10-K 1 egn-12312012x10k.htm FORM 10-K EGN-12.31.2012-10K


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-K

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

(  ) 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___
 
Commission
File Number
Registrant
State of
Incorporation
IRS Employer
Identification Number
 
 
1-7810
Energen Corporation
Alabama
63-0757759
 
 
2-38960
Alabama Gas Corporation
Alabama
63-0022000
 

605 Richard Arrington Jr. Boulevard North, Birmingham, Alabama 35203-2707
Telephone Number 205/326-2700
http://www.energen.com

Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class
 
Exchange on Which Registered
Energen Corporation Common Stock, $0.01 par value
 
New York Stock Exchange

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

Indicate by check mark if the registrants are a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES (X) NO ( )

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
YES ( ) NO (X)

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Energen Corporation Large accelerated filer (X) Accelerated filer ( ) Non-accelerated filer ( ) Smaller reporting company ( )
Alabama Gas Corporation Large accelerated filer ( ) Accelerated filer ( ) Non-accelerated filer (X) Smaller reporting company ( )

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

Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30, 2012:
Energen Corporation
 
$3,193,878,000
Indicate number of shares outstanding of each of the registrant's classes of common stock as of February 15, 2013:
Energen Corporation
 
72,222,552 shares
Alabama Gas Corporation
 
1,972,052 shares

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

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




INDUSTRY GLOSSARY
 
For a more complete definition of certain terms defined below, as well as other terms and concepts applicable to successful efforts accounting, please refer to Rule 4-10(a) of Regulation S-X, promulgated pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, each as amended.

Basis
The difference between the futures price for a commodity and the corresponding cash spot price. This commonly is related to factors such as product quality, location and contract pricing.
 
 
Basin-Specific
A type of derivative contract whereby the contract's settlement price is based on specific geographic basin indices.
 
 
Behind Pipe Reserves
Oil or gas reserves located above or below the currently producing zone(s) that cannot be extracted until a recompletion or pay-add occurs.
 
 
Cash Flow Hedge
The designation of a derivative instrument to reduce exposure to variability in cash flows from the forecasted sale of oil, gas or natural gas liquids production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted sale.
 
 
Collar
A financial arrangement that effectively establishes a price range between a floor and a ceiling for the underlying commodity. The purchaser bears the risk of fluctuation between the minimum (or floor) price and the maximum (or ceiling) price.
 
 
Development Costs
Costs necessary to gain access to, prepare and equip development wells in areas of proved reserves.
 
 
Development Well
A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
 
Downspacing
An increase in the number of available drilling locations as a result of a regulatory commission order.
 
 
Dry Well
An exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
 
 
Exploration Expenses
Costs primarily associated with drilling unsuccessful exploratory wells in undeveloped properties, exploratory geological and geophysical activities, and costs of impaired and expired leaseholds.
 
 
Exploratory Well
A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.
 
 
Futures Contract
An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price. Such contracts offer liquidity and minimal credit risk exposure but lack the flexibility of swap contracts.
 
 
Hedging
The use of derivative commodity instruments such as futures, swaps, options and collars to help reduce financial exposure to commodity price volatility.
 
 
Gross Revenues
Revenues reported after deduction of royalty interest payments.
 
 
Gross Well or Acre
A well or acre in which a working interest is owned.
 
 
Liquified Natural Gas (LNG)
Natural gas that is liquified by reducing the temperature to negative 260 degrees Fahrenheit. LNG typically is used to supplement traditional natural gas supplies during periods of peak demand.
 
 
Long-Lived Reserves
Reserves generally considered to have a productive life of approximately 10 years or more, as measured by the reserves-to-production ratio.
 
 
Natural Gas Liquids (NGL)
Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and other hydrocarbons.
 
 
Net Well or Acre
A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.
 
 
Odorization
The adding of odorant to natural gas which is a characteristic odor so that leaks can be readily detected by smell.
 
 
Operational Enhancement
Any action undertaken to improve production efficiency of oil and gas wells and/or reduce well costs.
 
 
Operator
The company responsible for exploration, development and production activities for a specific project.
 
 
Pay-Add
An operation within a currently producing wellbore that attempts to access and complete an additional pay zone(s) while maintaining production from the existing completed zone(s).
 
 
Pay Zone
The formation from which oil and gas is produced.
 
 
Production (Lifting) Costs
Costs incurred to operate and maintain wells.





 
 
Productive Well
An exploratory or a development well that is not a dry well.
 
 
Proved Developed Reserves
The portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
 
 
Proved Reserves
Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
 
 
Proved Undeveloped Reserves (PUD)
The portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
 
 
Recompletion
An operation within an existing wellbore whereby a completion in one pay zone is abandoned in order to attempt a completion in a different pay zone.
 
 
Reserves-to-Production Ratio
Ratio expressing years of supply determined by dividing the remaining recoverable reserves at year end by actual annual production volumes. The reserve-to-production ratio is a statistical indicator with certain limitations, including predictive value. The ratio varies over time as changes occur in production levels and remaining recoverable reserves.
 
 
Secondary Recovery
The process of injecting water, gas, etc., into a formation in order to produce additional oil otherwise unobtainable by initial recovery efforts.
 
 
Service Well
A well employed for the introduction into an underground stratum of water, gas or other fluid under pressure or disposal of salt water produced with oil or other waste.
 
 
Sidetrack Well
A new section of wellbore drilled from an existing well.
 
 
Swap
A contractual arrangement in which two parties, called counterparties, effectively agree to exchange or "swap" variable and fixed rate payment streams based on a specified commodity volume. The contracts allow for flexible terms such as specific quantities, settlement dates and location but also expose the parties to counterparty credit risk.
 
 
Transportation
Moving gas through pipelines on a contract basis for others.
 
 
Throughput
Total volumes of natural gas sold or transported by the gas utility.
 
 
Working Interest
Ownership interest in the oil and gas properties that is burdened with the cost of development and operation of the property.
 
 
Workover
A major remedial operation on a completed well to restore, maintain, or improve the well's production such as deepening the well or plugging back to produce from a shallow formation.
 
 
-e
Following a unit of measure denotes that the gas components have been converted to barrels of oil equivalents at a rate of 1 barrel per 6 thousand cubic feet.






















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



2



This Form 10-K is filed on behalf of Energen Corporation (Energen or the Company)
and Alabama Gas Corporation (Alagasco).

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

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

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

Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.

PART I

ITEM 1.    BUSINESS

General

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

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

The Company maintains a Web site with the address www.energen.com. The Company does not include the information contained on its Web site as part of this report nor is the information incorporated by reference into this report. The Company makes available free of charge through its Web site the annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports. Also, these reports are available in print upon shareholder request. These reports are available as soon as reasonably practicable after being electronically filed with or furnished to the Securities and Exchange Commission. The Company's Web site also includes its Business Conduct Guidelines, Corporate Governance Guidelines, Audit Committee Charter, Officers' Review Committee Charter, Governance and Nominations Committee Charter and Finance Committee Charter, each of which is available in print upon shareholder request.



3



Financial Information About Industry Segments

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

Narrative Description of Business

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

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

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

Since the end of fiscal year 1995, Energen Resources has invested approximately $1.9 billion to acquire proved and unproved reserves, $3.7 billion in related development and $1.3 billion in exploration. Energen Resources' capital spending plans 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 end-users of natural gas. Alagasco also provides transportation services to large industrial and commercial customers located on its distribution system. These transportation customers, using Alagasco as their agent or acting on their own, purchase gas directly from marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system. Alagasco charges a fee to transport such customer-owned gas through its distribution system to the customers' facilities.

Alagasco's service territory is located in central and parts of north Alabama and includes 186 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.5 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. 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 35th Avenue site. The parcel is the former site of a manufactured gas distribution facility. Alagasco has responded to the inquiry.

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

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


9



ITEM 1A.    RISK FACTORS

The future success and continued viability of Energen and its businesses, like any venture, is subject to many recognized and unrecognized risks and uncertainties. Such risks and uncertainties could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by management. The following list identifies and briefly summarizes certain risk factors, and should not be viewed as complete or comprehensive. The Company undertakes no obligation to correct or update such risk factors whether as a result of new information, future events or otherwise. These risk factors should be read in conjunction with the Company’s disclosure specific to Forward-Looking Statements made elsewhere in this report.

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

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

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

The Company is exposed to counterparty credit risk as a result of its concentrated customer base: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids to a small number of energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to a limited number of customers in the energy marketing industry has the potential to affect the Company's overall exposure to credit risk, either positively or negatively, based on changes in economic, industry or other conditions specific to a single customer or to the energy marketing industry generally. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

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


10



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

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

Pipeline and storage leaks, ruptures and spills;
Equipment malfunctions and mechanical failures;
Fires and explosions;
Well blowouts, explosions and cratering; and
Soil, surface water or groundwater contamination from petroleum constituents, hydraulic fracturing fluid, or produced water.

Such events could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial financial losses. The location of certain of our pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses and the insurance coverages are subject to retention levels and coverage limits. The occurrence of any of these events could adversely affect Energen Resources', Alagasco's and the Company's financial positions, results of operations and cash flows.

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

The Company is subject to numerous federal, state and local laws and regulations that may require significant expenditures or impose significant restrictions on its operations: Energen and Alagasco are subject to extensive federal, state and local regulation which significantly influences operations. Although the Company believes that operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations.  Such changes can subject the Company to significant tax or cost increases and can impose significant restrictions and limitations on the Company's operations.

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

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None

11



ITEM 2.    PROPERTIES

The corporate headquarters of Energen, Energen Resources and Alagasco are located in leased office space in Birmingham, Alabama. See the discussion under Item 1, Business, for further information related to Energen Resources’ and Alagasco’s business operations. Information concerning Energen Resources' production and reserves is summarized in the table below and included in Note 17, Oil and Gas Operations (Unaudited), in the Notes to Financial Statements. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the future outlook and expectations for Energen Resources and Alagasco and additional information regarding Energen Resources’ production, revenue and production costs.

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


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

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

 
Year ended
 
 
 
December 31, 2012
December 31, 2012
December 31, 2012
 
Production Volumes
(MBOE)
Proved Reserves (MBOE)
Reserves-to-Production Ratio
Permian Basin
11,198

225,006

20.09 years
San Juan Basin
9,921

100,910

10.17 years
Black Warrior Basin
2,120

16,165

7.63 years
North Louisiana/East Texas
763

3,394

4.45 years
Other
64

884

13.81 years
Total
24,066

346,359

14.39 years



12



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

 
Gas MMcf
Oil MBbl
NGL MBbl
Permian Basin
208,831

154,172

36,028

San Juan Basin
478,592

1,017

20,127

Black Warrior Basin
96,993



North Louisiana/East Texas
20,055

51


Other
4,657

108


Total
809,128

155,348

56,155


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

 
Gas MMcf
Oil MBbl
NGL MBbl
Permian Basin
127,443

104,825

17,725

San Juan Basin
459,509

992

18,715

Black Warrior Basin
96,993



North Louisiana/East Texas
20,055

51


Other
4,657

108


Total
708,657

105,976

36,440


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

 
Gas MMcf
Oil MBbl
NGL MBbl
Permian Basin
81,388

49,347

18,303

San Juan Basin
19,083

25

1,412

Black Warrior Basin



North Louisiana/East Texas



Total
100,471

49,372

19,715


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

Year ended December 31, 2012
Total MMBOE
Balance at beginning of period
94.6
Undeveloped reserves transferred to developed reserves*
(24.6)
Revisions**
(28.2)
Acquisitions
10.2
Extensions and discoveries
33.9
Balance at end of period
85.9
* Reflects capital expenditures of approximately $443 million during the year ended December 31, 2012 in development of previously proved undeveloped reserves.
** The majority of the revisions relate to the five-year proved undeveloped reserve development rules (8.9 MMBOE) and to well performance (8.8 MMBOE).

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

13



associated with the Company-owned net proved reserves reported in the table above does not exceed five percent. Estimated proved reserves as of December 31, 2012 are based upon studies for each of our properties prepared by Company engineers and audited by Ryder Scott Company, L.P. (Ryder Scott) and T. Scott Hickman and Associates, Inc. (T. Scott Hickman), independent oil and gas reservoir engineers. Calculations were prepared using geological and engineering methods generally used in the Petroleum Industry and in accordance with Securities and Exchange Commission (SEC) guidelines.

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

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

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

Reserve estimates of proved reserves are sent to independent reservoir engineers for audit and verification. For 2012, approximately 99 percent of all proved reserves were audited by the independent reservoir engineers which audit engineering procedures, check the reserve estimates for reasonableness and check that the reserves are properly classified.

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

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

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

 

Net Wells
Net Developed Acreage
Net Undeveloped Acreage
Permian Basin
2,965

160,294

97,211

San Juan Basin
1,454

281,179

20,471

Black Warrior Basin
797

146,529

80

North Louisiana/East Texas
175

20,793


Other
10

5,902


Total
5,401

614,697

117,762


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

14



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

 
  Gas MMcf
San Juan Basin
42,790

Black Warrior Basin
9,222

Total
52,012


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

ITEM 3.    LEGAL PROCEEDINGS

Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specific relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive or other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

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

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

ITEM 4.    MINE SAFETY DISCLOSURES

None


15



EXECUTIVE OFFICERS OF THE REGISTRANTS

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

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

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

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

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

(5) Mr. Reynolds has been employed by the Company in various capacities since 1980. He was elected General Counsel and Secretary of Energen and each of its subsidiaries in April 1991. He was elected President and Chief Operating Officer of Alagasco effective January 1, 2003.

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

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


16



PART II

ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Quarterly Market Prices and Dividends Paid Per Share
Quarter ended (in dollars)
High
Low
Close
Dividends Paid
March 31, 2011
63.83
48.62
63.12
0.135
June 30, 2011
65.44
53.79
56.50
0.135
September 30, 2011
62.50
38.84
40.89
0.135
December 31, 2011
53.24
37.22
50.00
0.135
March 31, 2012
58.24
47.33
49.15
0.14
June 30, 2012
53.28
40.13
45.13
0.14
September 30, 2012
55.59
43.81
52.41
0.14
December 31, 2012
54.77
41.38
45.09
0.14

Energen's common stock is listed on the New York Stock Exchange under the symbol EGN. On February 15, 2013, there were 5,467 holders of record of Energen's common stock. At the date of this filing, Energen Corporation owned all the issued and outstanding common stock of Alabama Gas Corporation. Energen expects to pay annual cash dividends of $0.58 per share on the Company’s common stock in 2013. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

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



Plan Category
Number of Securities to be Issued for Outstanding Options and Performance Share Awards

Weighted Average Exercise Price
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders*
1,648,475

$
47.58

4,288,140
Equity compensation plans not approved by security holders


Total
1,648,475

$
47.58

4,288,140
* These plans include 3,418,881 shares associated with the Company’s Stock Incentive Plan, 162,904 shares associated with the 1992 Energen Corporation Directors Stock Plan and 706,355 shares associated with the 1997 Deferred Compensation Plan.

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



Period


Total Number of Shares Purchased


Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans
Maximum Number of Shares that May Yet Be Purchased Under the Plans**
October 1, 2012 through October 31, 2012

943*

$
51.55


8,992,700
November 1, 2012 through November 30, 2012



8,992,700
December 1, 2012 through December 31, 2012



8,992,700
Total
943

$
51.55


8,992,700
* Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans.
** By resolution adopted May 24, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board of Directors authorized the Company to repurchase up to 12,564,400 shares of the Company's common stock. The resolutions do not have an expiration date.

17



PERFORMANCE GRAPH
Energen Corporation — Comparison of Five-Year Cumulative Shareholder Returns

This graph compares the total shareholder returns of Energen, the Standard & Poor’s Composite Stock Index (S&P 500), the Standard & Poor’s Supercomposite Oil & Gas Exploration & Production Index (S15OILP), and the Standard & Poor’s Supercomposite Gas Utilities Index (S15GASUX). The graph assumes $100 invested at the per-share closing price of the common stock on the New York Exchange Composite Tape on December 31, 2007, in the Company and each of the indices. Total shareholder return includes reinvested dividends.




As of December 31,
2007
2008
2009
2010
2011
2012
S&P 500
$
100

$
63

$
80

$
92

$
94

$
109

Energen
$
100

$
46

$
75

$
78

$
81

$
74

S15OILP
$
100

$
63

$
91

$
103

$
95

$
97

S15GASUX
$
100

$
76

$
96

$
112

$
135

$
134



18



ITEM 6.    SELECTED FINANCIAL DATA

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

SELECTED FINANCIAL AND COMMON STOCK DATA
Energen Corporation

Years ended December 31,
(dollars in thousands, except per share amounts)

2012
 

2011
 

2010
 

2009
 

2008
INCOME STATEMENT
 
 
 
 
 
 
 
 
 
Operating revenues
$
1,617,169

 
$
1,483,479

 
$
1,578,534

 
$
1,440,420

 
$
1,568,910

Net income
$
253,562

 
$
259,624

 
$
290,807

 
$
256,325

 
$
321,915

Diluted earnings per average common share
$
3.51

 
$
3.59

 
$
4.04

 
$
3.57

 
$
4.47

BALANCE SHEET
 
 
 
 
 
 
 
 
 
Total property, plant and equipment, net
$
5,541,636

 
$
4,620,776

 
$
3,719,227

 
$
3,144,469

 
$
2,867,648

Total assets
$
6,175,890

 
$
5,237,416

 
$
4,363,560

 
$
3,803,118

 
$
3,775,404

Long-term debt
$
1,103,528

 
$
1,153,700

 
$
405,254

 
$
410,786

 
$
561,631

Total shareholders' equity
$
2,676,690

 
$
2,432,163

 
$
2,154,043

 
$
1,988,243

 
$
1,913,920

COMMON STOCK DATA
 
 
 
 
 
 
 
 
 
Cash dividends paid per common share
$
0.56

 
$
0.54

 
$
0.52

 
$
0.50

 
$
0.48

Diluted average common shares outstanding (000)
72,316

 
72,332

 
72,051

 
71,885

 
72,030

Price range:
 
 
 
 
 
 
 
 
 
High
$
58.24

 
$
65.44

 
$
49.94

 
$
48.89

 
$
79.57

Low
$
40.13

 
$
37.22

 
$
40.25

 
$
23.18

 
$
23.00

Close
$
45.09

 
$
50.00

 
$
48.26

 
$
46.80

 
$
29.33





























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-to-market hedges.

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

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


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

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

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

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

Dividends
Energen expects to pay annual cash dividends of $0.58 per share on the Company’s common stock in 2013. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

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

31



(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.


32



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-than-expected production performance. If a material event occurs, Energen Resources makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, the Company will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows.

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

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

Derivatives: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. Energen Resources recognizes all derivatives on the balance sheet and measures all derivatives at fair value. Realized gains and losses from derivatives designated as cash flow hedges are recognized in oil and gas production revenues when the forecasted transaction occurs. Energen Resources also periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Company’s financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred.

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

Consolidated
Employee Benefit Plans: An employer is required to recognize the net funded status of defined benefit pensions and other postretirement benefit plans (benefit plans) as an asset or liability in its statement of financial position and to recognize changes in the funded status through comprehensive income in the year in which the changes occur. The pension benefit obligation is the projected benefit obligation, a measurement of earned benefit obligations at expected retirement salary levels; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation, a measurement of earned postretirement benefit obligations expected to be paid to employees upon retirement. Alagasco established a regulatory asset for the portion of the total benefit obligation to be recovered through rates in future periods.

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

In selecting the discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments; the weighted average discount rate used to determine net periodic costs was 4.52 percent for the plans for the year ended December 31, 2012. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions; the return on assets used to determine net periodic expense was 7 percent for each of the applicable plans for the year ended December 31, 2012. The estimated weighted average rate of increase in the compensation level for pay related plans was 3.59 percent for the year ended December 31, 2012.

37



The selection and use of actuarial assumptions affects the amount of benefit expense recorded in the Company’s financial statements.
The table below reflects a hypothetical 25 basis point change in assumed actuarial assumptions to pre-tax benefit expense for the year ended December 31, 2012:

(in thousands)
Pension
Expense
Postretirement
Expense
Discount rate change
$
1,350

$
40

Return on assets
$
500

$
160

Compensation increase
$
745

$


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

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

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

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD
See Note 15, Recently Issued Accounting Standards, in the Notes to Financial Statements for information regarding recently issued accounting standards.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

38



ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES

 
 
Page
1.
Financial Statements
 
 
 
 
 
Energen Corporation
 
 
 
 
 
Report of Independent Registered Public Accounting Firm
 
 
 
 
Consolidated Statements of Income for the years ended December 31, 2012, 2011
and 2010
 
 
 
 
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011
and 2010
 
 
 
 
Consolidated Balance Sheets as of December 31, 2012 and 2011
 
 
 
 
Consolidated Statements of Shareholders' Equity for the years ended December 31, 2012, 2011
and 2010
 
 
 
 
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010
 
 
 
 
Notes to Financial Statements
 
 
 
 
Alabama Gas Corporation
 
 
 
 
 
Report of Independent Registered Public Accounting Firm
 
 
 
 
Statements of Income for the years ended December 31, 2012, 2011 and 2010




 
 
 
Balance Sheets as of December 31, 2012 and 2011
 
 
 
 
Statements of Shareholder's Equity for the years ended December 31, 2012, 2011
and 2010
 
 
 
 
Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010
 
 
 
 
Notes to Financial Statements
 
 
 
2.
Financial Statement Schedules
 
 
 
 
 
Energen Corporation
 
 
Schedule II - Valuation and Qualifying Accounts
 
 
 
 
Alabama Gas Corporation
 
 
Schedule II - Valuation and Qualifying Accounts

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