10-K 1 egn-12312013x10k.htm 10-K EGN-12.31.2013-10K


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, 2013

(  ) 
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, 2013:
Energen Corporation
 
$3,809,442,960
Indicate number of shares outstanding of each of the registrant’s classes of common stock as of February 14, 2014:
Energen Corporation
 
72,713,965 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 21, 2014 (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
2013 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 2013 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 is an oil and gas exploration and production company complemented by its legacy natural gas distribution business. Headquartered in Birmingham, Alabama, the Company is engaged in the development and exploration 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 and Governance and Nominations 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 20, 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 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 and San Juan 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 2013, Energen Resources’ proved oil and gas reserves totaled 347.8 million barrels of oil equivalent (MMBOE). Substantially all of these reserves are located in the Permian Basin in west Texas and the San Juan Basin in New Mexico and Colorado. 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 15 years. Oil, natural gas and natural gas liquids represent approximately 47 percent, 35 percent and 18 percent, respectively, of Energen Resources’ proved reserves.

In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which is reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

In January 2014, Energen Resources signed a purchase and sale agreement on its North Louisiana/East Texas natural gas and oil properties for $31.5 million (subject to closing adjustments). The Company expects to complete the sale in the first quarter of 2014 and will use the proceeds to repay short-term obligations. During the third quarter of 2013, Energen Resources classified these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the third and fourth quarters of $24.6 million pre-tax and $5.2 million pre-tax, respectively, to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. The non-cash impairment writedowns are reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

Growth Strategy: Energen operates under a strategy to grow the oil and gas operations of Energen Resources largely through the development of proved and unproved reserves and through the exploration in and around the basins in which it operates. 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 95 percent of its proved reserves at December 31, 2013.

Since the end of fiscal year 1995, Energen Resources has invested approximately $1.9 billion to acquire proved and unproved reserves, $4.3 billion in related development and $1.7 billion in exploration. Energen Resources’ capital spending plans for 2014 target a total investment of approximately $1.05 billion, the bulk of which will focus on drilling and related development activities on its existing properties, with approximately 99 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.


4



During the three years ended December 31, 2013, the Company’s development and exploratory efforts have added 139 MMBOE of proved reserves from the drilling of 1,308 gross development, exploratory and service wells (including 11 sidetrack wells) and 289 well recompletions and pay-adds. In 2013, Energen Resources’ successful development and exploratory wells and other activities added approximately 37 MMBOE of proved reserves; the Company drilled 347 gross development, exploratory and service wells (including no sidetrack wells), performed some 87 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources’ production from continuing operations totaled 23.3 MMBOE in 2013 and in 2014 is estimated to range from 24.4 MMBOE to 25.4 MMBOE, with a midpoint of 24.9 MMBOE, including approximately 22.1 MMBOE of estimated production from proved reserves owned at December 31, 2013.

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

Years ended December 31,
2013
2012
2011
Development:
 
 
 
Productive
169.5

239.9

370.3
Dry


3.3
Total
169.5

239.9

373.6
Exploratory:
 
 
 
Productive
89.1

74.1

23.3
Dry
0.9

1.1

1.0
Total
90.0

75.2

24.3

As of December 31, 2013, the Company was participating in the drilling of 5 gross development and 11 gross exploratory wells, with the Company’s interest equivalent to 2.2 wells and 9.4 wells, respectively. In addition to the development wells drilled, the Company drilled 9.8, 47.8 and 29.1 net service wells during 2013, 2012 and 2011, respectively.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2013, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

 
Gross

Net

Oil wells
4,876

3,262

Gas wells
3,305

1,616

Developed acreage
654,848

480,983

Undeveloped acreage
164,416

112,732


There were 10 wells with multiple completions in 2013. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Texas and Colorado.

Concentration of Credit Risk: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The two largest oil and gas purchasers accounted for approximately 35 percent and 12 percent of Energen Resources’ accounts receivable for commodity sales as of December 31, 2013. Energen Resources’ other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2013. During the year ended December 31, 2013, Plains Marketing, LP, accounted for approximately 25 percent of consolidated total operating revenues. All other oil and gas purchasers each accounted for less than 10 percent of consolidated total operating revenues for the year ended December 31, 2013.


5



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. Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions.

Effective June 30, 2013, the Company elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues. As a result of the Company’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 are accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.

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

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 187 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 2013, Alagasco served an average of 391,093 residential customers and 31,174 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 11,229 miles of main and more than 12,015 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. The Alagasco’s current RSE order had an original term extending through December 31, 2014. On December 20, 2013, the APSC issued a final written order modifying RSE effective January 1, 2014 as follows. The term will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, if any. Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to operations and maintenance (O&M) expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from 2007 actual expenses, adjusted for inflation using the Index Range. 

Alagasco’s allowed range of return on average equity was 13.15 percent to 13.65 percent through December 31, 2013. 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. Through December 31, 2013, RSE limited the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Currently, under the inflation-based 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 September 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 Alagasco 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

6



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 prescribe 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.

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, 2013, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:

 
December 31, 2013
 
(Mcfd)
Southern firm transportation
112,933

Southern storage and no notice transportation
231,679

Transco firm transportation
70,000

Various intrastate transportation
20,240


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 2013, substantially all of Alagasco’s large commercial and industrial customer deliveries involved the transportation of customer-owned gas.


7



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 2013 declined approximately 0.6 percent from 2012 and reflected a moderation in decline over the five-year trend. Other factors impacting Alagasco’s average customer count include recent weather trends, 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.

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 one percent by volume) that can vary by project. The millimeter-thick cracks or fractures in the target formation are propped open by the sand, thereby allowing the 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;

8



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.

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $2.1 million of which $1.9 million has been incurred and $0.2 million has been reserved.

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

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. Management expects that, should future remediation of the sites be required, Alagasco’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the United States EPA, Alagasco and the current site owner.

In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the 35th Avenue Superfund Site located in North Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35th Avenue Superfund Site. In September 2013, Alagasco received from the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies Alagasco as a PRP under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. Alagasco has discussed its designation as a PRP further with the EPA, and Alagasco has requested additional information from the EPA regarding its designation as a PRP. Alagasco has not been provided information at this time that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action, and therefore Alagasco has not agreed to undertake the proposed removal activities and no amount has been accrued as of December 31, 2013.

Employees
The Company has approximately 1,434 employees, of which Alagasco employs 993 and Energen Resources employs 441. 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 oil, natural gas 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 credit ratings of the Company or its subsidiaries 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 lenders, the Company and its subsidiaries. In addition to operating results, business decisions relating to recapitalization, refinancing, restructuring, acquisition and disposition (including by sale, spin-off or distribution) transactions involving the Company, Energen Resources or Alagasco may negatively impact market and rating agency considerations regarding the credit of the Company or its subsidiaries, and the management of the Company periodically considers these types of transactions. 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, limit availability of funds to the Company and adversely affect the price of outstanding debt securities.

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

10



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.

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 19, 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 development and exploration of onshore North American oil and gas properties. Energen Resources maintains district offices in Midland, Texas; Farmington, New Mexico; and Arcadia, Louisiana.
                                     



The major areas of operations include (1) the Permian Basin, (2) the San Juan Basin and (3) North Louisiana/East Texas as highlighted on the above map. As of December 31, 2013, North Louisiana/East Texas natural gas and oil properties were classified as held-for-sale and the associated operating results were reflected in discontinued operations.














12



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

 
Year ended
 
 
 
December 31, 2013
December 31, 2013
December 31, 2013
 
Production Volumes
(MBOE)
Proved Reserves (MBOE)
Reserves-to-Production Ratio
Permian Basin
14,187

246,586

17.38 years

San Juan Basin
9,011

96,448

10.70 years

North Louisiana/East Texas*
617

3,877

6.28 years

Other
83

924

11.13 years

Total excluding Black Warrior Basin
23,898

347,835

14.55 years

Black Warrior Basin (sold during 2013)
1,464



Total
25,362



* North Louisiana/East Texas were classified as held-for-sale as of December 31, 2013.

The following table sets forth proved reserves by area as of December 31, 2013:

 
Gas MMcf
Oil MBbl
NGL MBbl
Permian Basin
232,345

163,716

44,147

San Juan Basin
460,097

900

18,864

North Louisiana/East Texas*
22,716

91


Other
4,567

163


Total
719,725

164,870

63,011

* North Louisiana/East Texas were classified as held-for-sale as of December 31, 2013.

See Note 19, Oil and Gas Operations (Unaudited), in the Notes to Financial Statements for the changes to proved reserves during the years ended December 31, 2013, 2012 and 2011 of natural gas, oil, and natural gas liquids.

The following table sets forth proved developed reserves by area as of December 31, 2013:

 
Gas MMcf
Oil MBbl
NGL MBbl
Permian Basin
135,925

112,641

23,223

San Juan Basin
460,097

900

18,864

North Louisiana/East Texas*
22,716

91


Other
4,567

163


Total
623,305

113,795

42,087

* North Louisiana/East Texas were classified as held-for-sale as of December 31, 2013.

The following table sets forth proved undeveloped reserves by area as of December 31, 2013:

 
Gas MMcf
Oil MBbl
NGL MBbl
Permian Basin
96,420

51,075

20,924

Total
96,420

51,075

20,924







13



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

Year ended December 31, 2013
Total MMBOE
Balance at beginning of period
85.9
Undeveloped reserves transferred to developed reserves
(20.3)
Revisions
5.7
Extensions and discoveries
16.7
Balance at end of period
88.0

Undeveloped reserves transferred to developed reserves reflect capital expenditures of approximately $414 million during the year ended December 31, 2013 in development of previously proved undeveloped reserves. Proved undeveloped reserves additions were one offset location away from producing wells where our geologic interpretation and experience indicate the reservoirs were continuous across those locations. The technologies associated with these additions to reserve estimates are analysis of well production data, geophysical data, wireline and core data. Revisions largely relate to well performance in the Permian Basin of approximately 13.4 MMBOE partially offset by a reduction in reserves of 5.3 MMBOE associated with the five-year proved undeveloped reserve development rules.

Estimated proved reserves as of December 31, 2013 are based upon studies for each of our properties prepared by Company engineers and audited by Ryder Scott Company, L.P. (Ryder Scott) and T. Scott Hickman and Associates, Inc. (T. Scott Hickman), independent oil and gas reservoir engineers. Calculations were prepared using geological and engineering methods widely used and referred to by professionals in the industry and in accordance with 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 2013, approximately 98 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.






14



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:

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

The following table sets forth the total net productive oil and gas wells by area as of December 31, 2013, 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
3,241

172,496

81,043

San Juan Basin
1,454

281,676

31,689

North Louisiana/East Texas*
175

20,720


Other
8

6,091


Total
4,878

480,983

112,732

* North Louisiana/East Texas were classified as held-for-sale as of December 31, 2013.

The following table sets forth expiration dates for gross and net undeveloped acreage at year end as of December 31, 2013:

 
Years ending December 31,
 
2014
2015
2016
Thereafter
 
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Permian
11,400

7,537

43,938

31,513

13,724

13,110

35,667

28,883

San Juan
498

245

1,619

919

20,731

5,982

36,839

24,543

Total*
11,898

7,782

45,557

32,432

34,455

19,092

72,506

53,426

* Our capital plan contemplates avoiding a significant portion of these lease expirations.

Energen Resources has 5.6 MMBOE of proved undeveloped reserves on leased acreage which is not held by production and is expected to be developed after the primary term of the leases. Drilling associated with these reserves is expected to occur under the continuous development provisions of the leases. The amount represents approximately 6 percent of the 88 MMBOE total proved undeveloped reserves and approximately 2 percent of the 347.8 MMBOE total proved reserves at December 31, 2013. We believe both of these amounts to be immaterial to our operations.

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 37.8 billion cubic feet (net) of natural gas through March 2015. The Company expects to fulfill delivery commitments through production of existing proved reserves.

 
  Gas MMcf
San Juan Basin
37,823


Natural Gas Distribution
The properties of Alagasco consist primarily of its gas distribution system, which includes approximately 11,229 miles of main and more than 12,015 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.


15



ITEM 3.    LEGAL PROCEEDINGS

Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Various pending or threatened legal proceedings are in progress currently. See Note 7, Commitments and Contingencies, in the Notes to Financial Statements for further discussion with respect to legal proceedings.

ITEM 4.    MINE SAFETY DISCLOSURES

None


16



EXECUTIVE OFFICERS OF THE REGISTRANTS

Name
Age
Position (1)
James T. McManus, II
55
Chairman, Chief Executive Officer and President of Energen and Chairman and Chief Executive Officer of Alagasco (2)
Charles W. Porter, Jr.
49
Vice President, Chief Financial Officer and Treasurer of Energen and Alagasco (3)
John S. Richardson
56
President and Chief Operating Officer of Energen Resources (4)
Dudley C. Reynolds
60
President and Chief Operating Officer of Alagasco (5)
J. David Woodruff, Jr.
57
Vice President, General Counsel and Secretary of Energen and Alagasco (6)
Russell E. Lynch, Jr.
40
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 was elected Vice President and Controller of Energen effective January 1, 2009.


17



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

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On February 14, 2014, there were 5,076 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 $0.60 per share on the Company’s common stock in 2014. 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 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, 2013 through October 31, 2013

$


8,992,700
November 1, 2013 through November 30, 2013



8,992,700
December 1, 2013 through December 31, 2013

507*

70.08


8,992,700
Total
507

$
70.08


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.

18



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, 2008, in the Company and each of the indices. Total shareholder return includes reinvested dividends.




As of December 31,
2008
2009
2010
2011
2012
2013
S&P 500
$
100

$
126

$
146

$
149

$
172

$
228

Energen
$
100

$
162

$
169

$
177

$
161

$
255

S15OILP
$
100

$
145

$
164

$
152

$
155

$
200

S15GASUX
$
100

$
126

$
147

$
177

$
177

$
230



19



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)

2013
 

2012
 

2011
 

2010
 

2009
INCOME STATEMENT
 
 
 
 
 
 
 
 
 
Operating revenues
$
1,738,650

 
$
1,540,819

 
$
1,373,113

 
$
1,425,107

 
$
1,273,574

Income from continuing operations
$
193,147

 
$
255,220

 
$
224,305

 
$
233,133

 
$
191,643

Net income
$
204,554

 
$
253,562

 
$
259,624

 
$
290,807

 
$
256,325

Diluted earnings per average common share from continuing operations
$
2.67

 
$
3.53

 
$
3.10

 
$
3.24

 
$
2.67

Diluted earnings per average common share
$
2.82

 
$
3.51

 
$
3.59

 
$
4.04

 
$
3.57

BALANCE SHEET
 
 
 
 
 
 
 
 
 
Total property, plant and equipment, net
$
6,003,638

 
$
5,541,636

 
$
4,620,776

 
$
3,719,227

 
$
3,144,469

Total assets
$
6,622,212

 
$
6,175,890

 
$
5,237,416

 
$
4,363,560

 
$
3,803,118

Long-term debt
$
1,343,464

 
$
1,103,528

 
$
1,153,700

 
$
405,254

 
$
410,786

Total shareholders’ equity
$
2,858,019

 
$
2,676,690

 
$
2,432,163

 
$
2,154,043

 
$
1,988,243

COMMON STOCK DATA
 
 
 
 
 
 
 
 
 
Cash dividends paid per common share
$
0.58

 
$
0.56

 
$
0.54

 
$
0.52

 
$
0.50

Diluted average common shares outstanding (000)
72,471

 
72,316

 
72,332

 
72,051

 
71,885

Price range:
 
 
 
 
 
 
 
 
 
High
$
89.92

 
$
58.24

 
$
65.44

 
$
49.94

 
$
48.89

Low
$
44.46

 
$
40.13

 
$
37.22

 
$
40.25

 
$
23.18

Close
$
70.75

 
$
45.09

 
$
50.00

 
$
48.26

 
$
46.80


























20



SELECTED BUSINESS SEGMENT DATA
Energen Corporation

Years ended December 31,
(dollars in thousands)

2013
 

2012
 

2011
 

2010
 

2009
OIL AND GAS OPERATIONS
 
 
 
 
 
 
 
 
 
Operating revenues from continuing operations
 
 
 
 
 
 
 
 
 
Natural gas
$
239,643

 
$
216,073

 
$
281,501

 
$
336,493

 
$
298,865

Oil
865,100

 
788,937

 
465,735

 
403,039

 
283,247

Natural gas liquids
101,550

 
85,938

 
87,464

 
65,161

 
67,254

Other
(981
)
 
(1,718
)
 
3,460

 
642

 
6,334

Total
$
1,205,312

 
$
1,089,230

 
$
838,160

 
$
805,335

 
$
655,700

Non-cash mark-to-market gains (losses) (included in operating revenues from continuing operations above)
 
Natural gas
$
(3,919
)
 
$
(515
)
 
$

 
$

 
$

Oil
(43,261
)
 
58,786

 
(37,473
)
 
(3
)
 
(107
)
Natural gas liquids
(652
)
 
479

 
(114
)
 

 

Total
$
(47,832
)
 
$
58,750

 
$
(37,587
)
 
$
(3
)
 
$
(107
)
Production volumes from continuing operations
 
 
 
 
 
 
 
 
 
Natural gas (MMcf)
58,104

 
59,166

 
54,132

 
51,778

 
50,365

Oil (MBbl)
10,364

 
8,749

 
6,300

 
5,109

 
4,664

Natural gas liquids (MMgal)
135.8

 
108.1

 
91.4

 
79.0

 
75.2

Production volumes from continuing operations (MBOE)
23,281

 
21,183

 
17,499

 
15,619

 
14,849

Total production volumes (MBOE)
25,362

 
24,066

 
20,448

 
18,832

 
18,537

Proved reserves
 
 
 
 
 
 
 
 
 
Natural gas (MMcf)
719,725

 
809,128

 
957,368

 
954,387

 
897,546

Oil (MBbl)
164,870

 
155,348

 
129,578

 
103,262

 
77,963

Natural gas liquids (MBbl)
63,011

 
56,155

 
53,957

 
40,601

 
30,257

Total (MMcfe)
2,087,010

 
2,078,154

 
2,058,594

 
1,817,565

 
1,546,866

Total (MBOE)
347,835

 
346,359

 
343,099

 
302,928

 
257,811

Other data from continuing operations
 
 
 
 
 
 
 
 
 
Lease operating expense
 
 
 
 
 
 
 
 
 
Lease operating expense and other
$
284,053

 
$
224,503

 
$
174,778

 
$
155,359

 
$
151,651

Production taxes
67,488

 
53,690

 
51,583

 
38,686

 
31,852

Total
$
351,541

 
$
278,193

 
$
226,361

 
$
194,045

 
$
183,503

Depreciation, depletion and amortization
$
453,474

 
$
343,183

 
$
213,841

 
$
168,016

 
$
146,946

Capital expenditures
$
1,104,745

 
$
1,291,211

 
$
1,115,452

 
$
717,782

 
$
427,399

Exploration expense
$
27,942

 
$
19,356

 
$
12,967

 
$
64,562

 
$
10,225

Operating income
$
257,963

 
$
369,765

 
$
308,561

 
$
315,990

 
$
252,927

NATURAL GAS DISTRIBUTION
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
 
Residential
$
340,563

 
$
277,698

 
$
343,740

 
$
414,870

 
$
398,289

Commercial and industrial
136,990

 
115,711

 
136,469

 
159,658

 
161,543

Transportation
61,254

 
58,857

 
55,234

 
57,049

 
53,856

Other
(5,469
)
 
(677
)
 
(490
)
 
(11,805
)
 
4,186

Total
$
533,338

 
$
451,589

 
$
534,953

 
$
619,772

 
$
617,874

Gas delivery volumes (MMcf)
 
 
 
 
 
 
 
 
 
Residential
20,279

 
16,014

 
21,132

 
24,463

 
20,921

Commercial and industrial
9,968

 
8,372

 
9,994

 
10,985

 
9,934

Transportation
47,534

 
48,106

 
44,614

 
46,479

 
40,903

Total
77,781

 
72,492

 
75,740

 
81,927

 
71,758

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

21



Average number of customers
 
 
 
 
 
 
 
 
 
Residential
391,093

 
393,467

 
395,766

 
404,697

 
409,214

Commercial, industrial and transportation
31,174

 
31,450

 
31,840

 
32,632

 
33,264

Total
422,267

 
424,917

 
427,606

 
437,329

 
442,478

Other data
 
 
 
 
 
 
 
 
 
Depreciation and amortization
$
43,907

 
$
42,270

 
$
39,916

 
$
44,042

 
$
50,995

Capital expenditures
$
88,769

 
$
71,869

 
$
73,984

 
$
93,566

 
$
77,809

Operating income
$
93,768

 
$
93,216

 
$
86,216

 
$
88,383

 
$
83,984


22



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, 2013 totaled $204.6 million, or $2.82 per diluted share compared to the year ended December 31, 2012 net income of $253.6 million, or $3.51 per diluted share. This 19.7 percent decrease in earnings per diluted share (EPS) largely reflected increased depreciation, depletion and amortization (DD&A) expense, a year-over-year after-tax $67.8 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $30.6 million non-cash mark-to-market loss on derivatives for 2013 and an after-tax $37.2 million non-cash mark-to-market gain on derivatives for 2012), higher lease operating expense excluding production taxes, increased administrative expense, increased production taxes, higher exploration expense, lower commodity prices for natural gas liquids and increased interest expense. Positively affecting net income was the impact of a net 2.1 million barrels of oil equivalent (MMBOE) increase in production volumes from Energen Resources Corporation, Energen’s oil and gas subsidiary, and higher oil and natural gas commodity prices. For the year ended December 31, 2013, Energen Resources earned $146.8 million, as compared with $204.1 million in the previous year. Alabama Gas Corporation (Alagasco), Energen’s utility subsidiary, generated net income of $57.4 million in the current year, which includes an after-tax gain of $6.8 million on the sale of the Metro Operations Center, as compared with net income in the prior period of $49.4 million. For the year ended December 31, 2011, Energen reported net income of $259.6 million, or $3.59 per diluted share.

2013 vs 2012: Energen Resources’ net income totaled $146.8 million in 2013 as compared with $204.1 million in 2012. Energen Resources’ income from continuing operations totaled $135.3 million in 2013 as compared with $205.7 million in 2012. Income from discontinued operations for the current year was $11.4 million, as compared with a loss of $1.7 million from the prior year. Income from discontinued operations in 2013 included an after-tax gain of $22.5 million on the sale of the Black Warrior Basin coalbed methane properties partially offset by the non-cash impairment writedown on North Louisiana/East Texas natural gas and oil properties of $18.9 million after-tax. Loss from discontinued operations in 2012 included a non-cash impairment on certain properties in East Texas of approximately $13.4 million after-tax. From continuing operations, increased DD&A expense of approximately $73 million after-tax, a year-over-year after-tax $67.8 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $30.6 million non-cash mark-to-market loss on derivatives for 2013 and an after-tax $37.2 million non-cash mark-to-market gain on derivatives for 2012), higher lease operating expense excluding production taxes of approximately $39 million after-tax, increased administrative expense of approximately $23 million after-tax, increased production taxes of approximately $9 million after-tax, higher exploration expense of approximately $6 million after-tax, lower commodity prices for natural gas liquids of approximately $3 million after-tax, increased interest expense of approximately $3 million after-tax and lower natural gas production volumes of approximately $3 million were partially offset by significantly greater oil and natural gas liquid production volumes of approximately $103 million after-tax and higher oil and natural gas commodity prices of approximately $49 million after-tax.

Alagasco earned net income of $57.4 million in 2013 as compared with net income of $49.4 million in 2012 which primarily reflects 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 and an after-tax gain of $6.8 million on the sale of the Metro Operations Center.

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. Energen Resources’ income from continuing operations totaled $205.7 million in 2012 as compared with $177.5 million in 2011. Loss from discontinued operations for 2012 was $1.7 million, as compared with income of $35.3 million from 2011. Loss from discontinued operations in 2012 included a non-cash impairment on certain properties in East Texas of approximately $13.4 million after-tax. Lower natural gas and natural gas liquids commodity prices of approximately $70 million after-tax, increased DD&A expense of approximately $83 million after-tax, higher lease operating expense of approximately $32 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 of $3.6 million on the sale of certain oil properties were partially offset by increased production volumes of approximately $153 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 $20 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.


23



Operating Income
Consolidated operating income in 2013, 2012 and 2011 totaled $351.2 million, $461.9 million and $393.7 million, respectively. Lower operating income for 2013 is primarily due to higher DD&A, higher lease operating expense and the non-cash mark-to-market decrease in derivatives partially offset by increased oil and natural gas liquids production and higher natural gas and oil commodity prices at Energen Resources. 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. During 2013 and 2012, 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 continuing oil and gas operations increased in the current year largely as a result of significantly higher oil and natural gas liquids production volumes and higher realized oil and natural gas commodity prices partially offset by the non-cash mark-to-market decrease in derivatives combined with lower natural gas liquids commodity prices and decreased natural gas production volumes. Production increased due to higher volumes related to increased field development in certain Permian Basin liquids-rich properties partially offset by normal production declines. Revenue per unit of production for natural gas production rose 14.5 percent to $4.19 per thousand cubic feet (Mcf), oil revenue per unit of production increased 5 percent to $87.65 per barrel and natural gas liquids revenue per unit of production fell 5.1 percent to $0.75 per gallon during 2013. Production from continuing operations rose 9.9 percent to 23.3 MMBOE during 2013. Natural gas production decreased 1.8 percent to 58.1 billion cubic feet (Bcf) while oil volumes rose 18.5 percent to 10,364 thousand barrels (MBbl). Production of natural gas liquids increased 25.6 percent to 135.8 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 non-cash mark-to-market hedges.

In 2012, revenues from continuing oil and gas operations increased largely as a result of 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. During 2012, revenue per unit of production for natural gas production fell 29.6 percent to $3.66 per Mcf, oil revenue per unit of production rose 4.5 percent to $83.46 per barrel and natural gas liquids revenue per unit of production decreased 17.7 percent to $0.79 per gallon. Production from continuing operations rose 21.1 percent to 21.2 MMBOE during 2012. Natural gas production increased 9.3 percent to 59.2 Bcf and oil volumes rose 38.9 percent to 8,749 MBbl. Production of natural gas liquids increased 18.3 percent to 108.1 MMgal.

Years ended December 31, (in thousands, except sales price data)
2013
2012
2011
Operating revenues from continuing operations
 
 
 
Natural gas
$
239,643

$
216,073

$
281,501

Oil
865,100

788,937

465,735

Natural gas liquids
101,550

85,938

87,464

Other
(981
)
(1,718
)
3,460

Total operating revenues
$
1,205,312

$
1,089,230

$
838,160

Non-cash mark-to-market gains (losses) (included in operating revenues above)
 
 
Natural gas
$
(3,919
)
$
(515
)
$

Oil
(43,261
)
58,786

(37,473
)
Natural gas liquids
(652
)
479

(114
)
Total
$
(47,832
)
$
58,750

$
(37,587
)
Production volumes from continuing operations
 
 
 
Natural gas (MMcf)
58,104

59,166

54,132

Oil (MBbl)
10,364

8,749

6,300

Natural gas liquids (MMgal)
135.8

108.1

91.4

Total production volumes from continuing operations (MBOE)
23,281

21,183

17,499

Production volumes
 
 
 
Natural gas (MMcf)
70,506

76,362

71,718

Oil (MBbl)
10,378

8,766

6,318

Natural gas liquids (MMgal)
135.8

108.1

91.4


24



Total production volumes (MBOE)
25,362

24,066

20,448

San Juan Basin - Basin Field production volumes (included in production volumes above)*
 
Natural gas (MMcf)
29,453

34,595

33,656

Oil (MBbl)
13

12

13

Natural gas liquids (MMgal)
22.7

24.2

25.2

Total production volumes (MBOE)
5,462

6,354

6,223

Permian Basin - Spraberry (Trend Area) Field production volumes (included in production volumes above)**
Natural gas (MMcf)
4,836

3,592

1,650

Oil (MBbl)
2,822

2,134

1,136

Natural gas liquids (MMgal)
38.5

25.8

14.7

Total production volumes (MBOE)
4,544

3,347

1,762

Revenue per unit of production excluding effects of non-cash mark-to-market derivative instruments
Natural gas (per Mcf)
$
4.19

$
3.66

$
5.20

Oil (per barrel)
$
87.65

$
83.46

$
79.87

Natural gas liquids (per gallon)
$
0.75

$
0.79

$
0.96

Revenue per unit of production excluding effects of all derivative instruments
Natural gas (per Mcf)
$
3.51

$
2.69

$
3.89

Oil (per barrel)
$
92.73

$
87.56

$
90.54

Natural gas liquids (per gallon)
$
0.67

$
0.75

$
1.11

Average production (lifting) cost (per BOE) (excludes ad valorem tax)
$
11.06

$
9.55

$
9.11

Average ad valorem tax (per BOE)
$
1.14

$
1.05

$
0.88

Average production tax (per BOE)
$
2.90

$
2.53

$
2.95

Average DD&A rate (per BOE)
$
19.32

$
16.03

$
12.03

* The Basin Field in the San Juan Basin contained 15 percent or more of the Company’s total proved reserves as of December 31, 2013.
** The Spraberry (Trend Area) Field in the Permian Basin contained 15 percent or more of the Company’s total proved reserves as of December 31, 2013.

Operations and maintenance (O&M) expense rose $103 million in 2013 and increased $57.7 million in 2012. 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. During 2013, lease operating expense (excluding production taxes) increased $59.6 million largely due to additional workover and repair expense (approximately $26.5 million), increased equipment rental expense (approximately $4.5 million), increased marketing and transportation costs (approximately $4.3 million), higher gathering costs (approximately $4.2 million), higher ad valorem taxes (approximately $4 million), higher labor costs (approximately $3.6 million), increased environmental compliance costs (approximately $3.1 million), additional electrical costs (approximately $2.8 million), increased chemical usage (approximately $2.4 million) and increased nonoperated costs (approximately $2.4 million). In 2012, lease operating expense (excluding production taxes) increased $49.7 million largely due to increased water disposal costs (approximately $15.2 million), higher workover and repair expense (approximately $9.3 million), higher ad valorem taxes (approximately $6.5 million), the Permian Basin 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 $2.7 million), additional electrical costs (approximately $2 million), increased nonoperated costs (approximately $1.7 million), increased labor costs (approximately $1.4 million) and higher environmental compliance expense (approximately $1.1 million) partially offset by decreased other O&M expense (approximately $3.6 million). On a per unit basis, the average lease operating expense (excluding production taxes) for 2013 was $12.20 per barrel of oil equivalent (BOE) as compared to $10.60 per BOE in the same period a year ago. In 2013, administrative expense rose $34.9 million primarily due to increased costs related to the Company’s benefit and performance-based compensation plans (approximately $21.7 million), higher labor costs (approximately $7.4 million), increased legal expenses (approximately $3 million) and higher professional services (approximately $1.1 million). Administrative expense rose $1.6 million in 2012 largely due to increased labor costs (approximately $4.3 million) partially offset by decreased costs from the Company’s benefit and performance-based compensation plans (approximately $1.8 million). Exploration expense increased $8.6 million in 2013 largely due to the

25



expected expiration of certain leasehold acreage. Exploration expense rose $6.4 million during 2012 primarily due to charges incurred of $5.3 million for unproved capitalized leasehold costs.

DD&A expense increased $110.3 million in 2013 and $129.3 million in 2012. The average DD&A rates were $19.32 per BOE in 2013, $16.03 per BOE in 2012 and $12.03 per BOE in 2011. The increase in the 2013 and 2012 per unit DD&A rates, which contributed approximately $76.6 million and $84.7 million, respectively, to the increase in DD&A expense, was primarily due to higher rates resulting from an increase in development costs. Increased production volumes also contributed approximately $33.6 million and $44.3 million to the increase in DD&A expense in 2013 and 2012, respectively.

Energen Resources’ expense for taxes other than income taxes primarily reflected production-related taxes. Energen Resources recorded severance taxes of $67.5 million, $53.7 million and $51.6 million for 2013, 2012 and 2011, respectively. In 2013, severance taxes were $13.8 million higher resulting from increased oil and natural gas commodity market prices and higher oil and natural gas liquids production volumes. Higher commodity market prices and the impact of increased production volumes contributed approximately $8.5 million and $5.3 million to the increase in severance taxes, respectively. Severance taxes were $2.1 million higher in 2012 resulting from higher production volumes largely offset by lower commodity market prices. Increased production volumes contributed approximately $10.9 million to the increase in severance taxes while decreased commodity market prices lowered severance taxes by approximately $8.8 million. 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 was allowed to earn a range of return of 13.15 percent to 13.65 percent on average equity through December 31, 2013. Rate Stabilization and Equalization (RSE) limited the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Alagasco’s original RSE order had a term extending through December 31, 2014. On December 20, 2013, the APSC issued a final written order modifying RSE effective January 1, 2014 as follows. The term will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, if any. Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to O&M expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from 2007 actual expenses, adjusted for inflation using the Index Range. Given existing economic conditions, Alagasco expects only modest growth in equity as annual dividends are typically paid by the utility.

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 (GSA) rider. 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 $533.3 million, $451.6 million and $535.0 million in 2013, 2012 and 2011, respectively. Sales revenue in 2013 rose primarily due to an increase in gas cost of approximately $37 million along with an increase in customer usage of approximately $36 million. In 2013, Alagasco had a net reduction in revenues of $10.6 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. During the year ended December 31, 2012, Alagasco had a 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. In 2013, weather that was 38.4 percent colder than in the prior year contributed to a 26.6 percent increase in residential sales volumes and a 19.1 percent increase in commercial and industrial volumes. Transportation volumes fell 1.2 percent. In 2012, sales revenue declined largely due to decreased customer usage of approximately $53 million and a decline in gas cost of approximately $38 million. Alagasco had a net reduction in revenues of $6.3 million pre-tax in 2012, as discussed above. During the year ended December 31, 2011, Alagasco had a 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. Weather was 27.1 percent warmer in 2012 than in the prior year. Residential sales volumes declined 24.2 percent while commercial and industrial volumes decreased 16.2 percent. Transportation volumes increased 7.8 percent. In 2013, higher gas costs along with increased gas purchase volumes contributed to a 51.5 percent increase in cost of gas. 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.

26




O&M expense at the utility rose 1.3 percent in 2013 largely due to increased labor-related costs (approximately $3.5 million) and increased bad debt expense (approximately $0.6 million) partially offset by decreased consulting and technology costs (approximately $1 million). 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. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2013, 2012 and 2011.

Depreciation expense increased 3.9 percent and 5.9 percent in 2013 and 2012, respectively, largely due to the extension and replacement of the utility’s distribution system and replacement of its support systems. Approved depreciation rates averaged approximately 3.1 percent, 3.2 percent and 3.1 percent in the years ended December 31, 2013, 2012 and 2011, 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)
2013
2012
2011
Natural gas transportation and sales revenues
$
533,338

$
451,589

$
534,953

Cost of gas
(215,455
)
(142,228
)
(233,523
)
Operations and maintenance
(143,138
)
(141,334
)
(139,030
)
Depreciation and amortization
(43,907
)
(42,270
)
(39,916
)
Income taxes
(34,687
)
(30,244
)
(26,670
)
Taxes, other than income taxes
(37,070
)
(32,541
)
(36,268
)
Operating income
$
59,081

$
62,972

$
59,546

Natural gas sales volumes (MMcf)
 
 
 
Residential
20,279

16,014

21,132

Commercial and industrial
9,968

8,372

9,994

Total natural gas sales volumes
30,247

24,386

31,126

Natural gas transportation volumes (MMcf)
47,534

48,106

44,614

Total deliveries (MMcf)
77,781

72,492

75,740


Non-Operating Items
Consolidated: Interest expense rose $3.7 million in 2013 largely due to higher short-term borrowings and the December 2013, issuance of $600 million in Senior Term Loans with a floating interest rate due March 31, 2014 through December 17, 2017. The $600 million issuance includes $400 million with a floating rate of LIBOR plus 1.625 percent, currently 1.792 percent at December 31, 2013 and $200 million swapped to a fixed rate at 2.6675 percent. These increases in interest expense for 2013 were partially offset by the October 2013 repayment of $50 million of 5 percent Notes and the December 2013 repayment of the Senior Term Loans of $300 million issued in November 2011. In 2012, interest expense increased $20.7 million primarily 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 included $100 million with a floating rate of LIBOR plus 1.375 percent and $200 million swapped to a fixed rate at 2.4175 percent. Higher short-term borrowings also contributed to the increase in interest expense for 2012. The average daily outstanding balance under credit facilities was $804.9 million in 2013. The average daily outstanding balance under credit facilities was $331.1 million in 2012 as compared to $229.1 million in 2011. Other income for the Company increased $12.5 million in 2013 primarily due to the pre-tax gain of $10.9 million on the August 2013 sale of Alagasco’s Metro Operations Center. Income tax expense decreased in 2013 largely due to lower pre-tax income while income tax expense increased in 2012 primarily due to higher pre-tax income.

FINANCIAL POSITION AND LIQUIDITY
The Company’s net cash from operating activities totaled $927.4 million, $735.7 million and $761.8 million in 2013, 2012 and 2011, respectively. During 2013, operating cash flows increased due to an increase in oil and natural gas liquids production and

27



higher natural gas and oil commodity prices at Energen Resources. Net income in 2013 was also significantly impacted by non-cash charges, including higher DD&A, the change in derivative fair value and a gain on the sale of certain assets. 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. 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. 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. Working capital needs during 2013, 2012 and 2011 at Alagasco were largely affected by gas costs, 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 and refundable negative salvage costs, combined to create the remaining increases in all years.

The Company made net investments of $1,053.6 million during 2013. Energen Resources invested $31.3 million in property acquisitions including approximately $26.8 million of unproved leaseholds; $675.4 million for development costs (excludes the reversal of approximately $23.9 million of accrued development cost) including approximately $457 million to drill 179 net development and service wells; and $423.7 million for exploration including approximately $295 million to drill 90 net exploratory wells. Energen Resources had cash proceeds in 2013 of $161 million primarily from the sale of certain Black Warrior Basin properties. Utility expenditures in 2013 totaled $86.0 million (excludes approximately $2 million of accrued capital cost) and primarily represented expansion and replacement of its distribution system and replacement of its support facilities and information systems. Alagasco had cash proceeds in 2013 of $13.8 million from the sale of its Metro Operations Center. During 2012, the Company made net investments of $1,322.2 million. 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 adding approximately 8.2 MMBOE of proved reserves. 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). 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 2013, Energen Resources added 37 MMBOE of proved 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. Also during 2013, the Company added approximately 0.2 MMBOE of proved reserves primarily from Permian Basin oil property acquisitions. Energen Resources added approximately 69 MMBOE and 66 MMBOE of proved reserves in 2012 and 2011, respectively.

The Company provided $122.1 million from net financing activities in 2013 largely from the December 2013 issuance of $600 million of Senior Term Loans with a floating interest rate partially offset the repayment of long-term debt of $350.1 million combined with a decrease in short-term borrowings. In 2012, the Company provided $586.6 million from net financing activities largely from an increase in short-term borrowings used to fund development activity at Energen 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 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 which were partially offset by the issuance of common stock through the Company’s stock-based compensation plan.




28




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 in 2012 and 2011.

Years ended December 31, (in thousands)
2013
2012
2011
Capital and exploration expenditures for:
 
 
 
Property acquisitions
$
31,481

$
138,496

$
306,881

Development
654,222

748,251

621,550

Exploration
423,698

416,678

188,660

Other
11,352

4,543

9,277

Total
1,120,753

1,307,968

1,126,368

Less exploration expenditures charged to income
16,008

16,757

10,916

Net capital expenditures
$
1,104,745

$
1,291,211

$
1,115,452


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

Years ended December 31, (in thousands)
2013
2012
2011
Capital expenditures for:
 
 
 
Renewals, replacements, system expansion and other
$
59,750

$
50,075

$
53,970

Support systems and facilities
29,019

21,794

20,014

Total
$
88,769

$
71,869

$
73,984


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 2014, the Company expects its oil and gas capital spending to total approximately $1.05 billion, including $780 million for existing properties and $265 million for exploration. Included in this $780 million is approximately $306 million for the development of previously identified proved undeveloped reserves.

Capital expenditures by area during 2014 are planned as follows:

Year ended December 31, (in thousands)
2014
Permian Basin development
$
765,000

Permian Basin exploration
265,000

San Juan Basin
15,000

Other
5,000

Total
$
1,050,000


Energen anticipates having the following drilling rigs and net wells by area during 2014. The drilling rigs presented below are operated while the net wells include operated and non-operated wells.

 
Drilling Rigs
Net Wells
Permian Basin
14
161

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.

29



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.

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

In January 2014, Energen Resources signed a purchase and sale agreement on its North Louisiana/East Texas natural gas and oil properties for $31.5 million (subject to closing adjustments). The Company expects to complete the sale in the first quarter of 2014 and will use the proceeds to repay short-term obligations. During the third quarter of 2013, Energen Resources classified these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the third and fourth quarters of $24.6 million pre-tax and $5.2 million pre-tax, respectively, to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. The non-cash impairment writedowns are reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

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

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 2013 declined approximately 0.6 percent from 2012 and reflected a moderation in decline over the five-year trend. Other factors impacting Alagasco’s average customer count include recent weather trends, 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, weather conditions and the underlying current and future economic conditions facing the utility’s customer base. During the year ended December 31, 2013, Alagasco reduced the bad debt reserve by approximately $0.7 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 $28 million in 2014 but will vary depending upon the price of natural gas. During 2014, Alagasco plans to invest approximately $74 million in capital expenditures for the normal needs of its distribution, support systems and technology-related projects designed to improve customer service and the construction of two service centers to replace the Metro Operations Center sold during 2013. 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.

In August 2013, Alagasco recorded a pre-tax gain of $10.9 million related to the sale of its Metro Operations Center which is located in Birmingham, Alabama, and has been in service since the 1940’s. The Company received approximately $13.8 million pre-tax in cash from the sale of this property. During the third quarter of 2013, the gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. In conjunction with the receipt of the rate order from the APSC on December 20, 2013, Alagasco recognized the deferred revenues

30



from this sale in the fourth quarter of 2013. Effective upon the sale of the Metro Operations Center, Alagasco leased the facility from the purchaser for a period of approximately 20 months.

Credit Facilities and Working Capital
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 $1.25 billion and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. Energen’s obligations under the $1.25 billion 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, 2013.

At December 31, 2013, the Company reported negative working capital of $682.7 million arising from current liabilities of $1,109.9 million exceeding current assets of $427.2 million. The negative working capital is primarily due to a $628 million increase in borrowings during 2012 partially offset by a $104 million decrease in borrowings during 2013 under the syndicated unsecured credit facilities and in support of Energen’s 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. Energen’s accounts receivable and accounts payable at December 31, 2013 include $17.5 million and $30.3 million, respectively, associated with its derivative financial instruments. Working capital of Alagasco is additionally impacted by the recovery and pass-through of regulatory items and the seasonality of Alagasco’s business and reflects an expected pass-through to rate payers of $15.8 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
On April 26, 2013, Moody’s Investor Service updated its credit opinion for Energen and Alagasco confirming Energen’s senior unsecured credit rating as investment grade with a negative outlook. Alagasco’s senior unsecured credit rating was lowered one notch but remains investment grade with a negative outlook. On December 16, 2013, Standard & Poor’s lowered its debt ratings for Energen and Alagasco’s from investment grade with a stable outlook to investment grade with a negative outlook.

Dividends
Energen expects to pay annual cash dividends of $0.60 per share on the Company’s common stock in 2014. 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.

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, 2013:

 
Payments Due Before December 31,

(in thousands)

Total

2014

2015-2016

2017-2018
2019 and Thereafter
Long-term debt (1)
$
1,403,923

$
60,000

$
200,000

$
439,000

$
704,923

Interest payments on debt
455,171

54,585

100,763

82,812

217,011

Purchase obligations (2)
171,110

47,810

93,840

26,791

2,669

Operating leases
31,627

5,270

9,331

6,389

10,637

Asset retirement obligations (3)
709,451

11,538

6,162

5,933

685,818

Nonqualified supplemental retirement plans
36,597

6,145

1,112

9,939

19,401

Total contractual cash obligations
$
2,807,879

$
185,348

$
411,208

$
570,864

$
1,640,459


31



(1) Long-term cash obligations include approximately $0.5 million of unamortized debt discounts as of December 31, 2013.

(2) Certain of the Company’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $171 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 134 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 7.1 MMBOE through September 2017.

Energen Resources entered into an agreement which commenced on January 15, 2012 and expires in January 2015 to secure a drilling rig necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of this drilling rig, Energen Resources’ total resulting exposure could be as much as $3.9 million depending on the contractor’s ability to remarket the drilling rig.

There are no required contributions to the qualified pension plans during 2014. 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 $3 million to the qualified pension plans in January 2014. During 2014, the Company may make additional discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. 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 $16.0 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 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of December 31, 2013.

OUTLOOK
Oil and Gas Operations: Energen Resources plans to continue to implement its growth strategy with capital spending in 2014. Production in 2014 is estimated to range from 24.4 MMBOE to 25.4 MMBOE, with a midpoint of 24.9 MMBOE, including approximately 22.1 MMBOE of estimated production from proved reserves owned at December 31, 2013. 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.


32



Production volumes by area are expected to be as follows:

Year ended December 31, (MMBOE)
2014
Permian Basin
16.5
San Juan Basin/other
8.4
Total (midpoint of range)
24.9

Production volumes by commodity are expected to be as follows:

Year ended December 31, (MMBOE)
2014
Gas
9.7
Oil
11.4
Natural gas liquids
3.8
Total (midpoint of range)
24.9

During 2014, Energen Resources expects an annualized decline rate of approximately14 percent for its proved developed producing properties owned at December 31, 2013. During the same period, total production from proved properties is expected to decrease approximately 5 percent and total production is expected to increase approximately 6.7 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, 2013 for the 5 year period 2013 to 2018, for the 10 year period 2013 to 2023 and for the 20 year period 2013 to 2033 of approximately 13.2 percent, 10.6 percent and 8.7 percent, respectively.

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 the Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply and demand factors, including seasonal variations and the availability and price of transportation to consuming areas. 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 exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. At December 31, 2013, 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 seven of its active counterparties and in a net loss position with the remaining six at December 31, 2013. 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.


33



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 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 rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability.

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

Production Period
Total Hedged Volumes
Average Contract
Price

Description
Natural Gas
2014
10.6
 Bcf
$4.55 Mcf
NYMEX Swaps
 
31.4
 Bcf
$4.60 Mcf
Basin Specific Swaps - San Juan
 
9.7
 Bcf
$3.81 Mcf
Basin Specific Swaps - Permian
2015
6.0
 Bcf
$4.07 Mcf
Basin Specific Swaps - San Juan
Oil
2014
9,796
 MBbl
$92.64 Bbl
NYMEX Swaps
2015
5,760
 MBbl
$88.85 Bbl
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, 2013, Energen Resources was in a net loss position of $7.4 million for derivative contracts and estimates that a 10 percent increase or decrease in the commodities prices would have resulted in an approximate $165 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 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.











34



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

 
December 31, 2013
(in thousands)
Level 2*
Level 3*
Total
Current assets
$
(1,658
)
$
19,121

$
17,463

Noncurrent assets
4,383

1,056

5,439

Current liabilities
(28,414
)
(1,888
)
(30,302
)
Net derivative asset (liability)
$
(25,689
)
$
18,289

$
(7,400
)

 
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

* 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, 2013, Alagasco had no derivative instruments. 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. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012.

Level 3 assets as of December 31, 2013 represent an immaterial amount of both total assets and liabilities. 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 $19 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $19 million associated with open Level 3 mark-to-market derivative contracts. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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. Energen’s derivative transactions qualify for the end-user exception which exempts them from certain Dodd-Frank Act margin and exchange clearing requirements pursuant to final regulations adopted by the CFTC and SEC and published in the Federal Register on July 19, 2012. However, the Company could experience increased costs and reduced liquidity in the markets as a result of the new rules and regulations, which could reduce hedging opportunities and negatively affect the Company’s revenues and cash flows.

Natural Gas Distribution: The extension of RSE effective January 1, 2014 provides Alagasco the opportunity to continue earning an allowed return on average equity between 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent through September 30, 2018. 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. 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. 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.



35



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 Oil and Natural Gas 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. The technologies associated with these proved reserve estimates are analysis of well production data, geophysical data, wireline and core data. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas 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, 2013. The independent reservoir engineers have issued reports covering approximately 98 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 2014 depreciation, depletion and amortization expense associated with an assumed downward revision in the reported oil and gas reserve amounts at December 31, 2013:

 
Percentage Change in Oil & Gas Reserves
 
From Reported Reserves as of December 31, 2013
(dollars in thousands)
-5%
-10%
Estimated increase in DD&A expense for the
year ended December 31, 2014, net of tax
$
15,197

$
31,912


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 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.

36




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 enters into derivative transactions that are accounted for as mark-to-market transactions with gains and losses reported in current period operating revenues. 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 each discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate for each plan was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments; the weighted average discount rate used to determine net periodic benefit costs was 3.63 percent for the plans for the year ended December 31, 2013. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions; the return on assets used to determine net periodic benefit cost was 7 percent for each of the applicable plans for the year ended December 31, 2013. The estimated weighted average rate of increase in the compensation level for pay related plans was 3.71 percent for the year ended December 31, 2013.

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, 2013:

(in thousands)
Pension
Expense
Postretirement
Expense
Discount rate change
$
1,750

$
10

Return on assets
$
530

$
180

Compensation increase
$
975

$


The weighted average discount rate, return on plan assets and estimated rate of compensation increase used in the 2014 actuarial assumptions are 4.31 percent, 7.00 percent and 3.63 percent, respectively.

37



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 17, 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, 2013, 2012
and 2011
 
 
 
 
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012
and 2011
 
 
 
 
Consolidated Balance Sheets as of December 31, 2013 and 2012
 
 
 
 
Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2013, 2012
and 2011
 
 
 
 
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011
 
 
 
 
Notes to Financial Statements
 
 
 
 
Alabama Gas Corporation
 
 
 
 
 
Report of Independent Registered Public Accounting Firm
 
 
 
 
Statements of Income for the years ended December 31, 2013, 2012 and 2011




 
 
 
Balance Sheets as of December 31, 2013 and 2012
 
 
 
 
Statements of Shareholder’s Equity for the years ended December 31, 2013, 2012
and 2011
 
 
 
 
Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011
 
 
 
 
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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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
March 3, 2014


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, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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
March 3, 2014


41



CONSOLIDATED STATEMENTS OF INCOME
Energen Corporation

Years ended December 31, (in thousands, except share data)
2013
2012
2011
 
 
 
 
Operating Revenues
 
 
 
Oil and gas operations
$
1,205,312

$
1,089,230

$
838,160

Natural gas distribution
533,338

451,589

534,953

Total operating revenues
1,738,650

1,540,819

1,373,113

Operating Expenses
 
 
 
Cost of gas
215,455

142,228

233,523

Operations and maintenance
562,350

458,084

398,084

Depreciation, depletion and amortization
497,381

385,453

253,757

Taxes, other than income taxes
105,268

86,801

88,351

Accretion expense
6,995

6,339

5,699

Total operating expenses
1,387,449

1,078,905

979,414

Operating Income
351,201

461,914

393,699

Other Income (Expense)
 
 
 
Interest expense
(69,200
)
(65,542
)
(44,822
)
Other income
16,803

4,285

2,206

Other expense
(375
)
(903
)
(456
)
Total other expense
(52,772
)
(62,160
)
(43,072
)
Income From Continuing Operations Before Income Taxes
298,429

399,754

350,627

Income tax expense
105,282

144,534

126,322

Income From Continuing Operations
193,147

255,220

224,305

Discontinued Operations, net of taxes
 
 
 
Income (loss) from discontinued operations
7,813

(1,658
)
35,319

Gain on disposal of discontinued operations, net
3,594



Income (Loss) From Discontinued Operations
11,407

(1,658
)
35,319

Net Income
$
204,554

$
253,562

$
259,624

 
 
 
 
Diluted Earnings Per Average Common Share
 
 
 
Continuing operations
$
2.67

$
3.53

$
3.10

Discontinued operations
0.15

(0.02
)
0.49

Net Income
$
2.82

$
3.51

$
3.59

Basic Earnings Per Average Common Share 
 
 
 
Continuing operations
$
2.67

$
3.54

$
3.11

Discontinued operations
0.16

(0.02
)
0.49

Net Income
$
2.83

$
3.52

$
3.60

 
 
 
 
Diluted Average Common Shares Outstanding
72,470,622

72,316,214

72,332,369

Basic Average Common Shares Outstanding
72,317,865

72,119,021

72,055,661


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)
2013
2012
2011
 
 
 
 
Net Income
$
204,554