
Expected life of award	5.8 years		5.8 years		5.7 years
Risk-free interest rate	1.07	%	2.45	%	2.76	%
Annualized volatility rate	39.6	%	37.8	%	37.3	%
Dividend yield	1.0	%	1.0	%	1.1	%

Schedule of outstanding stock options by range of exercise prices

The following table summarizes options outstanding as of December 31, 2012:

Stock Incentive Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
$14.86	16,270	.08 years
$21.38	5,560	1.08 years
$46.45	150,710	4.00 years
$55.08	7,260	4.50 years
$60.56	184,565	5.00 years
$29.79	333,232	6.00 years
$43.30	4,750	6.67 years
$46.69	281,110	7.00 years
$54.99	293,978	8.00 years
$54.11	371,040	9.00 years
$14.86-$60.56	1,648,475	6.83 years

Schedule of restricted stock activity and transactions

A summary of restricted stock activity as of December 31, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 is presented below:

	Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2009	53,005		$	32.66
Vested	(28,855	)	30.30
Nonvested at December 31, 2010	24,150		35.49
Vested	(14,875	)	30.81
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

Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity [Table Text Block]

A summary of stock appreciation rights activity as of December 31, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 are presented below:

	2004 Stock Appreciation Rights Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2009	503,215		$	35.46
Granted	171,749		46.69
Exercised/forfeited	(18,624	)	37.65
Outstanding at December 31, 2010	656,340		38.30
Granted	189,984		54.99
Exercised/forfeited	(69,106	)	41.21
Outstanding at December 31, 2011	777,218		42.00
Exercised/forfeited	(124,188	)	30.90
Outstanding at December 31, 2012	653,030		$	44.14

Schedule of stock appreciation rights valuation assumptions

For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2012:

Grant date	1/26/2011	1/27/2010	2/13-16/2009	1/28/2009	2/4/2008	2/1/2007
Awards granted	189,984	171,749	3,292	305,257	67,093	85,906
Fair market value of award	$11.19	$11.93	$17.57	$18.46	$5.80	$9.25
Expected life of award	4.6 years	3.6 years	3.0 years	3.0 years	2.6 years	2.0 years
Risk-free interest rate	0.63%	0.44%	0.37%	0.37%	0.31%	0.26%
Annualized volatility rate	40.4%	40.4%	40.4%	40.4%	40.4%	40.4%
Dividend yield	1.2%	1.2%	1.2%	1.2%	1.2%	1.2%

Petrotech Incentive Plan

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of incentive units activity

A summary of Petrotech unit activity as of December 31, 2012, and transactions during the years ended December 31, 2012, 2011 and 2010 are presented below:

	Petrotech Incentive Plan
	Shares
Outstanding at December 31, 2009	32,350
Granted (three-year vesting period)	2,442
Paid	(26,587	)
Outstanding at December 31, 2010	8,205
Granted (three-year vesting period)	6,314
Paid	(1,914	)
Forfeited	(1,544	)
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

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Long-Term Debt and Notes Payable (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Long-term debt	$ 1,154,028	$ 1,155,246
Less amounts due within one year	50,000	1,000
Less unamortized debt discount	500	546
Long-term debt	1,103,528	1,153,700
Medium-term Notes | Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.6%, for notes due July 24, 2017 to February 15, 2028
Debt Instrument [Line Items]
Long-term debt	154,000	155,000
Debt instrument, interest rate, minimum	7.125%
Debt instrument, interest rate, maximum	7.60%
Medium-term Notes | Medium-term Notes, Series A, interest of 7.57%
Debt Instrument [Line Items]
Debt instrument, interest rate		7.57%
Notes | 5% Notes, due October 1, 2013
Debt Instrument [Line Items]
Long-term debt	50,000	50,000
Debt instrument, interest rate	5.00%
Senior Notes | 4.625% Notes, due September 1, 2021
Debt Instrument [Line Items]
Long-term debt	400,000	400,000
Debt instrument, interest rate	4.625%
Senior Term Loans | Senior Term Loans, (floating rate interest LIBOR plus 1.375%; 1.59% at December 31, 2012), due March 31, 2014 to November 29, 2016
Debt Instrument [Line Items]
Long-term debt	300,000	300,000
Debt Instrument, basis spread on variable rate	1.375%
Floating rate interest, plus basis points	1.59%
Alabama Gas Corporation
Debt Instrument [Line Items]
Less amounts due within one year	0	0
Long-term debt	250,028	250,246
Alabama Gas Corporation | Notes | 5.20% Notes, due January 15, 2020
Debt Instrument [Line Items]
Long-term debt	40,000	40,000
Debt instrument, interest rate	5.20%
Alabama Gas Corporation | Notes | 5.70% Notes, due January 15, 2035
Debt Instrument [Line Items]
Long-term debt	35,028	35,246
Debt instrument, interest rate	5.70%
Alabama Gas Corporation | Notes | 5.368% Notes, due December 1, 2015
Debt Instrument [Line Items]
Long-term debt	80,000	80,000
Debt instrument, interest rate	5.368%
Alabama Gas Corporation | Notes | 5.90% Notes, due January 15, 2037
Debt Instrument [Line Items]
Long-term debt	45,000	45,000
Debt instrument, interest rate	5.90%
Alabama Gas Corporation | Notes | 3.86% Notes, due December 21, 2021
Debt Instrument [Line Items]
Long-term debt	$ 50,000	$ 50,000
Debt instrument, interest rate	3.86%

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Acquisition and Dispositions of Oil and Gas Properties

12 Months Ended

Dec. 31, 2012

Acquisition and Dispositions of Oil and Gas Properties [Abstract]

Acquisition and Dispositions of Oil and Gas Properties

ACQUISITION AND DISPOSITION OF OIL AND GAS PROPERTIES

During the first quarter of 2012, Energen Resources recognized a noncash 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. 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 was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

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.

On December 27, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $60 million. This purchase had an effective date of July 1, 2011. Energen acquired total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percent of the proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 15 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 December 27, 2011 (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	60,017
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	36,068
Unproved leasehold properties	23,686
Accounts receivable	680
Accounts payable	(244		)
Asset retirement obligation	(173		)
Total identifiable net assets	$	60,017

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

On November 16, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $162 million. This purchase had an effective date of August 1, 2011. Energen acquired total proved reserves of approximately 13.6 MMBOE. Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 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 November 16, 2011, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	161,967
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,544
Unproved leasehold properties	7,883
Accounts receivable	3,070
Accounts payable	(388		)
Asset retirement obligation	(142		)
Total identifiable net assets	$	161,967

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

In July 2011, Energen completed the purchase of properties in the Permian Basin for a cash purchase price of approximately $20 million. In April 2011, Energen completed the purchase of unproved leasehold properties for a cash purchase price of approximately $37 million covering an estimated 11,000 net acres in the Permian Basin.

During 2010, Energen Resources incurred write-offs of unproved capitalized leasehold costs associated with its Alabama shale acreage. The non-cash costs totaled $39.7 million pre-tax and were charged to exploration expense, which is included in O&M expense, after the Company determined that the shale acreage was not economically viable. During the year ended December 31, 2010, Energen Resources also recorded $15.5 million pre-tax in write-offs of well costs related to Alabama shale leasehold.

On December 15, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $74 million. This purchase had an effective date of December 1, 2010. Energen acquired proved reserves of approximately 7.6 MMBOE. Of the proved reserves acquired, an estimated 92 percent are undeveloped. Approximately 62 percent of the acquisition’s estimated proved reserves are oil, 24 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 December 15, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	73,630
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	41,066
Unproved leasehold properties	32,500
Accounts receivable	143
Asset retirement obligation	(79		)
Total identifiable net assets	$	73,630

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2010.

On December 9, 2010, Energen completed the asset purchase of certain properties in the Permian Basin from SandRidge Energy, Inc. for a cash purchase price of $103 million (including the effects closing adjustments). This purchase had an effective date of December 9, 2010. Energen acquired no proved reserves related to this acquisition. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition.

On September 30, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash price of $188 million. This purchase had an effective date of September 1, 2010. Energen acquired proved reserves of approximately 18 MMBOE. Of the proved reserves acquired, an estimated 89 percent are undeveloped. Approximately 65 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 13 percent. Energen Resources used its 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 September 30, 2010, (including the effects of closing adjustment).

(in thousands)
Consideration given
Cash (net)	$	188,314
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,747
Unproved leasehold properties	35,360
Accounts receivable	1,461
Asset retirement obligation	(142		)
Accounts payable	(112		)
Total identifiable net assets	$	188,314

Included in the Company’s consolidated results of operations for the year ended December 31, 2010, is $5 million of operating revenues and $2.1 million in operating income resulting from the operation of the properties acquired above.

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Oil and Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2012

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Operations

OIL AND GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:

(in thousands)	December 31, 2012		December 31, 2011
Proved	$	6,241,148	$	4,927,576
Unproved	197,979		238,792
Total capitalized costs	6,439,127		5,166,368
Accumulated depreciation, depletion and amortization	1,765,241		1,382,526
Capitalized costs, net	$	4,673,886	$	3,783,842

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)	2012		2011		2010
Property acquisition:
Proved	$	79,862	$	214,993	$	207,161
Unproved	58,634		91,888		201,881
Exploration	419,284		190,854		37,371
Development	749,256		623,775		332,541
Total costs incurred	$	1,307,036	$	1,121,510	$	778,954

Results of Operations From Producing Activities: The following table sets forth results of the Company's oil and gas operations from producing activities:

Years ended December 31, (in thousands)	2012		2011		2010
Gross revenues*	$	1,167,183	$	944,908	$	957,371
Production (lifting costs)	306,375		257,045		224,901
Exploration expense	19,363		13,110		64,584
Depreciation, depletion and amortization	394,668		240,232		200,179
Accretion expense	7,534		6,837		6,178
Income tax expense	157,670		154,180		166,750
Results of operations from producing activities	$	281,573	$	273,504	$	294,779

*The years ended December 31, 2012, 2011 and 2010 gross revenues includes a pre-tax non cash mark-to-market gain on derivatives of $58.8 million, a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million and a pre-tax non-cash mark-to-market loss on derivatives of $3,000, respectively.

Oil and 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. Reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2012, 2011 and 2010. Changes to prices and costs could have a significant effect on the disclosed amount of reserves and their associated values. In addition, the estimation of 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 reserves disclosed. The proved reserves are located onshore in the United States of America.

Estimates of physical quantities of oil and 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 gas reservoir engineers, have audited the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2012. Ryder Scott audited the reserve estimates for coalbed methane in the Black Warrior and San Juan basins and substantially all of the Permian Basin reserves. T. Scott Hickman audited the reserves for the North Louisiana and East Texas regions and the conventional reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 99 percent of the Company's ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

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

Year ended December 31, 2011	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
Proved reserves at beginning of period	954,387		103,262		40,601		302.9
Revisions of previous estimates	(12,823	)	(4,513	)	841		(5.8	)
Purchases	19,362		12,583		5,055		20.8
Extensions and discoveries	68,160		24,564		9,637		45.6
Production	(71,718	)	(6,318	)	(2,177	)	(20.4	)
Proved reserves at end of period	957,368		129,578		53,957		343.1
Proved developed reserves at end of period	788,812		83,899		33,154		248.5
Proved undeveloped reserves at end of period	168,556		45,679		20,803		94.6

Year ended December 31, 2010	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
Proved reserves at beginning of period	897,546		77,963		30,257		257.8
Revisions of previous estimates	66,679		(2,243	)	2,434		11.3
Purchases	21,700		16,443		5,730		25.8
Extensions and discoveries	39,570		16,234		4,058		26.8
Production	(70,924	)	(5,131	)	(1,880	)	(18.8	)
Sales	(184	)	(4	)	2		—
Proved reserves at end of period	954,387		103,262		40,601		302.9
Proved developed reserves at end of period	786,292		72,030		28,809		231.9
Proved undeveloped reserves at end of period	168,095		31,232		11,792		71.0

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

During 2012, Energen Resources 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.

2011 Activities: Energen Resources had downward reserve revisions during 2011 which totaled 5.8 MMBOE. The Black Warrior Basin had downward reserve revisions totaling 0.3 MMBOE of which approximately 0.7 MMBOE related to estimated negative price related revisions partially offset by other positive revisions of 0.4 MMBOE. The San Juan Basin downward reserve revisions of 2.6 MMBOE included 3.9 MMBOE in negative performance related revisions partially offset by 1.3 MMBOE related to estimated positive price related revisions. Downward reserve revisions of 3.1 MMBOE in the Permian Basin were primarily due to lower than anticipated injection response in certain waterflood units and other performance related adjustments. These downward revisions were partially offset by 1.4 MMBOE of estimated positive price related revisions.

Energen Resources purchased 20.8 MMBOE of reserves during 2011 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2011, Energen Resources had extensions and discoveries of 45.6 MMBOE of which 69 percent were proved undeveloped reserves and 31 percent were proved developed reserves. Extension drilling resulted in 41.1 MMBOE of discoveries with exploratory drilling providing 4.5 MMBOE of discoveries. The San Juan Basin added 5.9 MMBOE of reserves through the drilling or identification of 53 well locations. The Permian Basin added 39.6 MMBOE of reserves primarily through the drilling or identification of 395 well locations.

2010 Activities: Energen Resources had upward reserve revisions during 2010 which totaled 11.3 MMBOE. The Black Warrior Basin had upward reserve revisions totaling 0.6 MMBOE of which approximately 1.3 MMBOE related to changes in year-end pricing partially offset by downward reserve revisions of 0.7 MMBOE. The San Juan Basin upward reserve revisions of 11 MMBOE included 7.6 MMBOE related to changes in year-end pricing and 8.2 MMBOE associated with well performance partially offset by 5.3 MMBOE of downward reserve revisions resulting from the SEC’s five-year development rule. Downward reserve revisions of 1.3 MMBOE in the Permian Basin were due to lower than anticipated injection response in certain waterflood units offset by 3.0 MMBOE of estimated positive price related revisions.

Energen Resources purchased 25.8 MMBOE of reserves during 2010 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2010, Energen Resources had extensions and discoveries of 26.8 MMBOE of which 77 percent were proved undeveloped reserves and 23 percent were proved developed reserves. Extension drilling resulted in 26.6 MMBOE of discoveries with exploratory drilling providing 0.3 MMBOE of discoveries. The San Juan Basin added 6.4 MMBOE of reserves through the drilling or identification of 36 well locations; additionally, 1 sidetrack well added 1.1 MMBOE of reserves. The Permian Basin added 22.1 MMBOE of reserves primarily through the drilling or identification of 271 well locations.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and 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 the Company'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, 2012, 2011 and 2010, the Company had a deferred hedging gain of $74.8 million, a deferred hedging gain of $15 million and a deferred hedging loss of $70.4 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.

Years ended December 31, (in thousands)	2012		2011		2010
Future gross revenues	$	17,735,363	$	18,196,229	$	13,210,211
Future production costs	5,715,248		5,823,395		4,959,403
Future development costs	1,892,600		1,539,072		1,026,903
Future income tax expense	2,809,411		3,326,382		2,201,742
Future net cash flows	7,318,104		7,507,380		5,022,163
Discount at 10% per annum	3,618,785		3,878,217		2,555,027
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	3,699,319	$	3,629,163	$	2,467,136
Discounted future net cash flows before income taxes	$	4,411,399	$	4,691,086	$	3,155,746

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

Years ended December 31, (in thousands)	2012			2011			2010
Balance at beginning of year	$	3,629,163		$	2,467,136		$	1,563,190
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	(922,792		)	707,411			945,179
Net changes due to revisions in quantity estimates	(383,755		)	(80,004		)	36,349
Development costs incurred, previously estimated	472,603			392,720			195,269
Accretion of discount	362,916			246,714			156,319
Changes in timing and other	(317,244		)	(25,937		)	15,815
Total revisions	(788,272		)	1,240,904			1,348,931
New field discoveries and extensions, net of future production and development costs	1,025,419			755,977			319,223
Sales of oil and gas produced, net of production costs	(812,781		)	(763,171		)	(576,755		)
Purchases	189,755			232,768			278,384
Sales	—			—			87
Net change in income taxes	456,035			(304,451		)	(465,924		)
Net change in standardized measure of discounted future net cash flows	70,156			1,162,027			903,946
Balance at end of year	$	3,699,319		$	3,629,163		$	2,467,136

XML

Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 45,515	$ 57,143
Regulatory Assets, Noncurrent	110,566	95,633
Regulatory Liability, Current	45,116	58,279
Regulatory Liability, Noncurrent	80,404	87,234
Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	18,300
Regulatory Liability, Noncurrent	53,500
Gas supply adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	42,726	0
Regulatory Assets, Noncurrent	0	0
Alabama Gas Corporation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	45,515	57,143
Regulatory Assets, Noncurrent	110,566	95,633
Regulatory Liability, Current	45,116	58,279
Regulatory Liability, Noncurrent	80,404	87,234
Alabama Gas Corporation | RSE adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	1,740	2,931
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Unbilled service margin
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	25,078	22,419
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Postretirement liabilities
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	1,237	0
Alabama Gas Corporation | Gas supply adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	12,626
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	18,265	20,269
Regulatory Liability, Noncurrent	53,467	65,646
Alabama Gas Corporation | Asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	24,930	20,785
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	33	34
Regulatory Liability, Noncurrent	770	803
Alabama Gas Corporation | Pension and postretirement assets
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	170	170
Regulatory Assets, Noncurrent	90,708	77,587
Alabama Gas Corporation | Accretion and depreciation for asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	16,536	13,981
Alabama Gas Corporation | Risk management activities
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	2,593	56,804
Regulatory Assets, Noncurrent	0	3,070
Alabama Gas Corporation | Asset removal costs, net
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	3,322	994
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	26	169
Regulatory Assets, Noncurrent	$ 0	$ 1

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Summary of Significant Accounting Policies (Employee Benefit Plans) (Details)	12 Months Ended
	Dec. 31, 2012 pension_plan
Defined Benefit Plan Disclosure [Line Items]
Number of non-contributory qualified pension plans	2

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Schedule II - Valuation and Qualifying Accounts (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$ 12,946	$ 15,048	$ 17,251
Charged to income	1,415	4,269	2,665
Recoveries and adjustments	(1,262)	(1,744)	(1,100)
Net additions	153	2,525	1,565
Less uncollectible accounts written off	(6,550)	(4,627)	(3,768)
Balance at end of year	6,549	12,946	15,048
Alabama Gas Corporation
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	12,100	14,200	16,400
Charged to income	1,409	4,202	2,655
Recoveries and adjustments	(1,263)	(1,745)	(1,094)
Net additions	146	2,457	1,561
Less uncollectible accounts written off	(6,546)	(4,557)	(3,761)
Balance at end of year	$ 5,700	$ 12,100	$ 14,200

XML

Regulatory Assets and Liabilities (Tables) (Alabama Gas Corporation)

12 Months Ended

Dec. 31, 2012

Alabama Gas Corporation

Regulatory Assets and Liabilities [Line Items]

Schedule of regulatory assets and liabilities

The following table details regulatory assets and liabilities on the consolidated balance sheets:

(in thousands)	December 31, 2012				December 31, 2011
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	90,708	$	170	$	77,587
Accretion and depreciation for asset retirement obligation	—		16,536		—		13,981
Risk management activities	2,593		—		56,804		3,070
Rate recovery of asset removal costs, net	—		3,322		—		994
Gas supply adjustment	42,726		—		—		—
Other	26		—		169		1
Total regulatory assets	$	45,515	$	110,566	$	57,143	$	95,633
Regulatory liabilities:
RSE adjustment	$	1,740	$	—	$	2,931	$	—
Unbilled service margin	25,078		—		22,419		—
Postretirement liabilities	—		1,237		—		—
Gas supply adjustment	—		—		12,626		—
Refundable negative salvage	18,265		53,467		20,269		65,646
Asset retirement obligation	—		24,930		—		20,785
Other	33		770		34		803
Total regulatory liabilities	$	45,116	$	80,404	$	58,279	$	87,234

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 9,704	$ 9,541
Accounts receivable
Allowance for doubtful accounts	(6,549)	(12,946)
Accounts receivable, net of allowance for doubtful accounts of $12,946 at December 31, 2011, and $15,048 at December 31, 2010	277,900	231,925
Inventories
Storage gas inventory	32,205	44,047
Materials and supplies	28,291	26,420
Liquified natural gas in storage	3,498	3,545
Regulatory asset	45,515	57,143
Income tax receivable	6,664	7,343
Deferred income taxes	8,520	48,818
Prepayments and other	12,823	15,386
Total current assets	425,120	444,168
Property, Plant and Equipment
Oil and gas properties, successful efforts method	6,439,127	5,166,368
Less accumulated depreciation, depletion and amortization	1,765,241	1,382,526
Oil and gas properties, net	4,673,886	3,783,842
Utility plant	1,416,590	1,358,266
Less accumulated depreciation	573,947	544,838
Utility plant, net	842,643	813,428
Other property, net	25,107	23,506
Total property, plant and equipment, net	5,541,636	4,620,776
Other Assets
Regulatory asset	110,566	95,633
Pension and other postretirement assets	1,404	0
Long-term derivative instruments	40,577	31,056
Deferred charges and other	56,587	45,783
Total other assets	209,134	172,472
TOTAL ASSETS	6,175,890	5,237,416
Current Liabilities
Long-term debt due within one year	50,000	1,000
Notes payable to banks	643,000	15,000
Accounts payable	257,579	302,048
Accrued taxes	30,076	32,359
Customers' deposits	24,705	23,950
Amounts due customers	19,718	21,065
Accrued wages and benefits	24,984	35,258
Regulatory liability	45,116	58,279
Royalty payable	34,426	22,592
Deferred income taxes	24,667	1,469
Other	30,178	32,328
Total current liabilities	1,159,782	543,879
Long-term debt	1,103,528	1,153,700
Deferred Credits and Other Liabilities
Asset retirement obligation	118,023	107,340
Pension and other postretirement liabilities	110,282	62,532
Regulatory liability	80,404	87,234
Deferred income taxes	905,601	806,127
Long-term derivative instruments	11,305	34,663
Other	10,275	9,778
Total deferred credits and other liabilities	1,235,890	1,107,674
Commitments and Contingencies
Shareholders' Equity
Preferred stock, cumulative $0.01 par value	0	0
Common shareholders' equity
Common stock, $0.01 par value	751	750
Premium on capital stock	492,108	482,918
Capital surplus	2,802	2,802
Retained earnings	2,314,055	2,100,885
Accumulated other comprehensive income (loss), net of tax
Unrealized gain (loss) on hedges, net	46,352	9,273
Pension and postretirement plans	(52,507)	(38,584)
Interest rate swap	(2,156)	(941)
Deferred compensation plan	2,774	3,511
Treasury stock, at cost; 3,036,549 shares and 3,024,847 shares at December 31, 2011 and 2010, respectively	(127,489)	(128,451)
Total shareholders' equity	2,676,690	2,432,163
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	6,175,890	5,237,416
Alabama Gas Corporation
Current Assets
Cash and cash equivalents	5,559	7,817
Accounts receivable
Gas	94,011	96,812
Other	5,117	6,858
Affiliated companies	5,742	2,841
Allowance for doubtful accounts	(5,700)	(12,100)
Inventories
Storage gas inventory	32,205	44,047
Materials and supplies	5,528	4,183
Liquified natural gas in storage	3,498	3,545
Regulatory asset	45,515	57,143
Income tax receivable	2,762	9,762
Deferred income taxes	18,799	21,986
Prepayments and other	4,451	4,422
Total current assets	217,487	247,316
Property, Plant and Equipment
Utility plant	1,416,590	1,358,266
Less accumulated depreciation	573,947	544,838
Utility plant, net	842,643	813,428
Other property, net	42	43
Other Assets
Regulatory asset	110,566	95,633
Pension and other postretirement assets	848	0
Deferred charges and other	11,290	10,380
Total other assets	122,704	106,013
TOTAL ASSETS	1,182,876	1,166,800
Current Liabilities
Long-term debt due within one year	0	0
Notes payable to banks	77,000	15,000
Accounts payable	51,741	110,552
Accrued taxes	24,186	26,861
Customers' deposits	24,705	23,950
Amounts due customers	19,718	21,065
Accrued wages and benefits	6,703	12,971
Regulatory liability	45,116	58,279
Deferred income taxes	1,401	1,348
Other	9,018	9,250
Total current liabilities	258,187	277,928
Long-term debt	250,028	250,246
Deferred Credits and Other Liabilities
Pension and other postretirement liabilities	43,611	21,383
Regulatory liability	80,404	87,234
Deferred income taxes	189,381	181,492
Long-term derivative instruments	0	3,070
Other	762	709
Total deferred credits and other liabilities	314,158	293,888
Commitments and Contingencies
Shareholders' Equity
Preferred stock, cumulative $0.01 par value	0	0
Common shareholders' equity
Common stock, $0.01 par value	20	20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	325,999	310,234
Accumulated other comprehensive income (loss), net of tax
Total shareholders' equity	360,503	344,738
Total capitalization	610,531	594,984
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 1,182,876	$ 1,166,800

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Financial Instruments and Risk Management (Concentration of Credit Risk) (Details)	12 Months Ended
	Dec. 31, 2012
Accounts receivable | Largest Oil & Gas Purchasers, One
Concentration Risk [Line Items]
Concentration of credit risk	29.00%
Accounts receivable | Largest Oil & Gas Purchasers, Two
Concentration Risk [Line Items]
Concentration of credit risk	13.00%
Accounts receivable | Largest Oil & Gas Purchasers, Three
Concentration Risk [Line Items]
Concentration of credit risk	9.00%
Total operating revenues | Largest Oil & Gas Purchasers, One
Concentration Risk [Line Items]
Concentration of credit risk	27.00%
Total operating revenues | Largest Oil & Gas Purchasers, Two
Concentration Risk [Line Items]
Concentration of credit risk	12.00%
Natural Gas Distribution
Concentration Risk [Line Items]
Number of customers	425,000

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Energen Corporation (Energen or the Company) is a diversified energy holding company engaged primarily in the development, acquisition, exploration and production of oil and gas in the continental United States (oil and gas operations) and in the purchase, distribution and sale of natural gas principally in central and north Alabama (natural gas distribution). The following is a description of the Company's significant accounting policies and practices.

A. Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, principally Energen Resources Corporation and Alabama Gas Corporation (Alagasco), after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years' financial statements to the current-year presentation.

B. Oil and Gas Operations

Property and Related Depletion: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid 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. 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. 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 Revenue: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids 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 reserves for such property. Energen Resources had no material production imbalances at December 31, 2012 and 2011.

Derivative Commodity Instruments: Energen Resources recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps and basis hedges typically 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.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of December 31, 2012, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s 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.

The Company periodically enters into derivatives that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change. Open mark-to-market gains (losses) on derivatives included in operating revenues were as follows:

Years ended December 31, (in thousands)	2012		2011			2010
Mark-to-market gain (loss) on derivatives	$	58,750	$	(37,587	)	$	(3	)

All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the cash flow 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 hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness in hedging the exposure to the hedged transaction's variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the cash flow hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge.

Long-Lived Assets and Discontinued Operations: The Company reports gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for certain held-for-sale properties are reclassified and reported as discontinued operations for prior periods. Energen Resources 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 fair value.

Acquisitions: Energen Resources recognizes all acquisitions at fair value. Energen Resources estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen Resources 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 Resources 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 operations and maintenance expense on the consolidated income statements.

C. Natural Gas Distribution

Regulatory Accounting: Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) with respect to rates, accounting and various other matters. In general, Alagasco capitalizes or defers certain costs or revenues, based on the approvals received from the APSC, to be recovered from or refunded to customers in future periods. These costs or revenues are recorded as regulatory assets or liabilities.

Utility Plant and Depreciation: Property, plant and equipment are stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. Gains and losses on all dispositions of land are recognized at time of disposal. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets are charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the APSC. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $14.2 million, $22.2 million and $2.7 million for the period January through December 2012, January through December 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $18.3 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $53.5 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a seven year period beginning January 1, 2013. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the Enhanced Stability Reserve (ESR) and other commission-approved charges. The refunds as of December 2012 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates. Approved depreciation rates averaged approximately 3.2 percent, 3.1 percent and 3.6 percent in the years ended December 31, 2012, 2011 and 2010, respectively. The revised depreciation rates decreased depreciation expense by approximately $6.8 million and $9.2 million for the years ended December 31, 2011 and 2010, respectively, from expense amounts calculated using the prior depreciation rate.

Inventories: Inventories, which consist primarily of gas stored underground, are stated at average cost. Liquified natural gas is stated at base cost.

Operating Revenue and Gas Costs: Alagasco records natural gas distribution revenues in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material gas imbalances at December 31, 2012. Alagasco had gas imbalances of $0.5 million at December 31, 2011.

Derivative Commodity Instruments: In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet at fair value. Any realized gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco's APSC approved tariff and are recognized as a regulatory asset or regulatory liability. 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 Alagasco.

Taxes on revenues: The collection and payment of revenue taxes such as utility license taxes and fees, franchise fees and taxes imposed by other governmental authorities are reported on a gross basis. These amounts are included in taxes other than income taxes on the consolidated statements of income as follows:

Years ended December 31, (in thousands)	2012		2011		2010
Taxes on revenues	$	21,479	$	25,268	$	30,704

The collection and payment of utility gross receipts tax is presented on a net basis.

D. Fair Value Measurements

The carrying values of cash and cash equivalents, accounts payable and receivable, 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). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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 fair value hierarchy that prioritizes the inputs used to measure fair value is defined 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 assumption that market value 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.

Derivative commodity instruments are over-the-counter derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These 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 the Company is 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 New York Mercantile Exchange natural gas and oil futures. 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. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties' valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.

Pension and postretirement plan assets include mutual and comingled funds and a limited partnership. 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 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.

E. Income Taxes

The Company 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. The Company 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 the Company's best estimate of the amount of probable credit losses in the existing accounts receivable. The Company 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 Equivalents

All highly liquid financial instruments with an original maturity of three months or less at the time of purchase are considered to be cash or cash equivalents.

As of December 31, 2012, the Company and Alagasco revised the presentation of outstanding checks in its financial statements. Previously, the Company and Alagasco reflected outstanding checks as a reduction in cash as of the date the checks cleared the bank as opposed to the date the checks were released for payment. Under the revised presentation, as of December 31, 2011, Energen's cash and accounts payable would have been reduced by $8.0 million and $7.3 million, respectively, while accounts receivable would have increased by $0.7 million. Under the revised presentation, as of December 31, 2011, Alagasco's cash and accounts payable would have been reduced by $6.8 million and $6.1 million, respectively, while accounts receivable would have increased by $0.7 million. The Company and Alagasco considered the impact of this adjustment on the December 31, 2011 balance sheets and statements of cash flows for the year then ended and determined that the amounts were not material. The effect of not revising the presentation of cash balances as of December 31, 2011, but presenting the correct cash balances at December 31, 2012, resulted in a decrease of $8.0 million and $6.8 million to Energen and Alagasco's 2012 operating cash flows, respectively. This adjustment caused no impact to Energen or Alagasco's income statements.

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, 2012 and 2011, Energen had no short-term investments.

I. Earnings Per Share (EPS)

The Company'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

The Company 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. The Company recognizes all stock-based compensation expense in the period of grant for retirement eligible employees. The Company utilizes the long-form method of calculating the available pool of windfall tax benefit. For 2012 and 2011, the Company recognized an excess tax benefit of $0.6 million and $1.0 million, respectively, related to its 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 oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that regulatory accounting will continue as the applicable accounting standard for the Company's regulated operations, the Company'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, self insurance reserves and regulatory assets and liabilities. 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 two defined benefit non-contributory qualified pension plans. These plans cover substantially all employees. Pension benefits for the majority of the Company’s employees are based on years of service and final earnings; one plan is based on years of service and flat dollar amounts. The Company also has nonqualified supplemental pension plans covering certain officers of the Company. In addition to providing pension benefits, the Company provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. The Company continues to provide these benefits to certain non-salaried employees. Substantially all of the Company's employees may become eligible for certain benefits if they reach normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.

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

Measurement: The Company calculates periodic expense for defined benefit pension plans and other post retirement 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 pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. Alagasco recognizes a regulatory asset for the portion of the obligation to be recovered in rates in future periods and a regulatory liability for the portion of the plan obligation to be provided through rates in the future. The Company measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.

Discount Rate: In selecting each discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company 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.

Long-Term Rate of Return: The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The Company 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. As more fully described in Note 2, Regulatory Matters, and as currently approved, the ESR provides deferred treatment and recovery for extraordinary operations and maintenance (O&M) expenses related to environmental response costs.

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Income Taxes (Unrecognized Tax Benefits) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance	$ 10,593,000	$ 24,590,000	$ 17,797,000
Additions based on tax positions related to the current year	3,731,000	3,644,000	1,436,000
Additions for tax positions of prior years	269,000	2,324,000	11,703,000
Reductions for tax positions of prior years (lapse of statute of limitations)			(3,624,000)
Reductions for tax positions of prior years	(446,000)	(39,000)
Lapse of statute of limitations	(1,592,000)	(1,482,000)	(1,313,000)
Settlements		(18,444,000)	(1,409,000)
Unrecognized Tax Benefits, Ending Balance	12,555,000	10,593,000	24,590,000
Gross addition (reduction)		5,900,000	(3,600,000)
Unrecognized income tax benefit liability, additions (release)	(5,100,000)	2,900,000	2,400,000
Full amount of tax benefit, chance of being realized, percentage	50.00%
Liability (benefit) adjustment due to settlement with IRS		1,500,000
Income tax interest (net of tax benefit) and penalties expense (income)	0	1,400,000	800,000
Accrued interest (net of tax benefit) and penalties payments	200,000	200,000
Alabama Gas Corporation
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance	102,000	18,941,000	7,621,000
Additions based on tax positions related to the current year	62,000	13,000	9,000
Additions for tax positions of prior years	201,000	1,000	11,645,000
Reductions for tax positions of prior years (lapse of statute of limitations)	(58,000)	(409,000)	(90,000)
Settlements		(18,444,000)	(244,000)
Unrecognized Tax Benefits, Ending Balance	307,000	102,000	18,941,000
Income tax interest (net of tax benefit) and penalties expense (income)	1,000	1,400,000	1,000,000
Accrued interest (net of tax benefit) and penalties payments	$ 4,000	$ 5,000

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Financial Instruments and Risk Management (Financial Instruments and Finance Receivables) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Financing Receivable, Allowance for Credit Losses [Roll Forward]
Allowance for credit losses, beginning balance	$ 421,000	$ 447,000
Provision	49,000	(26,000)
Allowance for credit losses, ending balance	470,000	421,000
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,255,800,000	1,214,900,000
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	1,154,000,000	1,155,200,000
Alabama Gas Corporation
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Recorded Unconditional Purchase Obligation	300,000
Recorded Unconditional Purchase Obligation, Market Value	300,000
Financing Receivable	10,700,000	10,500,000
Financing Receivable, Recorded Investment, Average Balance 0 to 60 Days Past Due	3,000
Average Finance Receivable Term	up to 60 months
Financing Receivable, Recorded Investment, Equal to Greater than 90 Days Past Due	500,000	400,000
Alabama Gas Corporation | Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	284,700,000	274,900,000
Alabama Gas Corporation | Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 300,000,000	$ 300,000,000

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Common Stock Plans (Performance Share Awards) (Details) (Performance Share Awards, Stock Incentive Plan, USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2010
Performance Share Awards | Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Each unit of performance share awards equivalent to market value of number of common stock (shares)	1
Share-based compensation, vesting period	4 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Nonvested, Beginning of Period, Shares		111,143
Nonvested, Beginning of Period, Weighted Average Price		$ 43.81
Vested, Shares		(111,143)
Vested, Weighted Average Price		$ 43.81
Nonvested, End of Period, Shares		0
Nonvested, End of Period, Weighted Average Price		$ 0.00

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Industry Segment Information

12 Months Ended

Dec. 31, 2012

Segment Reporting [Abstract]

Segment Information

INDUSTRY SEGMENT INFORMATION

The Company is principally engaged in two business segments: the development, acquisition, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution). The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies.

Years ended December 31,(in thousands)	2012			2011			2010
Operating revenues
Oil and gas operations	$	1,165,580		$	948,526		$	958,762
Natural gas distribution	451,589			534,953			619,772
Total	$	1,617,169		$	1,483,479		$	1,578,534
Operating income (loss)
Oil and gas operations	$	367,243		$	363,131		$	406,729
Natural gas distribution	93,216			86,216			88,383
Eliminations and corporate expenses	(1,067		)	(1,078		)	(1,735		)
Total	$	459,392		$	448,269		$	493,377
Depreciation, depletion and amortization expense
Oil and gas operations	$	377,328		$	244,081		$	203,823
Natural gas distribution	42,270			39,916			44,042
Total	$	419,598		$	283,997		$	247,865
Interest expense
Oil and gas operations	$	49,972		$	30,907		$	25,753
Natural gas distribution	16,284			14,740			13,894
Eliminations and other	(700		)	(825		)	(425		)
Total	$	65,556		$	44,822		$	39,222
Income tax expense (benefit)
Oil and gas operations	$	114,375		$	120,079		$	138,775
Natural gas distribution	30,244			26,670			29,875
Other	(800		)	(1,048		)	(1,660		)
Total	$	143,819		$	145,701		$	166,990
Capital expenditures
Oil and gas operations	$	1,291,211		$	1,115,452		$	717,782
Natural gas distribution	71,869			73,984			93,566
Total	$	1,363,080		$	1,189,436		$	811,348
Identifiable assets
Oil and gas operations	$	4,975,170		$	4,046,242		$	3,160,601
Natural gas distribution	1,177,134			1,163,959			1,166,899
Eliminations and other	23,586			27,215			36,060
Total	$	6,175,890		$	5,237,416		$	4,363,560
Property, plant and equipment, net
Oil and gas operations	$	4,697,683		$	3,806,787		$	2,936,284
Natural gas distribution	842,685			813,471			782,665
Other	1,268			518			278
Total	$	5,541,636		$	4,620,776		$	3,719,227

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Common Stock Plans (Restricted Stock) (Details) (Restricted Stock, Stock Incentive Plan, USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Restricted Stock | Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation, vesting period	3 years
Share-based compensation expense	$ 100,000	$ 100,000	$ 200,000
Tax benefit related to stock-based compensation	31,000	47,000	70,000
Unrecognized compensation cost	$ 500,000
Remaining requisite service period (in years)	2 years 11 months 16 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Nonvested, Beginning of Period, Shares	9,275	24,150	53,005
Nonvested, Beginning of Period, Weighted Average Price	$ 42.99	$ 35.49	$ 32.66
Vested, Shares	(9,275)	(14,875)	(28,855)
Vested, Weighted Average Price	$ 42.97	$ 30.81	$ 30.30
Granted, Shares	11,115
Granted, Weighted Average Price	$ 45.24
Nonvested, End of Period, Shares	11,115	9,275	24,150
Nonvested, End of Period, Weighted Average Price	$ 45.24	$ 42.99	$ 35.49

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Schedule of change in asset retirement obligation

In 2012, 2011 and 2010, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2009	$	88,298
Liabilities incurred	4,033
Liabilities settled	(1,094		)
Accretion expense	6,178
Balance of ARO as of December 31, 2010	97,415
Liabilities incurred	4,627
Liabilities settled	(1,539		)
Accretion expense	6,837
Balance of ARO as of December 31, 2011	107,340
Liabilities incurred	3,994
Liabilities settled	(845		)
Accretion expense	7,534
Balance of ARO as of December 31, 2012	$	118,023

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2012

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental information concerning Energen's cash flow activities was as follows:

Years ended December 31, (in thousands)	2012		2011		2010
Interest paid, net of amount capitalized	$	61,379	$	33,601	$	37,517
Income taxes paid	$	17,170	$	9,432	$	83,894
Noncash investing activities:
Accrued development, exploration costs and other capital	$	120,024	$	72,030	$	75,167
Capitalized depreciation	$	80	$	93	$	116
Capitalized asset retirement obligations costs	$	4,409	$	4,927	$	4,194
Allowance for funds used during construction	$	623	$	807	$	808
Capital lease obligations	$	5,072	$	—	$	—
Noncash financing activities:
Issuance of common stock for employee benefit plans	$	838	$	822	$	5,765
Treasury stock acquired in connection with tax withholdings	$	277	$	713	$	2,894

The Company recorded a non-cash adjustment for accretion expense of $7.5 million, $6.8 million and $6.2 million during 2012, 2011 and 2010, respectively.

Supplemental information concerning Alagasco's cash flow activities was as follows:

Years ended December 31, (in thousands)	2012		2011		2010
Interest paid, net of amount capitalized	$	13,513	$	12,385	$	11,653
Income taxes paid	$	16,796	$	5,143	$	13,063
Interest on affiliated company debt, net	$	295	$	376	$	274
Noncash investing activities:
Accrued property, plant and equipment costs	$	3,536	$	2,229	$	2,592
Capitalized depreciation	$	80	$	93	$	116
Capitalized asset retirement obligations costs	$	415	$	300	$	161
Allowance for funds used during construction	$	623	$	807	$	808

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Oil and Gas Operations (Unaudited) (Oil and Gas Operations) (Details)	12 Months Ended
	Dec. 31, 2012 MMBoe	Dec. 31, 2011 MMBoe	Dec. 31, 2010 MMBoe
Reserve Quantities [Line Items]
Percentage of proved reserves audited by independent reservoir enginners	99.00%
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period, total	343.1	302.9	257.8
Revisions of previous estimates, total	(42.1)	(5.8)	11.3
Purchases, total	12.4	20.8	25.8
Extensions and discoveries, total	57.1	45.6	26.8
Production, total	(24.1)	(20.4)	(18.8)
Sales, total			0.0
Proved reserves at end of period, total	346.4	343.1	302.9
Proved developed reserves at end of period (BOE)	260.5	248.5	231.9
Proved undeveloped reserves at end of period (BOE)	85.9	94.6	71.0
Natural Gas Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period	957,368	954,387	897,546
Revisions of previous estimates	(143,704)	(12,823)	66,679
Purchases	10,656	19,362	21,700
Extensions and discoveries	61,170	68,160	39,570
Production	(76,362)	(71,718)	(70,924)
Sales			(184)
Proved reserves at end of period	809,128	957,368	954,387
Proved developed reserves at end of period (volume)	708,657	788,812	786,292
Proved undeveloped reserves at end of period (volume)	100,471	168,556	168,095
Oil Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period	129,578	103,262	77,963
Revisions of previous estimates	(8,546)	(4,513)	(2,243)
Purchases	7,950	12,583	16,443
Extensions and discoveries	35,132	24,564	16,234
Production	(8,766)	(6,318)	(5,131)
Sales			(4)
Proved reserves at end of period	155,348	129,578	103,262
Proved developed reserves at end of period (volume)	105,976	83,899	72,030
Proved undeveloped reserves at end of period (volume)	49,372	45,679	31,232
Natural Gas Liquids Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved reserves at beginning of period	53,957	40,601	30,257
Revisions of previous estimates	(9,557)	841	2,434
Purchases	2,569	5,055	5,730
Extensions and discoveries	11,759	9,637	4,058
Production	(2,573)	(2,177)	(1,880)
Sales			2
Proved reserves at end of period	56,155	53,957	40,601
Proved developed reserves at end of period (volume)	36,440	33,154	28,809
Proved undeveloped reserves at end of period (volume)	19,715	20,803	11,792