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 payadd 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-toproduction 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 yearend 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 longlived 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 for 2013 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 endusers 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. During 2012, 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 35th 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 5 5 President and Chief Operating Officer of Energen Resources (4)

Dudley C. Reynolds 5 9 President and Chief Operating Officer of Alagasco (5)

J. David Woodruff, Jr. 5 6 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 $ 9 5 $ 97

S15GASUX $ 100 $ 76 $ 9 6 $ 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

19
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

20
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

21
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.

22
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-tomarket 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.

23
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).

27
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

28
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

29
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 longerterm 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.

30
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.

33
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

34
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.

35
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-thanexpected 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 9 9

Alabama Gas Corporation

Schedule II - Valuation and Qualifying Accounts 9 9

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 index presents 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 Reporting appearing 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 appearing 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

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'

(in thousands, except share data) Equity

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.

52
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 heldfor-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.

5 5
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 shortterm investments. As of December 31, 2012 and 2011, Energen had no short-term investments.

5 6
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.

57
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 5 5 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.

58
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 — —

5 9
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 6 5 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 6 5

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.

60
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

61
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)

62
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

63
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

64
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.

6 5
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.

6 6
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

67
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

68
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

6 9
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.

70
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

71
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 nonqualified, 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.

75
2004 Stock Appreciation Rights Plan: The Energen 2004 Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the longterm 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

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.

77
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 35th 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

78
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.

79
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 commodityrelated 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 thirdparty 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.

87
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

88
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 5 9 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.

89
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 6 5 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

91
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

92
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 9 9 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

94
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.

9 5
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

9 6
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

97
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

9 9
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 13a15(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
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»
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»
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»
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 1.1 Definitions. When used in this document with initial capital letters, the following terms have the meanings

indicated unless a different meaning is plainly required by the context:

(a) “Account” or “Accounts” means the account or accounts established and maintained for a Participant pursuant to

Article IV of the Plan. A Participant’s Account shall consist of the Participant’s Investment Account and the Participant’s Company

Stock Account.

(b) “Alagasco” means Alabama Gas Corporation, a 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.

1
(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

2
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

3
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.

4
(dd) “Plan” means the Energen Corporation 1997 Deferred Compensation Plan, as amended, which is maintained by

Energen and its affiliated companies primarily for the purpose of providing financial incentives for directors and certain key employees

of Energen and its affiliated companies.

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

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

(gg) “Trust” means the trust described in Section 12.4. The Trust shall constitute an unfunded arrangement and shall

not affect the status of the Plan as an unfunded plan. Participants and their beneficiaries shall have no beneficial ownership interest in any

assets of any such Trust.

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

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

Participant in accordance with the terms of the Plan.

ARTICLE II.

PARTICIPATING EMPLOYERS

Section 2.1 Eligibility. To be eligible to adopt and participate in the Plan, an employer must be a member of the “controlled

group” of corporations, within the meaning of Section 414 of the Code, that includes Energen and must be determined to be eligible to

participate in the Plan by Energen. The corporations which are eligible to participate in this Plan as of January 1, 2008, are Energen,

Alagasco, Resources, Basin, and EGN.

Section 2.2 Participation Reimbursements. Energen, the sponsor of the Plan, Alagasco, Resources, Basin, and EGN, are

Participating Employers in the Plan effective as of January 1, 2008. Any other affiliated company that is or becomes eligible to adopt the

Plan and become a Participating Employer pursuant to Section 2.1 of the Plan may, with the approval of the Board of Directors by

resolution of the Board of Directors, adopt this Plan and become a Participating Employer in the Plan. The date on which such eligible

company may become a Participating Employer in the Plan shall be stated in the resolutions of the Board of Directors. Each of the

Participating Employers agree to make payments of their allocable portion of the benefits provided under the Plan to their respective

employee and Director Participants. Energen hereby guarantees the performance by each of the other Participating Employers of their

respective obligations under the Plan. Neither the respective benefit payment obligations of the Participating Employers nor Energen’s

guarantee of performance is secured in any way. Such obligations and guarantee constitute no more than unfunded and unsecured

promises of payment and performance. Each Participating Employer, other than Energen, shall reimburse Energen for its allocable

share of costs and expenses paid by Energen in connection with the operation and administration of the Plan, and shall reimburse

Energen for any benefits paid by Energen under the Plan to Participants to the extent allocable to such Participating

5
Employer and its Participants. Payments made to Participants by the Trust shall constitute payments by Energen and Energen shall be

reimbursed for such payments by the appropriate Participating Employers.

Section 2.3 Recordkeeping and Reporting. Each Participating Employer, other than Energen, shall furnish to Energen the

information with respect to each of its Participants necessary to enable Energen to maintain records sufficient to determine the benefits

(and the compensation sources of such benefits) which may become payable to or with respect to such Participants and to give those

Participants any reports which may be required under the terms of the Plan or by law.

Section 2.4 Termination of Participation. A Participating Employer, other than Energen, may withdraw from participation in

the Plan at any time by providing Energen with 30 days advance written notice of such withdrawal from participation and the effective

date of such Participating Employer’s withdrawal, which 30 ‐day notice period may be waived by Energen. In addition, Energen may

terminate a Participating Employer’s participation in the Plan by providing such Participating Employer with 30 days advance written

notice, which 30‐day notice period may be waived by the Participating Employer. A Participating Employer which terminates its

participation in the Plan shall remain obligated under the Plan with respect to deferrals made prior to such termination by its Participants

(including subsequent investment performance adjustments), unless otherwise expressly agreed by Energen with Energen fully

assuming such obligations.

Section 2.5 Separate Accounting. Energen shall establish and maintain separate Accounts for each of the Participating

Employers and their respective Participants. Such separate accounting is intended to comply with Section 404(a)(5) of the Code and

Section 1.404(a) ‐ 12 of the Treasury Regulations (which provide that an employer can deduct the amounts contributed to a nonqualified

plan in the taxable year in which an amount attributable to the contribution is includable in the gross income of employees participating in

the plan, but, in the case of a plan in which more than one employee participates only if separate accounts are maintained for each

employee).

ARTICLE III.

ELIGIBILITY AND PARTICIPATION

Section 3.1 Eligibility. Each Director and each Officer of a Participating Employer shall be eligible to participate in the Plan

effective as of the later of the effective date of the Plan or the date on which such individual first becomes a Director or Officer. In

addition, the 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 3.2 Participation. An individual eligible to participate in the Plan shall become a Participant upon the filing with

Energen of a completed Deferral Election Form and acceptance of such form by Energen. The name of each individual eligible to

participate in the Plan and the date on which such individual becomes a Participant in the Plan, shall be recorded on Exhibit A, which

exhibit is attached hereto and incorporated herein by reference and which shall be revised by Energen

6
from time to time to reflect the operation of the Plan. Once an individual becomes a Participant in the Plan, the individual shall remain a

Participant until the benefits which may be payable to the individual under the Plan have been distributed to or on behalf of the

individual.

Section 3.3 Suspension of Eligibility. The 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 4.1 Deferred Compensation. A Participant may elect to defer receipt of part or all of any one or more of the following

items of compensation:

(a) Base salary;

(b) Annual Incentive Compensation Plan awards;

(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 4.2 Form 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

7
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 4.3 Participant Accounts. A Pre-2005 Company Stock Account, a Post-2004 Company Stock Account, or Pre-2005

Investment Account and a Post-2004 Investment Account shall be established and maintained for each Participant. Except as otherwise

directed by the 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 4.4 Discretionary Amounts. In addition to amounts deferred by a Participant, the Board of Directors may from time to

time, in its sole discretion, authorize a Participant’s Participating Employer to credit the Participant’s 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 5.1 Vested Benefit. A Participant shall be considered to be 100% Vested in his or her Account.

Section 5.2 Limitation on Benefits. The benefits that may be payable to or on behalf of a Participant under the Plan shall be

equal to a cash payment equal to the value of the amounts credited to the Participant’s Investment Accounts and a distribution of that

number of Common Shares equal to the number of shares credited to the Participant’s Company Stock Accounts (with any fractional

share being rounded to a whole share).

ARTICLE VI.

8
DISTRIBUTIONS.

Section 6.1 Distributable Events. A Participant’s Distributable Event shall be the first to occur of the following events;

provided, that events (b) - (e) shall be Distributable Events only if so elected by the Participant in the Deferral Election Form and

further provided that 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 6.2 Distribution of Benefits.

(a) Distribution Commencement Date . Excepting withdrawals under Sections 6.3 and 6.4 which shall be distributed

in accordance with those Sections and subject to Section 6.8 and to reasonable time for administrative direction and processing,

distribution of a Participant’s Plan benefit shall commence as of the first day of the second calendar month immediately following the

calendar month in which the Participant’s applicable Distributable Event occurs.

9
(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 6.3 Early 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

10
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 6.4 Hardship Withdrawals. In addition to the other distribution and withdrawal provisions of this Article VI and

notwithstanding any provision herein to the contrary, in the event a Participant incurs an unforeseeable emergency, the Participant may

request, by providing a written request to the 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 6.5 Distributions as Result of Tax Determination. Notwithstanding any provision in this Plan to the contrary, if, at any

time, a court or the Internal Revenue Service determines that any amounts or shares credited to a Participant’s Accounts under the Plan

or Trust are includable in the gross income of the Participant and subject to tax pursuant to Section 409A of the Code, the 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 6.6 No 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 6.7 Distribution Upon Termination for Cause. In the event that a Participant is terminated for Cause (as defined

below), the Company shall treat such termination as a Distributable Event. For purposes of this Plan, termination for Cause means

termination based on any of the following:

11
(i) The willful and continued failure by the Participant to substantially perform Participant’s duties with a

Participating Employer (other than any such failure resulting from Participant’s incapacity due to physical or mental illness) after a

written demand for substantial performance is delivered to Participant specifically identifying the manner in which Participant has not

substantially performed Participant’s duties;

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

Participating Employers monetarily or otherwise; or

(iii) the conviction of Participant of a felony.

Section 6.8 Delay in Payments for Specified Employees. With respect to any payments from the Plan subject to the provisions

of Section 409A(a)(2)(B)(i) of the Code, distribution of the amounts attributable to a Participant’s Post-2004 Company Stock Account

and Post-2004 Investment Account shall be paid as promptly as practicable following the date that is six months following the

Distributable Event giving rise to such payment.

ARTICLE VII.

VALUATION OF BENEFITS.

Section 7.1 Company Stock Accounts.

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

12
Director Fees or other cash compensation be allocated to the Participant’s Company Stock Account. A Participant’s request to make such

an allocation or change a previous allocation must be in writing on an Allocation Request Form. All such requests are subject to

acceptance by Energen in its discretion. If accepted by Energen, the allocation request will be effective as of the allocation date specified

by the request (as defined in Section 7.4).

Section 7.2 Investment Account.

(a) Interest. Subject to 7.2(b), as of the close of the last day of each calendar quarter, an additional amount shall be

credited to each Participant’s Investment Accounts equal to the product of (i) the average daily balance in such Investment Account for

the quarter, times (ii) one-fourth of the annual prime rate for corporate borrowers quoted at the beginning of the quarter by Regions

Bank of Alabama, Birmingham, Alabama (or such other comparable interest rate as the 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 7.3 Hypothetical Accounts. The Accounts established under this Plan shall be hypothetical in nature and shall be

maintained for bookkeeping purposes only. Neither the Plan nor any of the Accounts (or subaccounts) shall hold or be required to hold

any actual funds or assets.

Section 7.4 Allocation Date. Upon acceptance of an allocation request pursuant to Section 7.1(e) or 7.2(c), Energen will

process the request as soon as reasonably administratively practicable and the request shall be implemented and reflected in the

Participant’s account as of the close of business on such date as may be determined by Energen in its reasonable discretion (the

“allocation date”).

Section 7.5 Contribution Timing. Subject to the authority of the 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 8.1 Anti‐Alienation of Benefits. Any benefits which may be credited to a Participant’s Accounts under the Plan, and

any rights or privileges pertaining thereto, may not be anticipated, alienated, sold, transferred, assigned, pledged, encumbered, or

subjected to any charge or legal process; and no interest or right to receive a benefit may be taken, either voluntarily or involuntarily, for

the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support,

separate maintenance and claims in bankruptcy proceedings.

Section 8.2 Incompetent Participants. If any person who may be eligible to receive a payment under the Plan has been legally

declared incompetent and a conservator or other person legally charged with the care of such person or of his or her estate has been

appointed, any payment under the Plan to which the person is eligible to receive shall be paid to such conservator or other person legally

charged with the care of the person or his or her estate. Any such payment shall be a payment for the account of such person and a

complete discharge of any liability of the Participating Employers and the Plan therefor.

Section 8.3 Designated Beneficiary. In the event of a Participant’s death prior to the payment of all or a portion of any benefits

which may be payable with respect to the Participant under the Plan, the payment of any benefits payable on behalf of the Participant

under the Plan shall be made to the Participant’s beneficiary designated on a Deferral Election Form. If no such beneficiary has been

designated, payment shall be made as required under the Participant’s will; or, in the event that there shall be no functioning will under

applicable state law, then to such persons as, at the date of the Participant’s death, would be entitled to share in the distribution of such

deceased Participant’s personal estate under the provisions of the applicable statute then in force governing the decedent’s intestate

property, in the proportions specified in such statute.

ARTICLE IX.

WITHHOLDING

Section 9.1 Withholding. Each Participant shall, no later than the date as of which amounts payable under the Plan first

become subject to taxation, pay to Energen, or make arrangements satisfactory to Energen, regarding payment of, any Federal, FICA,

state, or local taxes of any kind required by law to be withheld with respect to the Award. The obligations of Energen and the

Participating Employers under the Plan shall be conditional on such payment or arrangements. Energen and, where applicable, the

Participating Employers shall, to the extent permitted by law, have the right to deduct any such taxes owed hereunder by a Participant

from any payment of any kind otherwise due to said Participant. The 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 10.1 Voting of Company Stock. No Participant shall be entitled to any voting rights with respect to any shares credited

to his or her Company Stock Account.

ARTICLE XI.

ADMINISTRATION OF A PLAN

Section 11.1 Administrator. The administrator of the Plan shall be Energen. However, the Board of Directors shall act on

behalf of Energen with respect to the administration of the Plan and may delegate authority with respect to the administration of the Plan

to the 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 11.2 Authority of Administrator. Energen shall have the authority, duty and power to interpret and construe the

provisions of the Plan as it deems appropriate, to adopt, establish and revise rules, procedures and regulations relating to the Plan, to

determine the conditions subject to which any benefits may be payable, to resolve all questions concerning the status and rights of

Participants and others under the Plan, including, but not limited to, eligibility for benefits and to make any other determinations which it

believes necessary or advisable for the administration of the Plan. Energen shall have the duty and responsibility of maintaining records,

making the requisite calculations and disbursing payments hereunder. The determinations, interpretations, regulations and calculations of

Energen shall be final and binding on all persons and parties concerned. The Secretary of Energen shall be the agent of the Plan for the

service of legal process in accordance with Section 502 of the Employee Retirement Income Security Act of 1974, as amended.

Section 11.3 Operation of Plan and Claims Procedures. Energen shall be responsible for the general operation and

administration of the Plan and for carrying out the provisions thereof. Energen shall be responsible for the expenses incurred in the

administration of the Plan. Energen shall also be responsible for determining eligibility for payments and the amounts payable pursuant

to the Plan. Energen shall be entitled to rely conclusively upon all tables, valuations, certificates, opinions and reports furnished by any

actuary, accountant, controller, counsel or other person employed or engaged by Energen with respect to the Plan. The procedures for

filing claims for payments under the Plan are described below. For claims procedures purposes, the “Claims Manager” shall be Energen.

(a) Claims Procedures. It is the intent of Energen to make payments under the Plan without the Participant having to

complete or submit any claims forms. However, a Participant who believes he or she is entitled to a payment under the Plan may submit

a claim for payments in writing to Energen. Any claim for payments under the Plan must be made by the Participant or his or her

beneficiary in writing and state the claimant’s name and the nature of benefits payable under the Plan on a form acceptable to Energen.

The Claims Manager shall notify any person or entity

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, the notice shall set forth (1) the specific reasons for such denial,

(2) a specific reference to the provisions of the Plan on which the denial is based, (3) any internal protocols the Claims Manager relied

upon in making its determination, (4) the right to review any documents created or received by the Claims Manager during the review

process and documents relevant to the claim whether or not relied upon by the Claims Manager, (5) a description of any additional

information or material necessary for the Claimant to perfect his or her claim and a description of why it is needed, and (6) an

explanation of the Plan’s claims review procedure and other appropriate information as to the steps to be taken if the Claimant wishes to

have the claim reviewed. If the Claims Manager determines that there are special circumstances requiring additional time to make a

decision, the Claims Manager shall notify the Claimant of the special circumstances and the date by which a decision is expected to be

made, and may extend the time for up to an additional 60 days.

(b) Review Procedure. If the Claimant is determined by the Claims Manager not to be eligible for benefits, or if the

Claimant believes that he or she is entitled to greater or different benefits, the Claimant shall have the opportunity to have such claim

reviewed by the Claims Manager by filing a petition for review with the Claims Manager within 60 (180 days for a claim for benefits on

account of Disability), days after receipt of the notice issued by the Claims Manager. Said petition shall state the specific reasons that the

Claimant believes entitle him or her to benefits or to greater or different benefits. Within 60 days (45 days for a claim for benefits on

account of Disability) after receipt by the Claims Manager of the petition, the Claims Manager shall afford the Claimant (and counsel, if

any) an opportunity to present his or her position to the Claims Manager verbally or in writing, and the Claimant (or counsel) shall have

the right to review the pertinent documents. The Claims Manager shall notify the Claimant of its decision in writing within such period,

stating specifically the basis of its decision, written in a manner to be understood by the Claimant and the specific provisions of the Plan

on which the decision is based. If, because of the need for a hearing, the 60-day period is not sufficient, the decision may be deferred for

up to another 30 days (15 days for a claim for benefits on account of Disability) at the election of the Claims Manager, but notice of this

deferral shall be given to the Claimant.

Section 11.4 Participant’s Address. Each Participant shall keep Energen informed of his or her current address and the current

address of his or her beneficiary. Energen shall not be obligated to search for any person. If the location of a Participant is not made

known to Energen within three (3) years after the date on which payment of the Participant’s benefits payable under the Plan may be

made, payment may be made as though the Participant had died at the end of the three-year period. If, within one (1) additional year after

such three‐year period has elapsed, or, within three (3) years after the actual death of a Participant, Energen is unable to locate any

designated beneficiary of the Participant, then Energen shall have no further obligation to pay any benefit hereunder to or on behalf of

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

ARTICLE XII.

16
MISCELLANEOUS PROVISIONS

Section 12.1 No Employment Rights. Neither the Plan nor any action taken hereunder shall be construed as giving any

Participant any right to be retained in the service or employ of any Participating Employer.

Section 12.2 Participants Should Consult Advisors. Neither any Participating Employer, nor their respective directors,

officers, employees or agents makes any representation or warranty with respect to the state, federal or other tax, financial, estate

planning, or the securities or other legal implications of participation in the Plan. Participants should consult with their own tax, financial

and legal advisors with respect to their participation in the Plan.

Section 12.3 Unfunded and Unsecured. The Plan shall at all times be considered entirely unfunded both for tax purposes and

for purposes of Title I of the Employee Retirement Income Security Act of 1974, as amended, and no provision shall at any time be

made with respect to segregating assets of any Participating Employer for payment of any amounts hereunder. Any funds invested

hereunder allocable to a Participating Employer shall continue for all purposes to be part of the respective general assets of such

Participating Employer and available to the general creditors of such Participating Employer in the event of a bankruptcy (involvement

in a pending proceeding under the Federal Bankruptcy Code) or insolvency (inability to pay debts as they mature) of such Participating

Employer. Energen shall promptly notify the Trustee and the applicable Participants of such bankruptcy or insolvency of a Participating

Employer. No Participant or any other person shall have any interests in any particular assets of any Participating Employer by reason of

the right to receive a benefit under the Plan and to the extent the Participant or any other person acquires a right to receive benefits

under the Plan, such right shall be no greater than the right of any general unsecured creditor of any Participating Employer. The Plan

constitutes a mere promise by the Participating Employers to make payments to the Participants in the future. With respect to the

guarantee of Energen under Section 2.2, Participants have rights only as general unsecured creditors of Energen. Nothing contained in

the Plan shall constitute a guaranty by any Participating Employer or any other person or entity that any funds in any trust or the assets

of any Participating Employer will be sufficient to pay any benefit hereunder. Furthermore, no Participant shall have any right to a

benefit under the Plan except in accordance with the terms of the Plan.

Section 12.4 The Trust.

(a) Establishment of Trust. In order to provide assets from which to fulfill its obligations to the Participants and their

beneficiaries under the Plan, Energen shall establish a Trust by a trust agreement with a third party, the Trustee, to which Energen

may, in its discretion, contribute cash or other property, including securities issued by Energen, to provide for the benefit payments

under the Plan. The Trustee will have the duty to invest the Trust assets and funds in accordance with the terms of the Trust. Energen

shall be entitled at any time, and from time to time, in its sole discretion, to substitute assets of at least equal fair market value for any

assets held in the Trust. All rights associated with the assets of the Trust will be exercised by the Trustee or the person designated by the

Trustee, and will in no event be exercisable by or rest with Participants or their beneficiaries. The Trust shall provide that in the event

of the insolvency of Energen, the Trustee shall hold the assets for the benefit of the general creditors of Energen and its affiliated

companies. The Trust

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

plural.

Section 12.6 Severability. If a provision of the Plan shall be held to be illegal or invalid, the illegality or invalidity shall not

affect the remaining parts of the Plan and the Plan shall be construed and enforced as if the illegal or invalid provision had not been

included.

Section 12.7 Applicable Law. To the extent not preempted by the laws of the United States, the laws of the State of Alabama

shall apply with respect to the Plan.

ARTICLE XIII.

AMENDMENTS

Section 13.1 Amendment of the Plan. Energen reserves the power to alter, amend or wholly revise the Plan at any time and

from time to time by the action of the Board of Directors and the interest of each Participant is subject to the powers so reserved;

provided, however, that no amendment made subsequent to a Change in Control shall be effective to the extent that it would have a

materially adverse impact on a Participant’s reasonably expected economic benefit attributable to compensation deferred by the

Participant prior to the Change in Control. An amendment shall be authorized by the Board of Directors and shall be stated in an

instrument in writing signed in the name of Energen by a person or persons authorized by the Board of Directors. After the instrument

has been so executed, the Plan shall be deemed to have been amended in the manner therein set forth, and all parties interested herein

shall be bound thereby. No amendment to the Plan may alter, impair, or reduce the benefits credited to any Accounts prior to the

effective date of such amendment without the written consent of any affected Participant.

ARTICLE XIV.

TERM OF PLAN

Section 14.1 Term of the Plan. Energen may at any time terminate the Plan by action of the Board of Directors with such

termination being effective as of the date that all Participant Accounts have been distributed to Participants in accordance with and subject

to the provisions of Article VI of the Plan including, without limitation, Section 6.6 of the Plan. Effective as of the date of such Board of

Directors action (or such later date as may be specified therein) all Section 4.1 compensation deferral elections will terminate and no

further amounts shall be credited to any Accounts of any Participant under Sections 7.1(a), (b), (c) and 7.2(a) after such date. However,

the Participants’ Accounts shall continue to be adjusted by the other provisions of Sections 7.1 and 7.2 until all benefits are distributed to

the Participants or to the Participants’ beneficiaries.

18
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
Exhibit 21

SUBSIDIARIES OF ENERGEN CORPORATION

Alabama Gas Corporation*

Energen Resources Corporation*

 

* Incorporated in the State of Alabama
Exhibit 23(a)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on 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
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
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
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 23rd 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
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 15d15(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
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 15d15(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
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 15d15(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
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 15d15(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
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.
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.
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.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or

as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of

geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate

recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”

Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental

agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and

should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the

quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with

those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s

Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of

certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1)

performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in

combination by the reserve evaluator in the process of estimating the quantities of reserves. 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 publiclytraded 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 selfregulating 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 1 hour 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 subclassified 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
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 industryaccepted 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-themonth 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